BVY 05-057, 2004 Annual Report, and, Securities and Exchange Commission Form 10-K Submittal
| ML051570549 | |
| Person / Time | |
|---|---|
| Site: | Indian Point, Pilgrim, Vermont Yankee, FitzPatrick  |
| Issue date: | 05/25/2005 |
| From: | Kansler M Entergy Nuclear Northeast, Entergy Nuclear Operations |
| To: | Document Control Desk, NRC/FSME |
| References | |
| -RFPFR, BVY 05-057, ENO 2.05.040, JPN-05-008, NL-05-074 | |
| Download: ML051570549 (548) | |
Text
[[:#Wiki_filter:Entergy Nuclear Northeast Entergy Nuclear Operations, Inc. Enrtgyt 440 Hamilton Avenue White Plains, NY 10601 Tel 914 272 3200 Fax 914 272 3205 Michael R. Kansler President May 25, 2005 JPN-05-008 NL-05-074 ENO 2.05.040 BVY 05-057 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001
Subject:
James A. FitzPatrick Nuclear Power Plant Docket No. 50-333 Indian Point Nuclear Generating Units No. 1, 2 and 3 Docket No. 50-003, 50-247 and 50-286 Pilgrim Nuclear Power Station Docket No. 50-293 Vermont Yankee Nuclear Power Station Docket No. 50-271 2004 Annual Report, and, Securities and Exchanqe Commission Form 1O-K Submittal
Dear Sir or Madam:
In accordance with 10 CFR 50.71(b), 10 CFR 72.80 (b) and 10 CFR 140.15 (b) (1), this letter transmits (Attachment 1) the Entergy Corporation 2004 Annual Report and the corresponding Securities and Exchange Commission Form 10-K. This submittal is made on behalf of each nuclear unit in the Entergy Nuclear Operations, Inc. system.
There are no commitments contained in this letter. contact Ms. Charlene Faison at 914-272-3378. : As stated cc: Next page 2
cc: Mr. Samuel J. Collins Senior Resident Inspector's Office Regional Administrator, Region I Pilgrim Nuclear Power Station U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission 475 Allendale Road 600 Rocky Hill Road - Mail stop 66 King of Prussia, PA 19406 Plymouth, MA 02360 Resident Inspector's Office Mr. Richard Ennis, Project Manager Indian Point Unit 3 Nuclear Power Plant Project Directorate I U.S. Nuclear Regulatory Commission Division of Licensing Project Management P.O. Box 337 Office of Nuclear Reactor Regulation Buchanan, NY 10511 U.S. Nuclear Regulatory Commission Mail Stop 0-8-Bl Senior Resident Inspector's Office Washington, DC 20555 James A. FitzPatrick Nuclear Power Plant U.S. Nuclear Regulatory Commission Mr. Patrick Milano, Sr. Project Manager P.O. Box 136 Project Directorate I Lycoming, NY 13093 Division of Licensing Project Management Office of Nuclear Reactor Regulation Mr. John Boska, Project Manager U.S. Nuclear Regulatory Commission Project Directorate I Mail Stop O-8-C2 Division of Licensing Project Management Washington, DC 20555 Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Mr. Peter Smith Mail Stop 0-8-Bl President Washington, DC 20555 NYSERDA 17 Columbia Circle USNRC Resident Inspector Albany, NY 12203 Vermont Yankee Nuclear Power Station 320 Governor Hunt Road Mr. Paul Eddy P.O. Box 157 NYS Department of Public Service Vernon, Vermont 05354 3 Empire State Plaza Albany, NY 12223 Senior Resident Inspector's Office Indian Point Unit 2 Nuclear Power Plant Mr. Michael Webb, Project Manager U.S. Nuclear Regulatory Commission Project Directorate IV P.O. Box 59 Division of Licensing Project Management Buchanan, NY 10511 Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Mr. David O'Brien, Commissioner Mail Stop 0-7-Dl Department of Public Service Washington, DC 20555 112 State Street - Drawer 20 Montpelier, VT 05620 3
bh ATTACHMENT 1 2004 Annual Report and 2004 Form 10-K For James A. FitzPatrick Nuclear Power Plant Docket No. 50-333 Indian Point Nuclear Generating Unit No. 1 Docket No. 50-003 Indian Point Nuclear Generating Unit No. 2 Docket No. 50-247 Indian Point Nuclear Generating Unit No. 3 Docket No. 50-286 Pilgrim Nuclear Power Station Docket No. 50-293 Vermont Yankee Nuclear Power Station Docket No. 50-271
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Entergy Corporation and Subsidiaries 2004 HIGHLIGHTS
% CHANGE 2003 % CHANGE 2002 FINANCIAL RESULTS (in millions, except percentages and per share amounts)
Operating revenues $10,124 10.1% $9,195 10.7% $8,305 Earnings applicable to common stock 5 910 (1.8%) S 927 54.8% S 599 Earnings per share Basic S 4.01 (2.0%) S 4.09 52.0% S 2.69 Diluted $ 3.93 (2.0%) S 4.01 51.9% S 2.64 Average shares outstanding (in millions) Basic 226.9 - 226.8 1.7% 223.0 Diluted 231.2 - 231.1 1.7% 227.3 Return on average common equity 10.70% (4.6%) 11.21% 42.8% 7.85% Net cash flow provided by operating activities $ 2,929 46.0% 52,006 (8.1%) 52,182 U.S. UTILITY ELECTRIC OPERATING DATA Retail kilowatt-hour sales (in millions) 102,225 2.3% 99,968 (1.6%) 101,613 Peak demand (in megawatts) 21,174 5.0% 20,162 (1.3%) 20,419 Retail customers - year end (in thousands) 2,662 1.2% 2,631 1.3% 2,598 TOTAL EMPLOYEES - YEAR END 14,425 (2.4%) 14,773 (5.3%) 15,601
.. aw ENTERGY CORPORATION and SUBSIDIARIES 2004 TABLE OF CONTENTS Entergy Corporation is an integrated energy company engaged primarily in electric power production and retail distribution operations.
Entergy owns and operates power plants with approximately 30,000 megawatts of electric generating capacity, and it is the second-largest nuclear generator in the United States. Entergy delivers electricity to 2.7 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy has annual revenues of more than $10 billion and approximately 14,000 employees.
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Entergy Corporation and Subsidiaries 2004 Finding shareholderl value in the d etails. \ I Iur focus in 2004 was on execution driven by fundamental points of view of our competitive, regulatory, and financial markets. We believe keeping a clear focus on both the forest and the trees is the only way to earn our customers' business, attract and retain the best employees, generate strong cash flow, and deliver superior total returns to our shareholders. In this year's annual report, we celebrate forests, trees, and the animal life they support. A forest habitat is an incredibly rich, complex system of plants and animals working and evolving together to sustain life. We think there are some striking parallels between the instinctive behaviors highlighted in the following pages and those we emphasize in our company. Entergy Corporation and Subsidiaries 2004 To Our Stakeholders: WIn 2004, we were honored for the second consecutive results and they guide the decisions we make to deliver long-term growth and completed in fourth quarter 2004 with cash proceeds expected to exceed year to receive the Edison value to our owners. S1 billion, of which the majority of the Electric Institute award in recognition The year 2004 turned out to be more proceeds were received in 2004. of the highest total shareholder return challenging for us than expected with In August 2004, we announced a share over the last five years for large-cap the exceptionally mild weather, the poor repurchase program of up to $1.5 billion electric utilities. From October 1999 to operating results of Entergy-Koch and by year end we had completed September 2004, our shareholders Trading, and the failure to obtain rate roughly one-third of the buyback realized a 149 percent return on their relief in Texas. program. In October 2004, the Board of investment while the S&P Electric Yet, we also had a number of Directors raised Entergy's dividend 20 Utilities Index returned 42 percent. successes last year. In November 2004, percent to $2.16 per share on an annual We begin with that simply because we completed the sale of Entergy-Koch basis. This follows a 29 percent increase being the leader in generating consistent Trading - our trading joint venture with in 2003. Even with the increase, our shareholder returns is one of our Koch Energy, Inc. - to Merrill Lynch. dividend payout ratio of 48 percent is overarching long-term aspirations. Our Our point of view on the trading below our internally imposed cap of 60 point-of-view driven business model business has changed dramatically since percent payout and well under the and the hundreds of decisions made and we created EKT in 2001. At that time, industry average, providing us the actions taken by our employees are all we faced impending deregulation and opportunity to continue to grow the designed to deliver superior long-term we were planning a large merchant dividend in the future. returns. Winning this particular award, generation build-out program. With We are confident we have significant then, is validation once again that our those commodity price risks financial resources to make sound strategies are working, our employees substantially eliminated, it became clear investments in our utilities and nuclear are performing, our customers are well- that EKT was inherently of more value business even as we return available cash served, and our shareholders are reaping to a natural owner like a large financial to our shareholders through the buyback the rewards. entity than it was to us. That point of and higher dividends. view was validated in the sale of EKT For 2004, Entergy produced a Financial Results for 2004 and the subsequent sale of the Gulf one-year total return to shareholders Our long-term aspirations guided the South Pipeline to a subsidiary of Loews of 22 percent versus 27 percent for actions we took in delivering 2004 Corporation - transactions that were the S&P Electric Utilities Index - Entergy Corporation and Subsidiaries 2004 k" `& 4 16kl
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r-11 -, 41i 01 I11 - a performance that ranked sixth out of service to customers while passing the 20-member S&P Electric Utilities lower-cost generation savings on to Index. While our one-year performance utility customers are efficient is below our long-term aspiration to mechanisms to align the economic deliver top-quartile shareholder returns, interests of public utilities, customers, we are confident that the actions taken and shareholders. We have incentive in 2004 support our continued leadership rate structures in place at Entergy in creating value for our shareholders. Mississippi and Entergy New Orleans. In a pending rate case for 'We were honoredfor the second consecutive 2004: Our Points of View Entergy Louisiana, we have filed year to receive the Edison ElectricInstitute In spite of more adversities than testimony proposing a formula rate award in recognition of the highest total expected, 2004 was a year of solid plan. And in a pending rate case for shareholderreturn over the lastfive years." progress consistent with our point-of- Entergy Gulf States - Louisiana, the view driven business model. Based on LPSC has advanced a procedural market knowledge and sophisticated schedule for a global settlement that analysis, we developed clear points of includes such a formula rate plan view in 2004 and then acted decisively. and would resolve 12 open dockets. Here are a few examples: Our point of view in Texas has We remain convinced that evolved along with changes in the performance-based incentives that regulatory direction there. While we allow utilities to earn a higher return have pursued Retail Open Access on equity by providing excellent since 1999, we now believe that there
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Entergy Corporation and Subsidiaries 2004 A REVIEW OF OUR ASPIRATIONS
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As in the last two years, we continue to report progress against our ongoing long-term aspirations. ___ a_ I With the sale of Entergy-Koch Trading, our number of aspirations now stands at five. A S P I R A T IO N S PROGRESS IN 2004 Entergy will be the consistent industry leader in We were once again recognized for the highest total shareholder return. total shareholder return over the last five years in aM EEl's index of large-cap shareholder-owned
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An Entergy will be recognized as an environmental We continue to set and meet voluntary standards p 1 leader, not only in generation, but among all U.S. to stabilize COemissions from our generating industrial companies, and will demonstrate facilities and strive to meet or beat all environmental the advantage of environmental excellence in standards. For the third year in a row, Entergy was achieving financial results. named to the Dow Jones Sustainability Index. Entergy will be one of five or fewer key We are recognized for our operational expertise owner/operators in a highly consolidated nuclear in nuclear. We push for continuous improvement in industry - the best of the best - who operate safety first and then productivity. Six of our nuclear safe, secure, low-cost plants, and we will be sites have achieved OSHA VPP Star status - the
= a demonstrating new nuclear technologies that highest industrial safety rating for a work site.
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Entergy's utilities will be recognized for industry-leading satisfaction, and for a comprehensive We continue to invest in our utilities to improve performance, reliability, and customer service. aI approach to meeting the particular needs of In 2004, we raised a record $1.7 million in Customer
------ a-low-income customers. Assistance Funds - from employees, customers, and shareholders - to help meet the needs of a_
_ I elderly and disabled customers living in poverty. Entergy's goal of an accident-free work We still are not satisfied with our overall safety environment will be internalized as more than an performance. Although in 2004 we improved our a& _ nft-- - 11
.aspiration." Nothing less is good enough. industry-standard safety measure by six percent lakdaMMOMB022-, , - - j and decreased the number of employee lost-time
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Entergy Corporation and Subsidiaries 2004 is little likelihood that the Public utility customers. Inherent in our Utility Commission of Texas will Generation Supply Plan are reduced approve ROA any time in the near exposure to gas prices and overall fuel future for Entergy. As a result, savings - both of which can lower our we filed a general rate case in customers' electricity bills. In 2004, August 2004 to recover the cost of we worked diligently with local and investments we have made since our federal regulators in order to continue last general rate case and to ensure we to implement the competitive bidding 'feeting our environmental, are able to maintain the high quality process, fully execute our Generation safety, and socialperformance service and reliability that our Supply Plan, and ultimately deliver goals is as importantto customers currently receive. Our last savings to our customers. We are on us as meeting ourfinancial base rate increase in Texas was more track to close on the purchase of the expectations. than 13 years ago - in 1991. We were Cleco Corporation's Perryville plant extremely disappointed when our case in mid-2005 and, in the meantime, was dismissed without a hearing and our customers continue to benefit the PUCT failed to act on our request from the power purchase agreement for a rehearing of the order to dismiss that remains in place. the case. We are currently pursuing an We sold forward additional output appeal in district court as well as from our unregulated nuclear fleet legislative action to get the appropriate and, in doing so, we raised the rate relief our case supports. average price of our portfolio of On the federal front, we continue to energy contracts by almost $4 per believe that the market power screen MWh. In addition, we continued to administered by FERC is substantially improve productivity in our Robert v.d. Luft flawed and we worked hard in 2004 unregulated nuclear fleet. When the Chairman to demonstrate why in multiple majority of labor contracts came up filings. The operation of the nation's for renewal in 2004, we were able to power transmission grid is both negotiate changes in the work rules to complex and of critical importance. improve the efficiency of plant Our utilities worked with FERC in operations and continue to move 2004 to advance a proposal for an operating costs closer to those in our Independent Coordinator of regulated nuclear fleet. We also Transmission - an approach that we completed uprates at FitzPatrick and think is less costly and considerably Indian Point 2, increasing the total more practical than other alternatives. capacity of our unregulated fleet to More importantly it supports the 4,058 MW from 3,955 MW at the reliability objectives and criteria end of 2002. necessary for the operation of a high- We believe sustainable development is voltage power grid. vital to our fiuture as a company and a Using our comprehensive Generation society. We are one of the cleanest Supply Plan, we continue to look for power generators in the U.S. In 2004, opportunities to purchase energy and we met our voluntary standard for capacity to mitigate our capacity CO 2 emissions for the fourth shortfall and meet the needs of our consecutive year. We will not be Entergy Corporation and Subsidiaries 2004 satisfied until we have an accident-free provide solid growth going forward. work environment. And we continued
- Growth in nuclear will come from to work with regulators, agencies, and greater availability of attractive advocates to better meet the needs of nuclear transactions as owners of low-income residents in our service underperforming nuclear assets move territory. Meeting our environmental, to lower their costs or improve safety, and social performance goals is operations. We believe the market for as important to us as meeting our potential transactions presents financial expectations. opportunities. Also, we will complete uprate projects at Waterford 3 and
'Its the extraordinaryefforts of In total, our progress in 2004 can just Indian Point 3 and we expect to everyone at Entergy -from our as easily be measured in what we didn't obtain approval to place in service the Boardmembers to our linemen - do as in what we did. We remained 50 MW uprate that was completed at that drive ourlong-term results." disciplined with our capital and kept a Vermont Yankee last year. In addition, careful eye on the amount of risk we we believe we have a longer-term want to hold as a company. We did not opportunity to transform our Northeast enter into any transactions that did not asset portfolio into a more integrated meet our risk and return hurdles. business by adding other types of Instead, we chose to return cash to our generation that are more dispatchable shareholders through both a stock or a short position that matches up repurchase program and a higher with our low-cost, reliable, base-load dividend. And our credit standing nuclear output. improved significantly as both Moody's and Standard & Poor's raised our credit While we cannot give a preview of ratings. After thorough analysis the precise mix of opportunities that J. Wayne Leonard (confirmed with the benefit of 20/20 will result in the future, we can assure ChiefExecutive Officer hindsight), we believe this was the best you that we will apply the same use of available cash in 2004. discipline and capital stewardship we have applied in the past to ensure our Growing the Business risk and return criteria are met. And if With the sale of EKT and an absence of our opportunity set becomes limited, we nuclear transactions in 2004, the question will return cash to owners through share naturally arises - how will we grow repurchases or through dividend shareholder value? increases, just as we are doing today. In our utilities, growth will come Bottom line, we believe our long-from increased demand, improved term growth aspiration of five to six rate structures, and our Generation percent is very achievable. And that Supply Plan. We believe demand belief holds not just for today, but also growth in our service territory will for tomorrow with whatever tomorrow continue at a modest one to two brings. With our dynamic business percent annual rate. However, coupled model, we are confident we can succeed with new rate structures that include in a wide range of market conditions. performance-based incentives, we Our point-of-view approach is believe the utility business can inherently flexible, enabling us to adjust Entergy Corporation and Subsidiaries 2004 and adapt to our habitat - the Entergy recently won its seventh It's the extraordinary efforts of competitive, regulatory, and financial consecutive Edison Electric Institute everyone at Entergy - from our Board markets where we conduct business. emergency award for help it sent to members to our linemen - that drive Florida last hurricane season. Entergy our long-term results. We thank each of The Forest and The Trees is the only utility in the nation to win them for their dedication to our company, Business models are important but either EEI's "Emergency Assistance our customers, and our shareholders in models do not drive results. It's the Award" or 'Emergency Response 2004 and in the years to come. hundreds of critical decisions made Award' every year they have been every day by our employees that drive offered. Entergy won the award due to results. As a company, we link the big its outstanding efforts in helping Florida picture to the daily decisions made utilities restore electric service in the across our business. We keep our eyes wake of the destruction levied by four on both the forest and the trees. massive hurricanes over a five-week Robert v.d. Luft, Our employees execute and manage period in 2004. Chairman the details - they proactively work to We'd also like to recognize a few keep power lines clear. They respond individuals who tend to the big picture to customer calls quickly and for our company - the forest. In 2004, knowledgeably. Every customer is Don Hintz, our former president and treated with respect, unique to their current member of our Board, received J. Wayne Leonard, specific needs. Our employees operate the Platts Lifetime Achievement Award ChiefExecutive Officer safely - taking fill advantage of both for his vision and career achievements. extensive training and well-documented We believe Don's many contributions - procedures. They maintain and upgrade both to our company and our industry - our equipment to reduce outages and have been invaluable, particularly in minimize our CO2 emissions. Our nuclear power where his insights and employees take all of these actions on a creativity led to a renaissance over the daily - almost routine - basis. Their past decade. We appreciate his commitment and hard work is second continued guidance and vision as a to none. Board member. In addition, we want to recognize the Finally, we would like to acknowledge truly extraordinary - non-routine - and appreciate the contributions of three efforts our employees made in 2004 to departing members of our Board of restore power to thousands of people Directors. Wm. Clifford Smith has after an unusually active hurricane served on our Board for more than season. Not only did employees labor 20 years. Paul W. Murrill and Bismark long hours to restore service to our A. Steinhagen have both served since customers, they also contributed to 1993. Each of these individuals has emergency restoration efforts across provided insightful guidance to our the Southeastern U.S. In each and every company. We thank them for their year, our employees tend to all the contributions - too numerous to list - critical details of our business - the and wish them the best in all their trees - with talent, pride, and a future endeavors. can-do spirit. Entergy Corporation and Subsidiaries 2004 Entergy Corporation Observantand Decisive WIn the last six years we have worked hard to build an organization that can of Directors, received the Platts Lifetime Achievement Award, marking the fourth Platts supply dean, affordable electricity to Global Energy Award for our company. our customers, provide a safe, productive working environment to our employees, and deliver Point-of-View Driven Actions top-quarile returns to our shareholders over We made several decisions and took actions the long term. consistent with our point of view of the markets for The choices we make as we operate our business retail and wholesale energy. Based on extensive are guided by our long-term aspirations. For market analysis, we concluded that our energy example, we have consistently made investments in trading business - Entergy-Koch Trading - was assets that improve our customer service and worth more to a financial entity than it was to us. reliability, the safety of our operations, our impact As a result, we sold EKT and Gulf South Pipeline on the environment, and our cost position. As a in two separate transactions that will produce total result, we are in a strong position to grow our future cash proceeds to Entergy of more than SI billion. earnings the right way - by continuing to deliver We also continued to harvest value from our non-the most reliable, affordable service we can to nuclear assets business with the January 2004 sale of our customers. our interest in a natural gas-fired power plant located While our past actions have been recognized, we in Crete, Illinois. We sold a portion of three other continually strive for more. Last year for the second generating plants, resulting in lower operational consecutive year, Entergy was recognized again. We spending for this business. received the Edison Electric Institute award in In another point-of-view driven action, we recognition of the highest total shareholder return initiated a S1.5 billion stock repurchase program and over the last five years for large-cap electric increased our annual dividend by 20 percent, from utilities. In addition, Don Hintz, former president 51.80 to S2.16 per share. Given our disciplined of Entergy and now a member of our Board approach to capital investments and strong cash r ,.;, . y \J A WELL-INFORMED VIEW Acute vision leads to a well-informed point of view. We use deep market knowledge and sophisticated analysis to develop our points of view. It's a dynamic process - we adapt as market conditions change - and it results in clear decision-making. The best example in 2004? Our decision to maximize shareholder return through the sale of Entergy-Koch Trading and Gulf South Pipeline. I a / /A-K I . ra11 I - I
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Entergy Corporation and Subsidiaries 2004 flows, we concluded that we can return improved credit standing at both the available cash to our shareholders and still operating subsidiary and corporate level. DIS CIPLINE, have the flexibility to invest in the long- In 2004, both Moody's and Standard & SECURITY, term growth of our business. Poor's raised our credit ratings. AND FUTUREI We continue to take action to RETURN S substantially lower risks across all our An Eye for Growth businesses by improving operations, We continue to strategically review all Saving for the future - whether strengthening regulatory relationships, aspects of our business and our markets it's nuts or dollars - requires and better managing our cash flows. in order to maintain a clear and current discipline. At Entergy, we take We continued to improve our cash flow point of view. It's a dynamic approach a disciplined approach to interest coverage - defined as 12-months that enables us to adapt as market managing cash, investing capital, cash flow from operating activities plus conditions change. And in our current and conserving risk. We will not 12-months rolling interest paid, divided point of view, we see exciting compromise our standards to by interest expense - realizing more opportunities to grow in our utility and meet an appetite lor short-term than a 95 percent improvement since nuclear businesses. For example: results. Instead, we invest to build 1999. Our continued success in producing
- In the utility, our Generation financial security, meet our long- strong cash flows is an important Supply Plan enables us to purchase term aspiration of five to six element contributing to our significantly power and invest in more efficient percent average annual earnings growth, and deliver top-quartile total shareholder return. t .
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I'\ Entergy Corporation and Subsidiaries 2004 power generation assets to both meet We continue to institute training and TOTAL SHAREHOLDER RETURN 2000-2004, % our capacity shortfall and displace our procedures to help us reach our goal of 21 older, less efficient generation. This an accident-free work environment. flexible approach to generation drives We also continue to strive to meet the savings for our customers and needs of our low-income customers earnings growth for our shareholders. through internal operational initiatives, 71
- In nuclear, we will expand our efforts to execute transactions that have consistently driven growth for us in and we fight the bigger war against poverty through external advocacy and regulatory initiatives.
I I (11) ETR S&P S&P the past - including both plant In 2004, we were honored to Electric 500 Utilities acquisitions and management service be included in the Dow Jones agreements - or through other Sustainability Index once again - for the TOTAL SHAREHOLDER RETURN 2004, % innovative ventures. third consecutive year. We are proud to 27 be one of only three U.S. electric utilities 22 We've done more than simply identify included in the index. DJSI-listed opportunities to grow - we are poised to companies must not only demonstrate act when the timing is right. We have strong financial performance, but must 11 made the infrastructure investments, also show outstanding leadership in developed operational expertise, and environmental and social commitment. cultivated strong relationships with In September 2004, Community customers, regulators, and suppliers. Action Partnership, a national ETR S&P S&P These are all strengths we can utilize in organization dedicated to fighting Electric 500 Utilities executing and integrating both utility poverty, honored our CEO Wayne Entergy ranks number one in its peer and nuclear asset acquisitions and other Leonard with its first-ever Corporate group for total shareholder return for the types of transactions. Above all, we Champion Award, recognizing his past five-year period and number six for remain disciplined - we seize only those corporate leadership in addressing the one-year return. We are confident 2004 opportunities that have the potential to multiple causes of poverty. results support our continued leadership in generate profitable long-term growth. Entergy recently received Edison creating value for our shareholders. Electric Institute's first-ever Our Nest Advocacy Excellence Award for our CASH PROVIDED TO SHAREHOLDERS
$ nillions While we have a sharp focus on growth, comprehensive campaign to forestall we also believe that growth must be 1.276 efforts calling for the closure of our sustainable. A clean environment, a safe Indian Point nuclear facilities in New workplace, and a strong economy - to York following the September I1th be a world-class organization, we believe terrorist attacks. Entergy employees Entergy must be a leader in all. volunteered hundreds of hours to We continue to set and meet voluntary educate the public, media, and standards to stabilize our CO 2 emissions governmental entities on the safety and at year-2000 levels. In 2004, our CO2 security of Indian Point as well as the 00 01 02 03 04 emissions were 28 percent lower than vital role the facility plays in delivering In the last five years, we provided nearly year-2000 levels. We have met our target each year since we established our energy to New York. Our campaign for $3 billion in available cash to our shareholders through dividend payouts and stock repurchases.
voluntary standards in 2000. Indian Point began in January 2002 and We believe we have the financial capacity to continues today. make sound investments in our businesses even as we return cash to our shareholders. Entergy Corporation and Subsidiaries 2004 Utility Resourceful and Driven fter making significant investments to result, we saw a 48 percent decrease in outage improve both customer service and frequency over this same period and a 39 percent reliability, our utilities are now in decrease in outage duration. Our regulatory outage position to advocate positive new regulatory rate complaints dropped from 535 in 1998 to 81 in 2004, structures and our Generation Supply Plan. Both a decrease of 85 percent. can deliver financial benefits to our customers and Of special note in 2004 was the recognition shareholders, and we believe they present a well- received by three of our distribution networks for engineered model for growth in our utility business. the safety of their operating environment. In 2004, our Chalmette, New Orleans East, and Riverlake Customer Service and Reliability East distribution networks achieved OSHA The utility business requires a daily commitment Voluntary Protection Program Star status, OSHA's to the basics - customer calls that are well-answered, highest possible industrial safety rating for a work site. generating plants that are well-operated and While this recognition is a terrific achievement in maintained, along with transmission lines with any case, it is especially noteworthy here because it enough capacity and flexibility to meet our marks the first time any utility distribution network customers' varying demand for power. At Entergy, has ever been recognized by OSHA with VPP Star we realize that investing in the basics is the only way status. The safety of our work environment and our to meet our customers' expectations for reliable, employees is vital to our ability to effectively serve affordable service. With this as our operating our customers. mentality, we have been able to improve consistently each year on a variety of customer service and Building Positive Rate Structures reliability measures. In 2004, we pursued opportunities to recover past In 2004, we invested more than S1 billion of our investments and improve returns at Entergy capital dollars in the utility business - a consistent Louisiana, Entergy Gulf States - Louisiana, and level of investment we have made since 1998. As a Entergy Gulf States - Texas.
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BUILDING EXPERTISE We operate our utility and nuclear businesses with an obsessive attention to detail. We stay on top of the basics - the customer call well-answered, fuel savings that drive lower retail energy bills, and intensive training. Operational expertise enables us to deliver excellent service, improve productivity, and provide a sound design for lasting success. k eWXA5 N(C I~ ;v/C5~~~(~1DJO5C'fi 4I
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Entergy Corporation and Subsidiaries 2004 OUTAGE FREQUENCY
- In January 2004, Entergy Louisiana In addition to state regulatory actions, averagenumberper customer peryear filed a S167 million rate case that we are also actively pursuing positive Down 48%
included resources from our regulatory outcomes with FERC. 3.54 Generation Supply Plan and While the majority of these actions are reliability investments. The potential not expected to have an impact on our 1.85 rate increase to customers would be future earnings, we are still fighting for largely offset by estimated fuel savings the best possible outcomes for our that would result from securing customers. Why? Because we know that capacity under our Generation Supply in order to build lasting value for our 98 04 Plan. Discussions indude a formula shareholders, we must operate in a rate plan and are ongoing with a regulatory environment that enables us OUTAGE DURATION potential decision expected around to deliver the best possible value to average minutesper customerperyear the end of first quarter 2005. our customers. Down 39%
- Entergy Gulf States - Louisiana Long term, we believe the incentive 278 requested a $22 million rate increase rate structures in place at Entergy in May 2002. In January 2005, a Mississippi and Entergy New Orleans 169 procedural schedule for a global are excellent models. They include settlement proposal was advanced. financial incentives to the utility upon The settlement proposal resolves 12 meeting performance hurdles in areas open dockets and includes a formula such as reliability, customer service, and rate plan. The current timeline calls the customers' overall cost of power.
98 04 for the Commission to consider the By aligning shareholder interests with global settlement proposal in customer interests, these structures drive REGULATORY OUTAGE COMPLAINTS March 2005. the right behaviors and the right results. Down 85%
- Entergy Gulf States - Texas filed for 535 a S68 million rate increase in August A Comprehensive Supply Plan 2004 after the move to Retail Open The gap between our utility-owned Access was delayed. The Public capacity and our demand load profile is Utility Commission of Texas dose to four gigawatts. To dose that dismissed our case in October and gap, we have developed a comprehensive 81 failed to act on our request for Generation Supply Plan that prescribes 1 rehearing, effectively dismissing our both the contract purchase of power as 98 04 case by operation of law. That's well as acquisition of generation assets.
something we have to change and we The merchant generation capacity We aspire to industry-leading customer satisfaction inour utilities and we steadily will work aggressively and relentlessly within our service territory is invest inour operations to improve reliability. to resolve this situation. We are approximately 19 GW - ample capacity Since 1998, our investments have delivered an currently pursuing an appeal in a to both meet our four GW-capacity improvement inboth the average frequency and Texas district court as well as shortfall and displace some of our less the average duration of outages, and inthe legislative action to get our case efficient, older units. We believe number of regulatory outage complaints. back on track to create financial contracting for or purchasing a portion stability and certainty for Entergy of our generation requirements from Gulf States -Texas. merchant generators creates opportunities to lower our customers' rates. Entergy Corporation and Subsidiaries 2004 In 2004, we took the following steps to Our commitment to executing our implement our Generation Supply Plan: Generation Supply Plan is driven by our desire to do what is right for our STRONG
- We pursued regulatory approvals of customers. In 2004, many consumers RELATIONSHIPS the 718 MW Perryville plant purchase from Cleco Corporation. experienced higher electricity bills as a We expect to be able to close this result of escalating fuel costs. We strive Our future depends on maintaining purchase in mid-2005 and in the to minimize the impact of fuel costs on strong, healthy relationships with interim, we continue to purchase 100 our customers by sourcing more than a number of stakeholders - first percent of the output of Perryville 50 percent of our utility generation from among them, our customers. In under a power purchase agreement nuclear and by acquiring highly efficient 2004, customer service improved that extends through the date of the sources through our Generation Supply with call center abandoned calls acquisition's dose. Plan. We will also consider liquefied down by eight percent and call
- We continued to pursue approval on natural gas, or LNG, in addition to solid answer times down by 24 percent the resources in our Requests for fuel generation such as coal and nuclear compared to 2003. We are also Proposals. While the transparency of plants. Our ongoing evaluation of these working to strengthen our our RFP process is currently being alternatives is based on economics, relationships with local, state, and contested at FERC before an environmental impacts, and other federal regulators as well as the administrative law judge, we continue customer benefits. thousands of employees and to believe the process is fair to all Our goal is to continue to be shareholders who have invested concerned. We expect a decision resourceful builders of shareholder value their time and money with us.
around mid-2005 from the driven by our customers' need for . . administrative law judge. reliable and affordable power.
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.4, Entergy Corporation and Subsidiaries 2004 Nuclear Strong and Vigilant
[I n just five years, Entergy Nuclear has acquired five plants, created a Upon acquiring each unit in our Northeast fleet, we focused first on improving the safety of the plant S200 million business, and grown and then on improving the capacity factor through as-reported earnings from six cents per share in the material condition of the plant. On an ongoing 1999 to S1.06 per share in 2004 - a compound basis, we push for continuous improvement to move annual growth rate of 78 percent. And we believe our Northeast fleet to the performance levels of our the future can be just as promising. Far from being regulated fleet. It's an operating approach that has threatened, we believe nuclear must continue to delivered consistently strong results since 1999 and grow as a percent of U.S. generation as it offers the last year was no different. best possible combination of safe, clean, and In 2004, Entergy plants continued to deliver low-cost energy. excellent performance metrics. The average INPO The operational expertise of our nuclear team is Index for Entergy plants was 96.7 percent - up well-recognized in the industry and has led to a new more than 25 percent since 1999. Outage duration revenue stream from service contracts - including averaged 29 days, compared to 43 days in 1999, and management services at the Cooper Nuclear Station, our forced loss rate improved to 1.69 percent from license renewal services, and nuclear decommissioning. 10.00 percent in 1999. In our nuclear business, we believe our operational In addition we continue to drive production costs strength can enable us to drive growth over and in our Northeast fleet down to levels closer to our above the intrinsic growth rate. regulated fleet and to the industry average. Average production costs declined from $29 per MWh prior Safety and Security Followed by Productivity to Entergy ownership to $20 per MVWh in 2004, We own 10 nuclear plants at eight sites - five in and are expected to be below $19 per MWh by 2006. our regulated utilities and five in the Northeast - Production costs in our regulated fleet remained making us the second-largest nuclear operator in the constant at $15 per MWh. U.S. In every one of our nuclear plants, we put safety and security concerns above all else. l
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-r SAFETY AND SECURITY FIRST We put safety first inour nuclear operations and inour utilities. Our goal is to have an accident-free work environment - nothing less is good enough. And we are fiercely protective of this goal - pursuing productivity improvements only when safety is assured.
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Entergy Corporation and Subsidiaries 2004 Nuclear Milestones record in the country. FitzPatrick was Of special note in 2004 is the recognition selected from more than 150 nominees OUR NEST, several of our plants received for their for accomplishments in the areas of OUR WORLD safe and efficient operations. Our James safety, performance, and costs. A. FitzPatrick plant in New York In Arkansas, our ANO Unit 2 was We have made a conscious received OSHA Voluntary Protection the winner of the Nuclear Energy decision to support sustainable Program Star status recognition - Institute Top Industry Practice award development, meaning we OSHA's highest possible industrial for an innovative inspection technique consciously integrate environmental, safety rating for a work site. We now endorsed by the Nuclear Regulatory social, and safety concerns into have six nuclear plant sites that have Commission for one-time use. It our daily decision-making. We achieved VPP Star status. provided data as reliable as visual have voluntarily committed to To-date, our operating team at inspection while saving an estimated stabilize greenhouse gas emissions FitzPatrick has worked more than $3.6 million in outage costs as well as from our plants and we are 10 million labor-hours without a single 10 days of additional outage downtime. aggressively pursuing solutions lost-time occurrence - a remarkable And it prevented additional radiation to meet the needs of our low- achievement. In addition, FitzPatrick exposure for our outage workers. income customers. We take these also received the Platts Power magazine's The Entergy Nuclear License commitments just as seriously as 2004 Marmaduke award for achieving Renewal team also won an NEI Top we do our financial commitments the best operations and maintenance Industry Practice award for an to our shareholders and lenders.
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Entergy Corporation and Subsidiaries 2004 internet-based work management use insights from our ongoing relationship NUCLEAR NORTHEAST PRODUCTION COSTS system that permits team members to with Merrill Lynch to keep our point of
$/MWh work on the same license renewal view unbiased and current, enabling us Down 31 %
project at the same time from multiple to determine the optimal portion of our 29 locations. Entergy Nuclear, partnering output to sell forward. 20 with Framatome, is the nation's largest contract provider of license renewal Opportunities Follow Capability services to the U.S. nuclear power In 2003, we signed a first-of-its-kind industry. service contract with the Nebraska Public Power District to operate its Before 2004 Intrinsic Growth ETR Cooper Nuclear Station. Since then, Ownership We pursue uprates when economically the NRC has noted improved 2004 Regulated Fleet = $15 per MWh attractive to increase the capacity and performance and recently closed output of our nuclear plants. As a a Cooper confirmatory action letter. NUCLEAR NORTHEAST general rule of thumb, a 100 MW uprate CAPACITY FACTORS A 5100 million capital improvement in our Nuclear Northeast fleet with an program is on schedule. The NPPD Up 19% 92 $800 per KW capital investment and a Board of Directors approved proceeding 77 market price for power of $40 per MVWh with the NRC's operating license yields approximately six cents in earnings renewal process. And in 2004, Cooper per share. had its longest run in plant history. In 2004, we implemented plant Clearly, in one year Cooper has uprates at FitzPatrick and Indian undergone a remarkable turnaround. We Point 2, bringing the total capacity of Before 2004 are proud of what we have been able to ETR our Northeast fleet to 4,058 MW. In Ownership accomplish and believe our capabilities 2005, we expect to complete uprates at 2004 Regulated Fleet = 95% as a nuclear operator will provide similar Waterford 3 and Indian Point 3, and we opportunities in the very near future. In the past five years, we have driven will work to resolve regulatory hurdles to All nuclear owners are facing significant performance Improvement in our place in service the 50 MW uprate we heightened regulatory scrutiny and we Northeast non-regulated nuclear fleet. We completed at Vermont Yankee in 2004. believe that will motivate many small- continue to target the performance levels We proactively engage in selling scale plant owners to exit the business. achieved by our regulated nuclear fleet. power generated by the Northeast fleet Today, there are more than 30 small-through forward contracts. At the end scale plants operating in the U.S. that of 2004, 95 percent of the planned have either production costs greater SOURCES OF GENERATION than $20 per MWh, low capacity generation for 2005 was under contract, Coal Gas/Oil factors, event issues, low regulatory 194 f 29% 89 percent for 2006, and 69 percent for scores, or all of the above. We believe 2007 at average prices per MWh of $39, this segment of the market has good $40, and 542 respectively. That's up potential for future plant sales or significantly from year-end 2003 when management services contracts. In the average contract prices per MWh were meantime, we will further develop the Nuclear 537, $36, and $36 for 2005, 2006, and 520%6 already strong operational expertise that 2007 respectively. Going forward, we will got us here. Entergy's utility generating fleet isone of the cleanest inthe nation. Almost 80 percent of Entergy's power comes from clean nuclear fuel and natural gas generation. Entergy Corporation and Subsidiaries 2004 Looking to the Future Survival of the Species e remain committed to using our In our nuclear business, we have the opportunity to: long-term aspirations as a guide for
- Execute new service agreements in the U.S. and developing our strategies and guiding evaluate opportunities in other markets.
our execution. In particular, we work to identify and
- Acquire additional nuclear assets in the U.S.
act on strategic opportunities that will enable us to
- Increase capacity through uprates.
achieve our stated financial aspirations:
- Sell our output forward under a comprehensive
- Earnings growth of eight to ten percent in 2005 hedging plan to better optimize our pricing.
and 2006 and five to six percent in the longer term.
- Transform our asset portfolio into a business by
- Return on invested capital of nine percent.
adding other types of generation or a short position.
- A net debt to net capital ratio of less than 50 percent.
We also continue to evaluate merger and
- Continuous improvement in credit ratings and acquisition opportunities as they become available business profile position.
- Consistent dividend increases. along with other capital investment opportunities to grow our business. In addition, we continually Our current objectives include several strategic evaluate the opportunity to return cash to shareholders opportunities that may advance our aspirations. through dividends and share repurchases.
Some will materialize and some will not. We believe the opportunities we have identified - In our utilities, we have the opportunity to: along with the decisions made and actions taken in
- Recover ongoing investments in our rate base in 2004 - will lead to continued growth in 2005 and the order to improve reliability and service. years ahead, in keeping with our financial aspirations.
- Earn incentives under performance-based rate structures and incentive regulation.
- Acquire generating capacity under our Generation Supply Plan.
el PF THE FOREST AND THE TREES In every action we take - from the sale of Entergy-Koch Trading to the capital investment to upgrade atransmission line - we are guided by decisive points of view based on extensive market knowledge and sophisticated analysis. We link the big picture to the everyday execution of hundreds of details across our business. N Entergy Corporation and Subsidiaries 2004 A. *' FORWARD-LOOKING INFORMATION From time to time, Entergy makes statements concerning its expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are 'forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Although Entergy believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in the statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:
- resolution of pending and future rate cases and potential stranded costs, the establishment of a negotiations, including various performance-based regional transmission organization that includes rate discussions, and other regulatory proceedings, Entergy's utility service territory, and the including those related to Entergy's System application of market power criteria by FERC Agreement and Entergy's utility supply plan
- changes in regulation of nuclear generating
- Entergy's ability to manage its operation and facilities and nuclear materials and fuel, including maintenance costs, particularly at its Non-Utility possible shutdown of Indian Point or other Nuclear generating facilities nuclear generating facilities
- the performance of Entergy's generating plants, puncertainty regarding the establishment of interim and particularly the capacity factors at its nuclear or permanent sites for spent nuclear fuel storage and disposal CONTENTS generating facilities
- prices for power generated by Entergy's
- resolution of pending or future applications for 22 Five-Year Summary of Selected Financial and unregulated generating facilities, the ability to license extensions or modifications of nuclear Operating Data extend or replace the existing purchased power generating facilities 23 Managements Financial agreements for those facilities, including the
- changes in law resulting from proposed Discussion and Analysis Non-Utility Nuclear plants, and the prices and energy legislation 46 Report of Management availability of power Entergy must purchase for its
- changes in environmental, tax, and other laws, including requirements for reduced emissions 46 Report of Independent utility customers Registered Public
- Entergy's. ability to deveop and execute on a point of sulfur, nitrogen, carbon, mercury, and Accounting Firm of view regarding prices of electricity, natural gas, other substances 47 Report of Independent
- the economic climate, and particularly growth in Registered Public and other energy-related commodities Accounting Firm
- changes in the financial mafkets, particularly those Entergy's service territory variations in weather and the occurrence of 47 Internal Control Over affecting the availability of capital and Entergy's Financial Reporting ability to refinance existing debt, execute its share hurricanes and other storms and disasters 48 Consolidated Statements repurchase program, and fund investments and oadvances in technology of Income acquisitions
- the potential effects of threatened or actual 49 Consolidated Statements
*actions of rating agencies, including changes in the terrorism and war of Retained Earnings, the effects of Entergy's strategies to reduce current Comprehensive Income, ratings of debt and preferred stock, and changes in
- and Paid-In Capital the rating agencies' ratings criteria tax payments 52 Consolidated Statements
- changes in inflation and interest rates
- the effects of litigation and government of Cash Flows
- Entergy's ability to purchase and sell assets at investigations 54 Notes to Consolidated attractive prices and on other attractive terms
- changes in accounting standards, corporate Financial Statements
- volatility and changes in markets for electricity, governance, and securities law requirements natural gas, uranium, and other energy-
- Entergy's ability to attract and retain talented related commodities management and directors
- changes in utility regulation, including the begin-ning or end of retail and wholesale competition, the ability to recover net utility assets and other Entergy Corporation and Subsidiaries 2004 FIVE-YEAR
SUMMARY
OF SELECTED FINANCIAL and OPERATING DATA K, Inthousands, except percentages and per share amounts 2004 2003 2002 2001 2000 SELECTED FINANCIAL DATA AS REPORTED: Operating revenues 510,123,724 S 9,194,920 S 8,305,035 S 9,620,899 510,022,129 Income before cumulative effect of accounting changes S 933,049 S 813,393 S 623,072 S 727,025 S 710,915 Earnings per share before cumulative effect of accounting changes Basic S 4.01 3.48 S 2.69 S 3.18 3.00 s Diluted 3.93 3.42 S 2.64 S 3.13 S 2.97 Dividends declared per share S 1.89 1.60 S 1.34 S 1.28 $ 1.22 Book value per share, year-end 38.25 38.02 S 35.24 S 33.78 31.89 Common shares outstanding At year-end 216,829 228,898 222,422 220,733 219,605 Weighted average - basic 226,864 226,804 223,047 220,944 226,580 Weighted average - diluted 231,194 231,146 227,303 224,734 228,541 Total assets 128,310,777 528,527,388 127,504,366 125,910,311 125,451,896 Long-term obligations(" S 7,180,291 S 7,497,690 S 7,488,919 S 7,743,298 S 8,214,724 Preferred stock S 382,756 S 355,189 S 358,664 S 360,522 S 400,446 Long-term debt (excluding currently maturing debt) S 7,016,831 S 7,322,940 S 7,308,649 S 7,321,028 5 7,732,093 Return on average common equity 10.70% 11.21% 7.85% 10.04% 9.62% Net cash flow provided by operating activities S 2,929,319 5 2,005,820 S 2,181,703 S 2,215,548 5 1,967,847 DOMESTIC UTILITY ELECTRIC REVENUES: Residential S 2,841,517 S 2,682,802 S 2,439,590 S 2,612,889 S 2,524,529 Commercial 2,045,382 1,882,060 1,672,964 1,860,040 1,699,699 Industrial 2,311,185 2,081,781 1,850,476 2,298,825 2,177,236 Governmental 199,631 194,998 179,508 205,054 185,286 Total retail 7,397,715 6,841,641 6,142,538 6,976,808 6,586,750 Sales for resale 388,899 371,646 330,010 395,353 423,519 Other 145,963 183,888 173,866 (127,334) 209,417 Total S 7,932,577 57,397,175 56,646,414 S 7,244,827 S 7,219,686 DOMESTIC UTILITY ELECTRIC SALES: (Milions of KWh) Residential 32,896 32,817 32,581 31,080 31,998 Commercial 26,468 25,863 25,354 24,706 24,657 Industrial 40,293 38,637 41,018 41,577 43,956 Governmental 2,568 2,651 2,678 2,593 2,605 Total retail 102,225 99,968 101,631 99,956 103,216 Sales for resale 8,624 9,248 9,828 8,896 9,794 Total 110,849 109,216 111,459 108,852 113,010 (a) Includes long-term debt (excluding currently maturing debt), preferredstock with sinkingfuna preferred securities ofsubsidiary trusts andpartnership,and noncurrentcapital lease obligations.
/I
Entergy Corporation and Subsidiaries 2004 MANAGEMENT'S FINANCIAL DISCUSSION and ANALYSIS 1_/ I Entergy Corporation is an investor-owned public utility holding RESULTS OF OPERATIONS company that operates primarily through three business segments. Earnings applicable to common stock for the years ended U. S. U T I L I T Y generates, transmits, distributes, and sells December 31, 2004, 2003, and 2002 by operating segment are as electric power in a four-state service territory that includes follows (in thousands): portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operates a small Operating Segment 2004 2003 2002 natural gas distribution business. U.S. Utility $643,408 $469,050 S 583,251
- NON-UTILITY NUCLEAR owns andoperates five nuclear Non-Utility Nuclear 245,029 300,799 200,505 power plants located in the northeastern United States and sells Energy Commodity Services 3,481 180,454 (145,830) the electric power produced by those plants to wholesale Parent &Other 17,606 (23,360) (38,566) customers. This business also provides services to other nuclear Total 5909,524 $926,943 S 599,360 power plant owners.
- ENERGY COMMODITY SERVICES includes Entergy-Koch Following is a discussion of Entergy's income before taxes and Entergy's non-nuclear wholesale assets business. Entergy- according to the business segments listed above. Earnings for 2004 Koch engaged in two major businesses: energy commodity include a 597 million tax benefit that resulted from the sale marketing and trading through Entergy-Koch Trading, and gas of preferred stock and less than 1% of the common stock in transportation and storage through Gulf South Pipeline. a subsidiary in the non-nuclear wholesale assets business; and a Entergy-Koch sold both of these businesses in the fourth quarter 536 million net-of-tax impairment charge in the non-nuclear of 2004, and Entergy-Koch is no longer an operating entity. The wholesale assets business, both of which are discussed below.
non-nuclear wholesale assets business sells to wholesale Earnings for 2003 include the $137.1 million net-of-tax customers the electric power produced by power plants that it cumulative effect of changes in accounting principle that increased owns while it focuses on improving performance and exploring earnings in the first quarter of 2003, almost entirely resulting from sales or restructuring opportunities for its power plants. the implementation of Statement of Financial Accounting Such opportunities are evaluated consistent with Entergy's Standards (SFAS) 143. Earnings were negatively affected in the market-based point-of-view. The non-nuclear wholesale assets fourth quarter of 2003 by voluntary severance program expenses of business terminated new greenfield power development activity 5122.8 million net-of-tax. As part of an initiative to achieve in 2002. productivity improvements with a goal of reducing costs, primarily in the Non-Utility Nuclear and U.S. Utility businesses, in the Following are the percentages of Entergy's consolidated revenues second half of 2003 Entergy offered a voluntary severance and net income generated by these segments and the percentage of program to employees in various departments. Approximately total assets held by them: 1,100 employees, including 650 employees in nuclear operations
%of Revenue from the Non-Utility Nuclear and U.S. Utility businesses, Segment 2004 2003 2002 accepted the offers.
U.S. Utility 81 82 82 Earnings for 2002 were negatively affected by net charges Non-Utility Nudear 13 14 14 ($238.3 million net-of-tax) reflecting the effect of Entergy's Energy Commodity Services 2 2 4 decision to discontinue additional greenfield power plant Parent & Other 4 2 - development and asset impairments resulting from the deteriorating economics of wholesale power markets principally in the United
%of Net Income States and the United Kingdom. The net charges are discussed Segment 2004 2003 2002 more filly below in the Energy Commodity Services discussion.
U.S. Utility 72 52 97 See Note 11 to the consolidated financial statements for further Non-Utility Nuclear 26 32 32 discussion of Entergy's business segments and their financial results Energy Commodity Services - 19 (23) in 2004,2003, and 2002. Parent & Other 2 (3) (6)
% of Total Assets Segment 2004 2003 2002 U.S. Utility 80 79 79 Non-Utility Nudear 16 15 16 Energy Commodity Services 3 7 8 Parent & Other 1 (1) (3)
Entergy Corporation and Subsidiaries 2004 MANAGEMENT'S FINANCIAL DISCUSSION and ANALYSIS continued lI K U.S. UTILITY The volume/weather variance resulted primarily from increased The increase in earnings for the U.S. Utility for 2004 from usage, partially offset by the effect of milder weather on sales
$469 million to $643 million was primarily due to the following. during 2004 compared to 2003. Billed usage increased a total of
- the $107.7 million (S65.6 million net-of-tax) accrual in 2003 of 2,261 GWh in the industrial and commercial sectors.
the loss that would be associated with a final, non-appealable The summer capacity charges variance was due to the decision disallowing abeyed River Bend plant costs. Refer to amortization in 2003 at Entergy Gulf States and Entergy Louisiana Note 2 to the consolidated financial statements for more details of deferred capacity charges for the summer of 2001. Entergy Gulf regarding the River Bend abeyed plant costs; States' amortization began in June 2002 and ended in May 2003.
- lower other operation and maintenance expenses primarily due Entergy Louisiana's amortization began in August 2002 and ended to $99.8 million ($70.1 million net-of-tax) of charges recorded in July 2003.
in 2003 in connection with the voluntary severance program; Base rates increased net revenue due to a base rate increase at
- the $21.3 million net-of-tax cumulative effect of a change in Entergy New Orleans that became effective in June 2003.
accounting principle that reduced earnings at Entergy Gulf The deferred fuel cost revisions variance resulted primarily from States in the first quarter of 2003 upon implementation of a revision in 2003 to an unbilled sales pricing estimate to more SFAS 143. See 'Critical Accounting Estimates - SFAS 143" closely align the fuel component of that pricing with expected below for discussion of the implementation of SFAS 143; recoverable fuel costs at Entergy Louisiana. Deferred fuel cost
- miscellaneous other income of $27.7 million (pre-tax) in 2004 revisions also decreased net revenue due to a revision in 2004 to the resulting from a revision of the decommissioning liability for estimate of fuel costs filed for recovery at Entergy Arkansas in the River Bend, as discussed in Note 8 to the consolidated March 2004 energy cost recovery rider.
financial statements; The price applied to unbilled sales variance resulted from a
- higher net revenue; and decrease in fuel price in 2004 caused primarily by the effect of
- lower interest charges. nuclear plant outages in 2003 on average fuel costs.
The decrease in earnings for the U.S. Utility for 2003 from Gross OperatingRevenues and Regulatory Credits - Gross operating
$583 million to $469 million was primarily due to: revenues include an increase in fuel cost recovery revenues of
- the $107.7 million (S65.6 million net-of-tax) accrual in 2003 of $475 million and $18 million in electric and gas sales, respectively, the loss that would be associated with a final, non-appealable primarily due to higher fuel rates in 2004 resulting from increases in decision disallowing abeyed River Bend plant costs; the market prices of purchased power and natural gas. As such, this
* $99.8 million ($70.1 million net-of-tax) of charges recorded in revenue increase is offset by increased fuel and purchased 2003 in connection with the voluntary severance program; and power expenses.
- the $21.3 million net-of-tax cumulative effect of a change in Other regulatory credits increased primarily due to the following:
accounting principle that reduced earnings at Entergy Gulf
- cessation of the Grand Gulf Accelerated Recovery Tariff that States in the first quarter of 2003 upon implementation of was suspended in July 2003; SFAS 143. See 'Critical Accounting Estimates - SFAS 143"
- the amortization in 2003 of deferred capacity charges for below for discussion of the implementation of SFAS 143. summer 2001 power purchases at Entergy Gulf States and Entergy Louisiana; Partially offsetting the decrease in earnings in 2003 were higher net
- the deferral in 2004 of $14.3 million of capacity charges related revenue and lower interest charges. to generation resource planning as allowed by the Louisiana Public Service Commission (LPSC);
Net Revenue
- the deferral in 2004 by Entergy Louisiana of $11.4 million 2004 Comparedto 2003 related to the voluntary severance program, in accordance with Net revenue, which is Entergy's measure of gross margin, consists of a proposed stipulation entered into with the LPSC staff; and operating revenues net of: 1) fuel, fuel-related, and purchased power
- the deferral in August 2004 of $7.5 million of fossil plant expenses and 2) other regulatory credits. Following is an analysis of maintenance and voluntary severance program costs at Entergy the change in net revenue comparing 2004 to 2003 (in millions): New Orleans as a result of a stipulation approved by the Council of the City of New Orleans (City Council or Council).
2003 net revenue $4,214.5 Volume/weather 68.3 Summer capacity charges 17.4 Base rates 10.6 Deferred fuel cost revisions (46.3) Price applied to unbilled sales (19.3) Other (1.2) 2004 net revenue U4,244.0 Entergy Corporation and Subsidiaries 2004 MANAGEMENT'S FINANCIAL DISCUSSION and ANALYSIS continued 2003 Compared to 2002 Other regulatory credits decreased primarily due to the Net revenue, which is Entergy's measure ofgross margin, consists of APSC-approved March 2002 settlement agreement mentioned operating revenues net of: 1) fuel, fuel-related, and purchased power above, which increased other regulatory credits in 2002 to offset other operation and maintenance expenses of $159.9 million expenses and 2) other regulatory credits. Following is an analysis of related to the December 2000 ice storms. The decrease was the change in net revenue comparing 2003 to 2002 (in millions): partially offset by the asset retirement obligation mentioned above, which increased other regulatory credits in 2003 to offset the 2002 net revenue 34,209.6 increases in depreciation and decommissioning expenses. Base rate increases 66.2 Base rate decreases (23.3) Other Income Statement Variances Deferred fuel cost revisions 56.2 2004 Comparedto 2003 Asset retirement obligation 42.9 Other operation and maintenance expenses decreased from 31.613 Net wholesale revenue 23.2 billion in 2003 to 31.569 billion in 2004 primarily due to voluntary March 2002 Arkansas settlement agreement (154.0) severance program accruals of 399.8 million in 2003 partially offset Other (6.3) by an increase of $30.5 million as a result of higher customer 54,214.5 service support costs in 2004 and an increase of approximately 2003 net revenue 333 million as a result of higher benefits costs in 2004. Entergy expects benefit costs to continue to increase in 2005. See "Critical Base rates increased net revenue due to base rate increases at Accounting Estimates - Pension and Other Retirement Benefits" Entergy Mississippi and Entergy New Orleans that became and Note 10 to the consolidated financial statements for further effective in January 2003 and June 2003, respectively. Entergy Gulf discussion of benefit costs. States implemented base rate decreases in its Louisiana jurisdiction Depreciation and amortization expenses increased from effective June 2002 and January 2003. The January 2003 3797.6 million in 2003 to 3823.7 million in 2004 primarily due to base rate decrease of 322.1 million had a minimal impact on net higher depreciation of Grand Gulf due to a higher scheduled income due to a corresponding reduction in nuclear depreciation sale-leaseback principal payment in addition to an increase in plant and decommissioning expenses associated with the change in in service. accounting estimate to reflect an assumed extension of River Other income (deductions) changed from (336.0 million) in 2003 to $108.9 million in 2004 primarily due to the following: Bend's useful life.
- the 3107.7 million accrual in the second quarter of 2003 for the The deferred fuel cost revisions variance was due to a revised loss that would be associated with a final, non-appealable unbilled sales pricing estimate made in December 2002 and further decision disallowing abeyed River Bend plant costs. See Note 2 revision of that estimate in the first quarter of 2003 to more dosely to the consolidated financial statements for more details align the fuel component of that pricing with expected recoverable regarding the River Bend abeyed plant costs; fuel costs at Entergy Louisiana.
- a reduction in the decommissioning liability for River Bend in The asset retirement obligation variance was due to the 2004, as discussed in Note 8 to the consolidated financial implementation of SFAS 143, 'Accounting for Asset Retirement statements; and Obligations," adopted in January 2003. See 'Critical Accounting
- a 310 million reduction in the loss provision for an Estimates - Nuclear Decommissioning Costs" for more details on environmental clean-up site.
SFAS 143. The increase was offset by increased depreciation and decommissioning expenses and had an insignificant effect Interest on long-term debt decreased from 3433.5 million in 2003 to $390.7 million in 2004 primarily due to the net retirement on net income. and refinancing of long-term debt in 2003 and the first six months The increase in net wholesale revenue was primarily due to an of 2004. See Note 5 to the consolidated financial statements for increase in sales volume to municipal and cooperative customers. details on long-term debt. The March 2002 settlement agreement variance reflects the absence in 2003 of the effect of recording the ice storm settlement 2003 Comparedto 2002 approved by the Arkansas Public Service Commission (APSC) in Other operation and maintenance expenses decreased from 31.679 2002. This settlement resulted in previously deferred revenues at billion in 2002 to 31.613 billion in 2003 primarily due to decreased Entergy Arkansas per the transition cost account mechanism being expenses at Entergy Arkansas. The March 2002 settlement recorded in net revenue in the second quarter of 2002. The decrease agreement that became final in the second quarter of 2002, was offset by a corresponding decrease in other operation and allowing Entergy Arkansas to recover a large majority of 2000 and 2001 ice storm repair expenses through the previously-maintenance expenses and had a minimal effect on net income. collected transition cost account amounts, increased Entergy Arkansas' expenses by 3159.9 million in 2002. This increase in Gross Operating Revenues and Regulatory Credits - Gross operating revenues include an increase in fuel cost recovery revenues of expenses in 2002 was offset by a regulatory credit resulting in no
$682 million and 353 million in electric and gas sales, respectively, effect on net income. The decrease was partially offset by an increase of 399.8 million in benefit costs as a result of voluntary primarily due to higher fuel rates in 2003 resulting from increases in the market prices of purchased power and natural gas. As such, this severance program accruals in 2003.
revenue increase was offset by increased fuel and purchased power expenses. 25-
/K
Entergy Corporation and Subsidiaries 2004 MANAGEMENT'S FINANCIAL DISCUSSION and ANALYSIS continued Decommissioning expense increased from $30.5 million in 2002
- miscellaneous income resulting from a reduction in the to $92.5 million in 2003 primarily due to the implementation of decommissioning liability for a plant, as discussed in Note 8 SFAS 143, 'Accounting for Asset Retirement Obligations.' The to the consolidated financial statements.
increase in decommissioning expense was offset by increases in other regulatory credits and interest and dividend income and had Partially offsetting this increase were the following: an insignificant effect on net income.
- higher income taxes, which increased from $88.6 million in Depredation and amortization expenses increased from $769.8 2003 to $142.6 million in 2004; and million in 2002 to $797.6 million in 2003 primarily due to an
- higher depreciation expense, which increased from $34.3 increase in plant in service. The increase was also due to million in 2003 to $48.9 million in 2004, due to additions to the implementation of SFAS 143. The increase in depreciation and plant in service.
amortization expense due to SFAS 143 implementation was offset by increases in other regulatory credits and interest and dividend income and has an insignificant effect on net income. Other income (deductions) changed from $47.6 million in 2002 to (536.0 million) in 2003 primarily due to a decrease "In the fourth quarter of 2004, Entergy-Koch sold its in "miscellaneous - net" as a result of a $107.7 million accrual in the second quarter of 2003 for the loss that would be associated energy trading and pipeline businesses to third parties. with a final, non-appealable decision disallowing abeyed The sales came after a review of strategic alternatives River Bend plant costs. See Note 2 to the consolidated financial statements for more details regarding the River Bend abeyed plant for enhancing the value of Entergy-Koch, LP." costs. The decrease was partially offset by an increase in interest and dividend income as a result of the implementation of SFAS 143. Interest on long-term debt decreased from $462.0 million in 2002 to $433.5 million in 2003 primarily due to the redemption and 2003 Comparedto 2002 refinancing of long-term debt. The increase in earnings for Non-Utility Nuclear from $200.5 million to $300.8 million was primarily due to the $154.5 million NON-UTILITY NUCLEAR net-of-tax cumulative effect of a change in accounting principle Following are key performance measures for Non-Utility Nuclear. recognized in the first quarter of 2003 upon implementation of SFAS 143. See 'Critical Accounting Estimates - SFAS 143" below 2004 2003 2002 for discussion of the implementation of SFAS 143. Income before Net MW in operation at December 31 4,058 4,001 3,955 the cumulative effect of accounting change decreased by $54.2 Average realized price per MWh $41.26 $39.38 $40.07 million. The decrease was primarily due to $83.0 million Generation in GWh for the year 32,524 32,379 29,953 ($50.6 million net-of-tax) of charges recorded in connection with Capacity factor for the year 92% 92% 93% the voluntary severance program. Except for the effect of the voluntary severance program, operation and maintenance expenses Results of Operations in 2003 per MWh of generation were in line with 2002 operation 2004 Comparedto 2003 and maintenance expenses. The decrease in earnings for Non-Utility Nuclear from $300.8 million to $245.0 million was primarily due to ENERGY COMMODITY SERVICES the $154.5 million net-of-tax cumulative effect of a change in Sales of Entergy-Koch Businesses accounting principle that increased earnings in the first quarter In the fourth quarter of 2004, Entergy-Koch sold its energy trading of 2003 upon implementation of SFAS 143. See 'Critical and pipeline businesses to third parties. The sales came after a Accounting Estimates - SFAS 143" below for discussion of the review of strategic alternatives for enhancing the value of Entergy-implementation of SFAS 143. Earnings before the cumulative effect Koch, LP. Entergy received $862 million of cash distributions in of accounting change increased by $98.7 million primarily due to 2004 from Entergy-Koch after the business sales, and Entergy the following: ultimately expects to receive total net cash distributions exceeding
- lower operation and maintenance expenses, which decreased S1 billion, comprised of the after-tax cash from the distributions of from $681.8 million in 2003 to $595.7 million in 2004, the sales proceeds and the eventual liquidation of Entergy-Koch.
primarily resulting from charges recorded in 2003 in connection Entergy currently expects that it will receive the remaining cash with the voluntary severance program; distributions in 2006, and expects that the net cash distributions
- higher revenues, which increased from $1.275 billion in 2003 to will exceed its equity investment in Entergy- Koch. Entergy expects
$1.342 billion in 2004, primarily resulting from higher contract to record a $60 million net-of-tax gain when the remainder of the pricing. The addition of a support services contract for the proceeds are received in 2006.
Cooper Nuclear Station and increased generation in 2004 due In the purchase agreements for the energy trading and the to power uprates completed in 2003 and fewer planned and pipeline business sales, Entergy-Koch has agreed to indemnify the unplanned outages in 2004 also contributed to the higher respective purchasers for certain potential losses relating to any revenues; and breaches of the sellers' representations, warranties, and obligations 26 -
Entergy Corporation and Subsidiaries 2004 MANAGEMENT'S FINANCIAL DISCUSSION and ANALYSIS continued under each of the purchase agreements. Entergy Corporation has * $204.4 million of the charges resulted from the write-off of guaranteed up to 50% of Entergy-Koch's indemnification Entergy Power Development Corporation's equity investment in obligations to the purchasers. Entergy does not expect any material the Damhead Creek project and the impairment of the values of claims under these indemnification obligations, but to the extent its Warren Power power plant and its Crete and RS Cogen that any are asserted and paid, the gain that Entergy expects to projects. This portion of the charges reflected Entergy's estimate record in 2006 may be reduced. of the effects of reduced spark spreads in the United States and the United Kingdom. Damhead Creek was sold in December Results of Operations 2002, resulting in net income of $31.4 million; 2004 Comparedto 2003 * $39.1 million of the charges related to the restructuring of the The decrease in earnings for Energy Commodity Services from non-nuclear wholesale assets business, which was comprised of
$180.5 million to $3.5 million was primarily due to: $22.5 million of impairments of administrative fixed assets,
- earnings from Entergy's investment in Entergy-Koch were $10.7 million of estimated sublease losses, and $5.9 million of
$254 million lower in 2004, primarily as a result of Entergy- employee-related costs; Koch's trading business reporting a loss from its operations in *$32.7 million of the charges resulted from the write-off of 2004; and capitalized project development costs for projects that would
- Entergy recorded a charge in 2004 of approximately $55 million not be completed; and (S36 million net-of-tax) as a result of an impairment of the
- a gain of $25.7 million ($15.9 million net-of-tax) realized on value of the Warren Power plant, which is owned in the the sale in August 2002 of an interest in projects under non-nuclear wholesale assets business. Entergy concluded that development in Spain.
the plant is impaired based on valuation studies prepared in connection with the Entergy Asset Management stock sale PARENT & OTHER discussed below. Results of Operations 2004 Comparedto 2003 Partially offsetting the decrease in earnings is a tax benefit resulting The increase in earnings for Parent & Other from a $23.4 million from the sale of preferred stock and less than 1% of the common loss to $17.6 million in earnings was primarily due to the following-stock of Entergy Asset Management, an Entergy subsidiary. In
- realization of S16.7 million of tax benefits related to the December 2004, an Entergy subsidiary sold the stock to a third Entergy-Koch investment; and party for $29.75 million. The sale resulted in a capital loss for
- Entergy's competitive retail business earned a very small profit tax purposes of $370 million, producing a net tax benefit of in 2004 compared to reporting a $14.4 million loss in 2003.
$97 million that Entergy recorded in the fourth quarter of 2004.
2003 Comparedto 2002 2003 Compared to 2002 The loss from Parent & Other decreased in 2003 from The increase in earnings for Energy Commodity Services in 2003 $38.6 million to $23.4 million primarily due to lower income from a $145.8 million loss to $180.5 million in earnings was tax expense. primarily due to net charges recorded to operating expenses in 2002, as discussed below. Higher earnings from Entergy's INCOME TAXES investment in Entergy-Koch also contributed to the increase in The effective income tax rates for 2004, 2003, and 2002 were earnings. The income from Entergy's investment in Entergy-Koch 28.2%, 37.9%, and 32.1%, respectively. See Note 3 to the was $73 million higher in 2003 primarily as a result of higher consolidated financial statements for a reconciliation of the federal earnings in its trading business. statutory rate of 35.0% to the effective income tax rates. The lower In 2002, Entergy recorded charges to reflect the effect of effective income tax rate in 2004 is primarily due to the tax benefits Entergy's decision to discontinue additional greenfield power plant resulting from the Entergy Asset Management stock sale development and to reflect asset impairments resulting from discussed above. the deteriorating economics of wholesale power markets principally in the United States and the United Kingdom. The net charges of $428.5 million ($238.3 million net-of-tax) consisted of the following-
- The power development business obtained contracts in October 1999 to acquire 36 turbines from General Electric. Entergy's rights and obligations under the contracts for 22 of the turbines were sold to an independent special-purpose entity in May 2001. $178.0 million of the charges, including an offsetting net-of-tax benefit of $18.5 million related to the subsequent sale of four turbines to a third party, was a provision for the net costs I resulting from cancellation or sale of the turbines subject to purchase commitments with the special-purpose entity; IIII- 27 -
6I
Entergy Corporation and Subsidiaries 2004 MANAGEMENT'S FINANCIAL DISCUSSION and ANALYSIS continued LIQUIDITY AND CAPITAL RESOURCES Note 5 to the consolidated financial statements provides more This section discusses Entergy's capital structure, capital spending detail concerning long-term debt. plans and other uses of capital, sources of capital, and the cash flow In May 2004, Entergy Corporation replaced its 364-day bank activity presented in the cash flow statement. credit facility with two separate facilities, a new 364-day credit facility and a three-year credit facility. The three-year credit CAPITAL STRUCTURE facility, which expires in May 2007, has a borrowing capacity Entergy's capitalization is balanced between equity and debt, as of $965 million, of which $50 million was outstanding at shown in the following table. The reduction in the debt to capital December 31, 2004. percentage from 2002 to 2003 is the result of reduced debt In December 2004, Entergy Corporation refinanced the 364-day outstanding in the U.S. Utility and Non-Utility Nuclear businesses, bank credit facility by entering into a five-year credit facility. The and an increase in shareholders' equity, primarily due to increased five-year credit facility, which expires in December 2009, has a retained earnings. borrowing capacity of $500 million, none of which was outstanding 2004 2003 2002 at December 31, 2004. Net debt to net capital at the end of the year 44.7% 45.3% 47.7% Entergy also has the ability to issue letters of credit against the Effect of subtracting cash from debt 2.7% 2.2% 4.1% total borrowing capacity of both credit facilities, and $50 million of Debt to capital at the end of the year 47.4% 47.5% 51.8% letters of credit had been issued against the three-year facility at December 31, 2004. Net debt consists of debt less cash and cash equivalents. Debt Entergy Corporation's credit facilities require it to maintain a consists of notes payable, capital lease obligations, preferred stock consolidated debt ratio of 65% or less of its total capitalization, and with sinking fund, and long-term debt, including the currently maintain an interest coverage ratio of 2 to 1. If Entergy fails to meet maturing portion. Capital consists of debt, common shareholders' these limits, or if Entergy or the domestic utility companies default equity, and preferred stock without sinking fund. Net capital on other indebtedness or are in bankruptcy or insolvency consists of capital less cash and cash equivalents. The preferred proceedings, an acceleration of the credit facilities' maturity stock with sinking fund is included in debt pursuant to SFAS 150, dates may occur. which Entergy implemented in the third quarter of 2003. The 2002 Capital lease obligations, including nuclear fuel leases, are a minimal part of Entergy's overall capital structure, and are discussed ratio does not reflect that type of security as debt, but does include it in net capital, which is how Entergy presented those securities further in Note 9 to the consolidated financial statements. Following are Entergy's payment obligations under those leases prior to implementation of SFAS 150. Entergy uses the net debt to (in millions): net capital ratio in analyzing its financial condition and believes it 2008- After provides useful information to its investors and creditors in 2005 2006 2007 2009 2009 evaluating Entergy's financial condition. Capital lease payments, Long-term debt, including the currently maturing portion, makes including nuclear fuel leases $136 5143 $3 $2 $3 up over 90% of Entergy's total debt outstanding. Following are Entergy's long-term debt principal maturities as of December 31, Notes payable, which include borrowings outstanding on credit 2003 and 2004 by operating segment. The figures below include facilities with original maturities of less than one year, were less than principal payments on the Entergy Louisiana and System Energy SI million as of December 31, 2004. Entergy Arkansas, Entergy sale-leaseback transactions, which are included in long-term debt Louisiana, Entergy Mississippi, and Entergy New Orleans each on the balance sheet (in millions): have 364-day credit facilities available as follows: Long-term 2008- After Expiration Amount of Amount Drawn as Debt Maturities 2004 2005 2006 2007 2009 2009 Company Date Facility of Dec. 31, 2004 As of December 31,2003 Entergy Arkansas April 2005 585 million U.S. Utility 5450 $355 S 28 $573 S 721 54,305 Entergy Louisiana April 2005 515 million(O - Non-Utility Nuclear 74 72 76 80 40 173 Entergy Mississippi May 2005 525 million Energy Commodity Entergy New Orleans April 2005 $14 million() - Services - - - - - - Parent and Other - 60 - - 539 301 (a) Tbe combined amount borrowed by Entergy Louisianaand Entergy New Orleans under thesefacilities at any one time cannot exceed $15 million. Total $524 $487 $104 $653 $1,300 $4,779 As of December 31, 2004 Operating Lease Obligations and Guarantees U.S. Utility - $359 S 27 S 98 S 749 $4,880 Non-Utility Nuclear - 77 76 80 40 173 of Unconsolidated Obligations Energy Commodity Entergy has a minimal amount of operating lease obligations and Services - - - - - - guarantees in support of unconsolidated obligations. Entergys Parent and Other - 60 - 50 539 301 guarantees in support of unconsolidated obligations are not likely to Total - $496 $103 $228 $1,328 $5,354 have a material effect on Entergy's financial condition or results Entergy Corporation and Subsidiaries 2004 MANAGEMENT'S FINANCIAL DISCUSSION and ANALYSIS continued of operations. Following are Entergy's payment obligations as of CAPITAL EXPENDITURE PLANS AND OTHER USES OF CAPITAL December 31, 2004 on non-cancelable operating leases with a term Following are the amounts of Entergy's planned construction over one year (in millions): and other capital investments by operating segment for 2005 through 2007 (in millions): 2008- After 2005 2006 2007 2009 2009 Planned construction Operating lease payments 599 586 569 S100 5210 and capital investments 2005 2006 2007 Maintenance Capital: The operating leases are discussed more thoroughly in Note 9 to the U.S. Utility S 734 S 699 S 763 consolidated financial statements. Non-Utility Nudear 72 72 60 Energy Commodity Services 3 4 6 Summary of Contractual Obligations Parent and Other 11 19 11 of Consolidated Entities (in millions) 820 794 840 Capital Commitments: 2006- 2008- After U.S. Utility 571 349 201 Contractual Obligations 2005 2007 2009 2009 Total Non-Utility Nuclear 90 67 43 Long-term debtu' S 496 S 331 51,328 55,354 57,509 Energy Commodity Services - - - Capital lease payments(2) S 136 S 146 S 2 S 3 S 287 Parent and Other - - - Operating leases(2) S 99 S 155 S 100 S 210 S 564 661 416 244 Purchase obligations(3) 51,160 $1,402 S 962 51,156 54,680 Total 51,481 51,210 51,084 (1) Long-term debt is discussed in Note S to the consolidatedfinancial statements. Maintenance Capital refers to amounts Entergy plans to spend on routine capital projects that are necessary to support reliability (2) Capital lease payments include nuclearfuel leases. Lease obligations are discussedin Note 9 to the consolidatedfinancialstatements. of its service, equipment, or systems and to support normal (3) Purchaseobligationsrepresent the minimum purchase obligation or cancellation customer growth. chargeforcontractualobligations to purchasegoodsor services. Approximately Capital Commitments refers to non-routine capital investments 99% of the totalpertainstofuel andpurchasedpower obligations that are for which Entergy is either contractually obligated, has recoveredin the normal course of business through variousfuel cost recovery Board-approval, or is otherwise required to make pursuant to a mechanisms in the US. Utility business. regulatory agreement or existing rule or law. Amounts reflected in In addition to these contractual obligations, Entergy expects to con- this category include the following: tribute $185.9 million to its pension plans and 563.3 million
- Replacement of the Arkansas Nuclear One Unit 1 (ANO 1) to other postretirement plans in 2005. steam generators and reactor vessel closure head. Management estimates the cost of the ANO 1 project to be approximately
$235 million, of which approximately $96 million has been incurred through 2004. 5115 million is expected to be incurred in 2005, with the remainder expected to be spent in 2006.
"Assuming regulatory approval by the Entergy expects the replacement to occur during a planned LPSC, Entergy Louisiana expects to refueling outage in 2005. Entergy Arkansas filed with the APSC in January 2003 a request for a declaratory order that the close its acquisition of the 718 MW investment in the replacement is in the public interest. The Perryville power plant in mid-2005." APSC issued the requested order in May 2003. This order is analogous to the order received in 1998 prior to the replacement of the Arkansas Nuclear One Unit 2 (ANO 2) steam generators.
Capital Funds Agreement
- Purchase of the Perryville power plant in Louisiana. In January 2004, Entergy Louisiana signed a definitive agreement to Pursuant to an agreement with certain creditors, Entergy acquire the 718 MW Perryville power plant for S170 Corporation has agreed to supply System Energy with sufficient million.The agreement has subsequently been amended to allow capital to:
the current plant owner to retain the interconnection facilities
- maintain System Energy's equity capital at a minimum of 35%
associated with the plant, resulting in a decrease in the of its total capitalization (excluding short-term debt); acquisition price to $162 million. As a result of the amended
- permit the continued commercial operation of Grand Gulf; terms, the Federal Energy Regulatory Commission (FERC) d pay in full all System Energy indebtedness for borrowed money issued an order in October 2004 disclaiming jurisdiction over when due; and the acquisition. This order currently is subject to rehearing by
- enable System Energy to make payments on specific System FERC. The plant is owned by a subsidiary of Cleco Energy debt, under supplements to the agreement assigning Corporation, which subsidiary submitted a bid in response to System Energy's rights in the agreement as security for the Entergy's Fall 2002 request for proposals for supply-side specific debt.
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Entergy Corporation and Subsidiaries 2004 MANAGEMENT'S FINANCIAL DISCUSSION and ANALYSIS continued I resources. The signing of the agreement followed a voluntary Dividends and Stock Repurchases Chapter 11 bankruptcy filing by the plant's owner. Entergy Declarations of dividends on Entergy's common stock are made at expects that Entergy Louisiana will own 100 percent of the the discretion of the Board. Among other things, the Board Perryville plant, and that Entergy Louisiana will sell 75 percent evaluates the level of Entergy's common stock dividends based upon of the output to Entergy Gulf States under a long-term cost-of- Entergy's earnings, financial strength, and future investment service power purchase agreement. In addition, Entergy opportunities. At its October 2004 meeting, the Board increased Louisiana and Entergy Gulf States executed an interim power Entergy's quarterly dividend per share by 20%, to $0.54. In 2004, purchase agreement with the plant's owner through the date of Entergy paid approximately $428 million in cash dividends on its the acquisition's closing (as long as that occurs by December common stock. 2005) for 100 percent of the output of the Perryville power In accordance with Entergy's stock-based compensation plan, plant. In April 2004, the bankruptcy court approved Entergy Entergy periodically grants stock options to its employees, which Louisiana's agreement to acquire the plant. In March 2004, may be exercised to obtain shares of Entergy's common stock. Entergy Gulf States and Entergy Louisiana filed with the According to the plan, these shares can be newly issued shares, LPSC for its approval of the acquisition and long-term cost-of- treasury stock, or shares purchased on the open market. Entergy's service power purchase agreement. Entergy is seeking approval management has been authorized to repurchase on the open market from the LPSC of cost recovery for the acquisition, giving shares up to an amount sufficient to fund the exercise of grants consideration to the need for the power and the prudence of under the plans. In addition to this authority, the Board has Entergy Louisiana and Entergy Gulf States in engaging in the approved a program under which Entergy will repurchase up to transaction. Hearings are scheduled for March 2005. Assuming $1.5 billion of its common stock through 2006. The amount of regulatory approval by the LPSC, Entergy Louisiana expects repurchases under the program may vary as a result of material the Perryville acquisition to dose in mid-2005. changes in business results or capital spending, or as a result of
- Transmission expansion designed to address immediate load material new investment opportunities. In 2004, Entergy growth needs and to provide improved transmission flexibility repurchased 16,631,800 shares of common stock under both for the southeastern Louisiana and Texas regions of Entergy's programs for a total purchase price of S1.018 billion.
service territory. Entergy expects to spend $170 million on high voltage transmission infrastructure to be completed in phases Public Utility Holding Company Act (PUHCA) between mid-2005 to mid-2007. Restrictions on Uses of Capital
- Purchase of additional generation supply sources within the Entergy's ability to invest in electric wholesale generators and U.S. Utility's service territory.
foreign utility companies is subject to the Securities and Exchange
- Nuclear power plant uprates, dry cask spent fuel storage, and Commission's (SEC) regulations under PUHCA. As authorized by license renewals.
the SEC, Entergy is allowed to invest earnings in electric wholesale generators and foreign utility companies in an amount equal to From time to time, Entergy considers other capital investments 100% of its average consolidated retained earnings. As of December as potentially being necessary or desirable in the future, including 31, 2004, Entergy's investments subject to this rule totaled additional nuclear plant power uprates, generation supply assets,
$2.7 billion constituting 55.9% of Entergy's average consolidated various transmission upgrades, environmental compliance retained earnings.
expenditures, or investments in new businesses or assets. Because no Entergy's ability to guarantee obligations of Entergy's contractual obligation, commitment, or Board-approval exists to non-utility subsidiaries is also limited by SEC regulations under pursue these investments, they are not included in Entergy's PUHCA. In August 2000, the SEC issued an order, effective planned construction and capital investments. These potential through December 31, 2005, that allows Entergy to issue up to investments are also subject to evaluation and approval in $2 billion of guarantees for the benefit of its non-utility companies. accordance with Entergy's policies before amounts may be spent. In In February 2005, Entergy requested that the SEC increase this addition, Entergy's capital spending plans do not include spending limit to $4 billion. for transmission upgrades requested by merchant generators, other Under PUHCA, the SEC imposes a limit equal to 15% of than projects currently underway. consolidated capitalization on the amount that may be invested in Estimated capital expenditures are subject to periodic review and
'energy-related" businesses without specific SEC approval. Entergy modification and may vary based on the ongoing effects of business has made investments in energy-related businesses, including restructuring, regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, and the power marketing and trading. Entergy's available capacity to ability to access capital. make additional investments at December 31, 2004 was approximately $1.9 billion.
Entergy Corporation and Subsidiaries 2004 MANAGEMENT'S FINANCIAL DISCUSSION and ANALYSIS continued
Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued NOTE 6. PREFERRED STOCK The number of shares authorized and outstanding and dollar value of preferred stock and minority interest for Entergy Corporation subsidiaries as of December 31, 2004 and 2003 are presented below. Only the Entergy Gulf States series 'with sinking fund" contain mandatory redemption requirements. All other series of the U.S. Utility are redeemable at Entergy's option. (S in thousands) Shares Authorized Shares Outstanding 2004 2003 2004 2003 2004 2003 U.S. Utility: Preferred Stock without sinking fund: Entergy Arkansas, 4.32% - 7.88% Series 1,613,500 1,613,500 1,613,500 1,613,500 5116,350 $116,350 Entergy Gulf States, 4.20% - 7.56% Series 473,268 473,268 473,268 473,268 47,327 47,327 Entergy Louisiana, 4.16% - 8.00% Series 2,115,000 2,115,000 2,115,000 2,115,000 100,500 100,500 Entergy Mississippi, 4.36% - 8.36% Series 503,807 503,807 503,807 503,807 50,381 50,381 Entergy New Orleans, 4.36% - 5.56% Series 197,798 197,798 197,798 197,798 19,780 19,780 Total U.S. Utility Preferred Stock without sinking fund 4,903,373 4,903,373 4,903,373 4,903,373 $334,337 S334,337 Energy Commodity Services: Preferred Stock without sinking fund: Entergy Asset Management, 11.50% Rate 1,000,000 - 297,376 - 29,738 Other - - - - 1,281 - Total Preferred Stock without sinking fund 5,903,373 4,903,373 5,200,749 4,903,373 5365,356 5334,337 U.S. Utility: Preferred Stock with sinking fund: Entergy Gulf States, Adjustable Rate 7.0%° 174,000 208,520 174,000 208,520 S 17,400 S 20,852 Total Preferred Stock with sinking fund 174,000 208,520 174,000 208,520 S 17,400 S 20,852 Fair Value of Preferred Stockwith sinking fund*" S 15,286 S 15,354 Totals may notfoot due to rounding. (a) Represents weighted-average annualized ratefor 2004 and 2003. of (b) Fairvalues were determinedusing bidprices reportedby dealermarkets and by nationally recognized investment bankingfirms. There is additionaldisclosure fair value offinancial instruments in Note 14 to the consolidatedfinancialstatements. All outstanding preferred stock is cumulative. Entergy Gulf States' preferred stock with sinking fund retirements were 34,500 shares in 2004 and 2003, and 18,579 shares in 2002. Entergy Gulf States has annual sinking fund requirements of 53.45 million through 2009 for its preferred stock outstanding. In 2004, Entergy realized a pre-tax gain of $0.9 million upon the sale to a third party of preferred shares, and less than 1% of the common shares, of Entergy Asset Management, an Entergy subsidiary. See Note 3 to the consolidated financial statements for a discussion of the tax benefit realized on the sale. Entergy Asset Management's stockholders' agreement provides that at any time during the 180-day period prior to December 31, 2007 or each subsequent December 31 thereafter, either Entergy Asset Management or the preferred shareholders may request that the preferred dividend rate be reset. If Entergy Asset Management and the preferred shareholders are unable to agree on a dividend reset rate, a preferred shareholder can request that its shares be sold to a third party. If Entergy Asset Management is unable to sell the preferred shares within 75 days, the preferred shareholder has the right to take control of the Entergy Asset Management board of directors for the purpose of liquidating the assets of Entergy Asset Management in order to repay the preferred shares and any accrued dividends. NOTE 7. COMMON EQUITY COMMON STOCK Treasury Stock Treasury stock activity for Entergy for 2004 and 2003 is as follows (S in thousands): 2004 2003 Treasury Shares Cost Treasury Shares cost Beginning Balance, January 1 19,276,445 S 561,152 25,752,410 S 747,331 Repurchases 16,631,800 1,017,996 155,000 8,135 Issuances: Employee Stock-Based Compensation Plans (4,555,897) (146,877) (6,622,095) (194,057) Directors' Plan (7,320) (252) (8,870) (257) Ending Balance, December 31 31,345,028 S1,432,019 19,276,445 S 561,152 Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors' Plan), the Equity Ownership Plan of Entergy Corporation and Subsidiaries (Equity Ownership Plan), the Equity Awards Plan of Entergy Corporation and Subsidiaries, and certain other stock benefit plans. The Directors' Plan awards to non-employee directors a portion of their compensation in the form of a fixed number of shares of Entergy Corporation common stock. A
Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued Equity Compensation Plan Information grant or restricted period, as appropriate. In 2004, 2003, and 2002, Entergy grants stock options, equity awards, and incentive awards $47 million, $45 million, and $28 million, respectively, was charged to key employees of the Entergy subsidiaries under the Equity to compensation expense. Ownership Plan which is a shareholder-approved stock-based Entergy was assisted by external valuation firms to determine the compensation plan. Stock options are granted at exercise prices not fair value of the stock option grants made in 2004 and 2003. The less than market value on the date of grant. The majority of options fair value applied to these grants was an average of two firms' option granted in 2004, 2003, and 2002 will become exercisable in equal valuations, which included adjustments for factors such as lack amounts on each of the first three anniversaries of the date of grant. of marketability, stock retention requirements, and regulatory Unless they are forfeited previously under the terms of the restrictions on exercisability. In 2002, the fair value of each option grant, options expire ten years after the date of the grant if they grant was estimated on the date of grant using the Black-Scholes are not exercised. option-pricing model, without any such adjustments. The stock Entergy grants most of the equity awards and incentive awards option weighted-average assumptions used in determining the fair earned under its stock benefit plans in the form of performance values were as follows: units, which are equal to the cash value of shares of Entergy 2004 2003 2002 Corporation common stock at the time of payment. In addition Stock price volatility 23.1% 26.3% 27.2% to the potential for equivalent share appreciation or depreciation, Expected term in years 6.3 6.2 5.0 performance units will earn the cash equivalent of the dividends Risk-free interest rate 3.2% 3.3% 4.2% paid during the performance period applicable to each plan. The Dividend yield 3.3% 3.3% 3.2% costs of equity and incentive awards, given either as company stock Dividend payment 51.80 51.40 51.32 or performance units, are charged to income over the period of the Stock option transactions are summarized as follows: 2004 2003 2002 Number Average Number Average Number Average of Options Exercise Price of Options Exercise Price of Options Exercise Price Beginning-of-year balance 15,429,383 538.64 19,943,114 S35.85 17,316,816 $31.06 Options granted 1,898,098 558.63 2,936,236 544.98 8,168,025 541.72 Options exercised (4,541,053) 538.07 (6,927,000) 533.12 (4,877,688) 528.62 Options forfeited/expired (476,351) 539.94 (522,967) 540.98 (664,039) 536.36 End-of-year balance 12,310,077 $41.88 15,429,383 538.64 19,943,114 535.85 Options exercisable at year-end 7,162,884 $37.25 6,153,043 534.82 4,837,511 531.39 Weighted-average fair value of options at time of grant 57.76 56.86 59.22 The following table summarizes information about stock options outstanding as of December 31, 2004: Options Outstanding Options Exercisable Weighted-Range of Number Average Remaining Weighted-Average Number Weighted-Average Exercise Prices of Options Contractual Life-Years Exercise Price of Options Exercise Price 523 - 533.99 1,674,430 5.0 526.28 1,674,430 526.28 534 - S44.99 8,547,519 7.1 S41.09 5,195,493 539.95 545 - $55.99 230,445 5.6 S49.61 222,378 $49.68 556 - S67.99 1,857,683 9.1 S58.64 70,583 $59.67 S23 - 567.99 12,310,077 7.1 541.88 7,162,884 537.25 Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued K RETAINED EARNINGS AND DIVIDEND RESTRICTIONS NUCLEAR INSUJRANCE Provisions within the Articles of Incorporation or pertinent Third Party Liability Insurance indentures and various other agreements relating to the long-term The Price-Anderson Act provides insurance for the public in the debt and preferred stock of certain of Entergy Corporation's event of a nuclear power plant accident. The costs of this insurance subsidiaries restrict the payment of cash dividends or other are borne by the nuclear power industry. Originally passed by distributions on their common and preferred stock. As of December Congress in 1957 and most recently amended in 1988, the 31, 2004, Entergy Arkansas and Entergy Mississippi had restricted Price-Anderson Act requires nuclear power plants to show evidence retained earnings unavailable for distribution to Entergy of financial protection in the event of a nuclear accident. This Corporation of 5394.9 million and $68.5 million, respectively. protection must consist of two levels: Additionally, the Public Utility Holding Company Act (PUHCA) 1. The primary level is private insurance underwritten by prohibits Entergy Corporation's subsidiaries from making loans or American Nuclear Insurers and provides liability insurance advances to Entergy Corporation. In 2004, Entergy Corporation coverage of $300 million. If this amount is not sufficient to received dividend payments totaling 5825 million from subsidiaries. cover claims arising from the accident, the second level, Investments in affiliates that are not controlled by Entergy Secondary Financial Protection, applies. An industry-wide Corporation, but over which it has significant influence, are aggregate limitation of 5300 million exists for domestically-accounted for using the equity method. Entergy's retained earnings sponsored terrorist acts. There is no limitation for for 2003 included $472 million of undistributed earnings of foreign-sponsored terrorist acts. equity method investees. Due to the receipt of dividends from 2. Within the Secondary Financial Protection level, each nuclear Entergy-Koch, LP after the sale of its energy trading and pipeline plant must pay a retrospective premium, equal to its businesses in 2004, there were no undistributed earnings in proportionate share of the loss in excess of the primary level, Entergy's retained earnings at December 31, 2004. Equity up to a maximum of $100.6 million per reactor per incident. method investments are discussed in Note 12 to the consolidated This consists of a $95.8 million maximum retrospective financial statements. premium plus a five percent surcharge that may be applied, if needed, at a rate that is presently set at $10 million per year per NOTE 8. COMMITMENTS AND CONTINGENCIES nuclear power reactor. There are no domestically- or foreign-Entergy is involved in a number of legal, tax, and regulatory sponsored terrorism limitations. proceedings before various courts, regulatory commissions, and Currendy, 104 nuclear reactors are participating in the Secondary governmental agencies in the ordinary course of its business. While Financial Protection program - 103 operating reactors and one management is unable to predict the outcome of such proceedings, closed reactor that still stores used nuclear fuel on site. The product management does not believe that the ultimate resolution of these of the maximum retrospective premium assessment to the nuclear matters will have a material adverse effect on Entergy's results of power industry and the number of nuclear power reactors provides operations, cash flows, or financial condition. over $10 billion in insurance coverage to compensate the public in the event of a nuclear power reactor accident. VIDALIA PURCHASED POWER AGREEMENT Entergy owns and operates ten of the nuclear power reactors, and Entergy Louisiana has an agreement extending through the year owns the shutdown Indian Point 1 reactor (10% of Grand Gulf 2031 to purchase energy generated by a hydroelectric facility known is owned by a non-affiliated company which would share on a as the Vidalia project. Entergy Louisiana made payments under the pro-rata basis in any retrospective premium assessment under the contract of approximately $147.7 million in 2004, 5112.6 million in Price-Anderson Act). 2003, and $104.2 million in 2002. If the maximum percentage An additional but temporary contingent liability exists for all (94%) of the energy is made available to Entergy Louisiana, current nuclear power reactor owners because of a previous Nuclear Worker production projections would require estimated payments of Tort (long-term bodily injury caused by exposure to nuclear approximately S125.3 million in 2005, and a total of $3.5 billion for radiation while employed at a nuclear power plant) insurance the years 2006 through 2031. Entergy Louisiana currently recovers program that was in place from 1988 to 1998. The maximum the costs of the purchased energy through its fuel adjustment clause. premium assessment exposure to each reactor is $3 million and will In an LPSC-approved settlement related to tax benefits from the only be applied if such claims exceed the program's accumulated tax treatment of the Vidalia contract, Entergy Louisiana agreed to reserve funds. This contingent premium assessment feature will credit rates by S11 million each year for up to ten years, beginning expire with the Nuclear Worker Tort program's expiration, which is in October 2002. The provisions of the settlement also provide that scheduled for 2008. the LPSC shall not recognize or use Entergy Louisiana's use of the cash benefits from the tax treatment in setting any of Entergy Propernt Insurance Louisiana's rates. Therefore, to the extent Entergy Louisiana's use of Entergy's nuclear owner/licensee subsidiaries are members of the proceeds would ordinarily have reduced its rate base, no change certain mutual insurance companies that provide property in rate base shall be reflected for ratemaking purposes. damage coverage, including decontamination and premature decommissioning expense, to the members' nuclear generating Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued -I K, plants. These programs are underwritten by Nuclear Electric maximum amounts of such possible assessments per occurrence Insurance Limited (NEIL). As of December 31,2004, Entergy was were $50.8 million for the U.S. Utility plants and $68.9 million for insured against such losses per the following structures: the Non-Utility Nuclear plants. Entergy maintains property insurance for its nuclear units in US. Utility Plants (ANO 1 and 2 GrandGuf l, River Bend, excess of the Nuclear Regulatory Commission's (NRC) minimum and Waterford3) requirement of $1.06 billion per site for nuclear power plant
- Primary Layer (per plant) - $500 million per occurrence licensees. NRC regulations provide that the proceeds of this
- Excess Layer (per plant) - S100 million per occurrence insurance must be used, first, to render the reactor safe and stable,
- Blanket Layer (shared among all plants) - $1.0 billion and second, to complete decontamination operations. Only after per occurrence proceeds are dedicated for such use and regulatory approval is
- Total limit - S1.6 billion per occurrence secured would any remaining proceeds be made available for the
- Deductibles:
benefit of plant owners or their creditors.
* $5.0 million per occurrence - Turbine/generator damage In the event that one or more acts of domestically-sponsored
* $5.0 million per occurrence - Other than turbine/
terrorism causes property damage under one or more or all nuclear generator damage Note: ANO 1 and 2 share in the Primary Layer with one insurance policies issued by NEIL (including, but not limited to, policy in common. those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such Non-Utility Nuclear Plants (Indian Point 2 and 3, FitzPatrick, nuclear insurance policies shall be an aggregate of $3.24 billion plus Pilgrim,and Vermont Yankee) the additional amounts recovered for such losses from reinsurance,
- Primary Layer (per plant) - $500 million per occurrence indemnity, and any other sources applicable to such losses. There
- Blanket Layer (shared among all plants) - $615 million is no aggregate limit involving one or more acts of foreign-per occurrence sponsored terrorism.
- Total limit - S1.115 billion per occurrence
- Deductibles: NUCLEAR DECOMMISSIONING AND OTHER
* $1.0 million per occurrence - Turbine/generator damage RETIREMENT COSTS
* $2.5 million per occurrence - Other than turbine/ SFAS 143, 'Accounting for Asset Retirement Obligations," which generator damage was implemented effective January 1, 2003, requires the recording Note: Indian Point 2 and 3 share in the Primary Layer with one of liabilities for all legal obligations associated with the retirement policy in common.
of long-lived assets that result from the normal operation of those assets. For Entergy, these asset retirement obligations consist of its In addition, the Non-Utility Nuclear plants are also covered under NEIL'S Accidental Outage Coverage program. This liability for decommissioning its nuclear power plants. coverage provides certain fixed indemnities in the event of an These liabilities are recorded at their fair values (which is the unplanned outage that results from a covered NEIL property present values of the estimated future cash outflows) in the period damage loss, subject to a deductible. The following summarizes this in which they are incurred, with an accompanying addition to coverage as of December 31, 2004: the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to Indian Point2 and3 reflect the time value of money for this present value obligation. The
- S4.5 million weekly indemnity amounts added to the carrying amounts of the long-lived assets will
* $490 million maximum indemnity be depreciated over the useful lives of the assets. The net effect of
- Deductible: 12 week waiting period implementing SFAS 143 for the rate-regulated business of the domestic utility companies and System Energy was recorded as a FitzPatrickand Pilgrim (eachplant has an individualpolicy with the notedparameters) regulatory asset, with no resulting impact on Entergy's net income.
* $4.0 million weekly indemnity Entergy recorded these regulatory assets because existing rate * $490 million maximum indemnity mechanisms in each jurisdiction are based on the principle
- Deductible: 12 week waiting period that Entergy will recover all ultimate costs of decommissioning from customers.
Vermont Yankee Upon implementation of SFAS 143 in 2003, assets and liabilities
* $3.5 million weekly indemnity increased $1.1 billion for the U.S. Utility segment as a result of
- S435 million maximum indemnity recording the asset retirement obligations at their fair values of
- Deductible: 12 week waiting period S1.1 billion as determined under SFAS 143, increasing utility plant by $287 million, reducing accumulated depreciation by Entergy's U.S. Utility nuclear plants have significantly less or no
$361 million, and recording the related regulatory assets of $422 accidental outage coverage. Under the property damage and million. The implementation of SFAS 143 for the portion of River accidental outage insurance programs, Entergy nuclear plants could Bend not subject to cost-based ratemanking decreased earnings by be subject to assessments should losses exceed the accumulated
$21 million net-of-tax as a result of a one-time cumulative effect of funds available from NEIL. As of December 31, 2004, the 74-I
Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued I accounting change. In accordance with ratemaking treatment and as $49.6 million reduction in non-utility property, a $40.1 million required by SFAS 71, the depreciation provisions for the domestic reduction in the related regulatory asset, and a regulatory liability of utility companies and System Energy include a component for $17.7 million. For the portion of River Bend not subject to removal costs that are not asset retirement obligations under SFAS cost-based ratemaking, the revised estimate resulted in the 143. In accordance with regulatory accounting principles, Entergy elimination of the asset retirement cost that had been recorded has recorded a regulatory asset for certain of its domestic utility at the time of adoption of SFAS 143 with the remainder recorded companies and System Energy of 586.9 million as of December 31, as miscellaneous income of $27.7 million. 2004 and $72.4 million as of December 31, 2003 to reflect an In the third quarter of 2004, Entergy's Non-Utility Nuclear estimate of incurred but uncollected removal costs previously business recorded a reduction of $20.3 million in decommissioning recorded as a component of accumulated depreciation. The liability to reflect changes in assumptions regarding the timing of decommissioning and retirement cost liability for certain of the when decommissioning of a plant will begin. Entergy considered domestic utility companies and System Energy includes a the assumptions as part of recent studies evaluating the economic regulatory liability of $34.6 million as of December 31, 2004 and effect of the plant in its region. The revised estimate resulted in $26.8 million as of December 31, 2003 representing an estimate of miscellaneous income of $20.3 million, reflecting the excess of the collected but not yet incurred removal costs. For the Non-Utility reduction in the liability over the amount of undepreciated asset Nuclear business, the implementation of SFAS 143 resulted in a retirement cost recorded at the time of adoption of SFAS 143. decrease in liabilities of $595 million due to reductions in If Entergy had applied SFAS 143 during prior periods, the decommissioning liabilities, a decrease in assets of $340 million, following impacts would have resulted: including a decrease in electric plant in service of $315 million, and For the year ended December 31, 2002 an increase in earnings in 2003 of $155 million net-of-tax as a result $599,360 Earnings applicable to common stock - as reported of a one-time cumulative effect of accounting change. Pro forma effect of SFAS 143 S 14,119 The cumulative decommissioning liabilities and expenses Earnings applicable to common stock - pro forma 5613,479 recorded in 2004 by Entergy were as follows (in millions): Basic earnings per average common share - as reported 52.69 Change in Liabilities Pro forma effect of SFAS 143 50.06 Liabilities as of Cash Flow as of Basic earnings per average common share - pro forma 52.75 Dec. 31, 2003 Accretion Estimate Spending Dec. 31, 2004 Diluted earnings per average common share - as reported 52.64 U. S.Utility $1,504.1 $98.0 S(274.1) - S1,328.0 Pro forma effect of SFAS 143 S0.06 Non-Utility Nuclear S 710.4 557.6 S (20.3) 5(9.4) S 738.3 Diluted earnings per average common share - pro forma 52.70 In addition, an insignificant amount of removal costs associated For the Indian Point 3 and FitzPatrick plants purchased with non-nuclear power plants are also included in the in 2000, NYPA retained the decommissioning trusts and decommissioning line item on the balance sheet. Entergy the decommissioning liability. NYPA and Entergy executed periodically reviews and updates estimated decommissioning costs. decommissioning agreements, which specify their decommissioning The actual decommissioning costs may vary from the estimates obligations. NYPA has the right to require Entergy to assume because of regulatory requirements, changes in technology, and the decommissioning liability provided that it assigns the increased costs of labor, materials, and equipment. During 2004, corresponding decommissioning trust, up to a specified level, Entergy updated decommissioning cost studies for ANO 1 and 2 to Entergy. If the decommissioning liability is retained by NYPA, and River Bend. Entergy will perform the decommissioning of the plants at a price In the first quarter of 2004, Entergy Arkansas recorded a revision equal to the lesser of a pre-specified level or the amount in the to its estimated decommissioning cost liability in accordance with a decommissioning trusts. Entergy believes that the amounts new decommissioning cost study for ANO 1 and 2 as a result of available to it under either scenario are sufficient to cover the revised decommissioning costs and changes in assumptions future decommissioning costs without any additional contributions regarding the timing of when the decommissioning of the plants to the trusts. will begin. The revised estimate resulted in a $107.7 million Entergy maintains decommissioning trust funds that are reduction in its decommissioning liability, along with a committed to meeting the costs of decommissioning the nuclear
$19.5 million reduction in utility plant and an $88.2 million power plants. The fair values of the decommissioning trust funds reduction in the related regulatory asset. and asset retirement obligation-related regulatory assets of Entergy In the third quarter of 2004, Entergy Gulf States recorded a as of December 31, 2004 are as follows (in millions):
revision to its estimated decommissioning cost liability in Regulatory accordance with a new decommissioning cost study for River Bend Decommissioning Trust Asset that reflected an expected life extension for the plant. The revised U. S. Utility $1,052.0 5380.1 estimate resulted in a $166.4 million reduction in decommissioning Non-Utility Nuclear 51,401.6 5 - liability, along with a $31.3 million reduction in utility plant, a Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued I/ The Energy Policy Act of 1992 contains a provision that Depreciable Property Lives assesses domestic nuclear utilities with fees for the decontamination During the years 1997 through 2004, Entergy subsidiaries, and decommissioning (D&D) of the DOE's past uranium Entergy Services, Entergy Arkansas, Entergy Gulf States, Entergy enrichment operations. Annual assessments in 2004 were Louisiana, Entergy Mississippi, Entergy New Orleans, and System 54.4 million for Entergy Arkansas, S1.1 million for Entergy Gulf Energy Resources reflected changes in tax depreciation methods States, 51.6 million for Entergy Louisiana, and S1.8 million for with respect to certain types of depreciable property (e.g. street System Energy. The Energy Policy Act calls for cessation of lighting, billing meters, and various generation plant equipment). annual D&D assessments not later than October 24, 2007. At The cumulative effect of these changes results in additional December 31, 2004, two years of assessments were remaining. depreciation deductions generating a cash flow benefit of D&D fees are included in other current liabilities and other approximately 5152 million as of December 31, 2004. The related non-current liabilities and, as of December 31, 2004, recorded IRS interest exposure if the deduction is ultimately disallowed is liabilities were S8.8 million for Entergy Arkansas, 51.9 million for 544 million at December 31, 2004. This benefit reverses over time Entergy Gulf States, 53.3 million for Entergy Louisiana, and and will also fluctuate with each year's addition to those types 53.3 million for System Energy. Regulatory assets in the financial of assets. Due to the temporary nature of the tax benefit, the statements offset these liabilities, with the exception of Entergy potential interest charge represents the total net earnings exposure Gulf States' 30% non-regulated portion. These assessments are of Entergy. recovered through rates in the same manner as fuel costs. For the years under audit, 1996-2001, the IRS challenged Entergy's classification of these assets and proposed adjustments to INCOME TAXES the depreciation deductions taken. Entergy disagrees with the Entergy is currently under audit by the Internal Revenue Service position of the IRS and has protested the disallowance of these (IRS) with respect to tax returns for tax periods subsequent to 1995 deductions to the Office of IRS Appeals. Entergy expects to and through 2001, and is subject to audit by the IRS and other receive a Notice of Deficiency in 2005 for this item, and plans taxing authorities for subsequent tax periods. The amount and to vigorously contest this matter. Entergy believes that the timing of any tax assessments resulting from these audits are contingency provision established in its financial statements uncertain, and could have a material effect on Entergy's financial sufficiently covers the risk associated with this item. position and results of operations. Entergy believes that the contingency provisions established in its financial statements will Mark to Market of Certain Power Contracts sufficiently cover the risk associated with tax matters. Certain In 2001, Entergy Louisiana changed its method of accounting for material audit matters as to which management believes there is a tax purposes related to its wholesale electric power contracts. The reasonable possibility of a future tax assessment are discussed below. most significant of these is the contract to purchase power from the See Note 3 to the consolidated financial statements for additional Vidalia hydroelectric project. The new tax accounting method discussion of income taxes. has provided a cumulative cash flow benefit of approximately
$790 million as of December 31, 2004. The related IRS interest Foreign Tax Credits exposure is $93 million at December 31, 2004. This benefit In July 1997, the UK government enacted the Windfall Tax, which is expected to reverse in the years 2005 through 2031. The election was a one-time tax imposed on formerly government-owned did not reduce book income tax expense. The timing of companies in regulated industries. The Windfall Tax applied to the reversal of this benefit depends on several variables, including companies that the government had previously privatized in the the price of power. Due to the temporary nature of the tax telecommunication, airport operation, gas, water, electricity, and benefit, the potential interest charge represents Entergy's net railway industries. London Electricity, the UK public limited earnings exposure. Entergy Louisiana's 2001 tax return is currently company purchased and subsequently sold by Entergy, was subject under examination by the IRS, though no adjustments have yet to the UK Windfall Tax. Entergy fudfilled its obligation with respect been proposed with respect to the mark to market election. Entergy to the tax in 1997 and 1998. In subsequent tax years, Entergy believes that the contingency provision established in its financial reported a foreign tax credit for the UK Windfall Tax that London statements will sufficiently cover the risk associated with this issue.
Electricity paid. Entergy has claimed a net tax benefit of $152 mil-lion related to this foreign tax credit. CASHPOINT BANKRUPTCY During 2004, the IRS proposed to disallow this foreign tax In 2003, the domestic utility companies entered an agreement with credit. Entergy disagreed with the position of the IRS and CashPoint Network Services (CashPoint) under which CashPoint protested the disallowance of the credit to the Office of IRS was to manage a network of payment agents through which Appeals. Entergy expects to receive a Notice of Deficiency in 2005 Entergy's utility customers could pay their bills. The payment agent for this item, and plans to vigorously contest this matter. The system allows customers to pay their bills at various commercial amount at issue including tax and interest as of December 31, 2004 or governmental locations, rather than sending payments by is 5195 million. Entergy believes that the contingency provision mail. Approximately one-third of Entergy's utility customers use established in its financial statements will sufficiently cover the risk payment agents. associated with this dispute. 76 - I
Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued On April 19, 2004, CashPoint failed to pay funds due to NUCLEAR FUEL LEASES the domestic utility companies that had been collected through As of December 31, 2004, arrangements to lease nuclear fuel payment agents. The domestic utility companies then obtained a existed in an aggregate amount up to 5150 million for Entergy temporary restraining order from the Civil District Court for the Arkansas, $105 million for Entergy Gulf States, 580 million for Parish of Orleans, State of Louisiana, enjoining CashPoint from Entergy Louisiana, and $110 million for System Energy. As of distributing funds belonging to Entergy, except by paying those December 31, 2004, the unrecovered cost base of nuclear fuel funds to Entergy. On April 22, 2004, a petition for involuntary leases amounted to approximately $93.9 million for Entergy Chapter 7 bankruptcy was filed against CashPoint by other Arkansas, $71.2 million for Entergy Gulf States, $31.7 million for creditors in the United States Bankruptcy Court for the Southern Entergy Louisiana, and $65.6 million for System Energy. The lessors finance the acquisition and ownership of nuclear fuel District of New York. In response to these events, the domestic through loans made under revolving credit agreements, the issuance utility companies expanded an existing contract with another of commercial paper, and the issuance of intermediate-term notes. company to manage all of their payment agents. The domestic The credit agreements for Entergy Arkansas, Entergy Gulf States, utility companies filed proofs of claim in the CashPoint Entergy Louisiana, and System Energy each have a termination bankruptcy proceeding in September 2004. Although Entergy date of October 30, 2006. The termination dates may be extended cannot precisely determine at this time the amount that CashPoint from time to time with the consent of the lenders. The intermediate-owes to the domestic utility companies that may not be repaid, it term notes issued pursuant to these fuel lease arrangements have has accrued an estimate of loss based on current information. If no varying maturities through February 15, 2009. It is expected that cash is repaid to the domestic utility companies, an event Entergy additional financing under the leases will be arranged as needed to does not believe is likely, the current estimate of maximum exposure acquire additional fuel, to pay interest, and to pay maturing debt. to loss is approximately $25 million. However, if such additional financing cannot be arranged, the lessee in each case must repurchase sufficient nuclear fuel to allow EMPLOYMENT LITIGATION the lessor to meet its obligations in accordance with the fuel lease. Entergy Corporation and certain subsidiaries are defendants in Lease payments are based on nuclear fuel use. The total numerous lawsuits filed by former employees asserting that they nuclear fuel lease payments (principal and interest) as well as were wrongfully terminated and/or discriminated against on the the separate interest component charged to operations by the basis of age, race, sex, and/or other protected characteristics. domestic utility companies and System Energy were $146.6 Entergy Corporation and these subsidiaries are vigorously defend- million (including interest of $12.8 million) in 2004, $142.0 million ing these suits and deny any liability to the plaintiffs. Nevertheless, (including interest of $11.8 million) in 2003, and $137.8 no assurance can be given as to the outcome of these cases. million (including interest of $11.3 million) in 2002. SALE AND LEASEBACK TRANSACTIONS NOTE 9. LEASES GENERAL In 1988 and 1989, System Energy and Entergy Louisiana, respectively, sold and leased back portions of their ownership As of December 31, 2004, Entergy had capital leases and non-interests in Grand Gulf and Waterford 3 for 26'A-year and 28-year cancelable operating leases for equipment, buildings, vehicles, and lease terms, respectively. Both companies have options to terminate fuel storage facilities (excluding nuclear fuel leases and the Grand the leases, to repurchase the sold interests, or to renew the leases at Gulf and Waterford 3 sale and leaseback transactions) with the end of their terms. minimum lease payments as follows (in thousands): Under System Energy's sale and leaseback arrangements, letters Capital of credit are required to be maintained to secure certain amounts Operating Year Leases Leases payable for the benefit of the equity investors by System Energy 2005 S 99,246 S 9,660 under the leases. The current letters of credit are effective until 2006 85,769 5,724 May 2009. 2007 68,557 3,438 Entergy Louisiana did not exercise its option to repurchase the 2008 55,155 1,754 undivided interests in Waterford 3 in 1994. As a result, Entergy 2009 45,240 237 Louisiana was required to provide collateral for the equity portion Years thereafter 210,474 2,606 of certain amounts payable by Entergy Louisiana under the leases. Minimum lease payments 5564,441 523,419 Such collateral was in the form of a new series of non-interest Less: Amount representing interest - 3,388 bearing first mortgage bonds in the aggregate principal amount of Present value of net $208.2 million issued by Entergy Louisiana in September 1994. minimum lease payments 5564,441 520,031 In July 1997, Entergy Louisiana caused the Waterford 3 lessors to issue $307.6 million aggregate principal amount of Waterford 3 Total rental expenses for all leases (excluding nuclear fuel leases Secured Lease Obligation Bonds, 8.09% Series due 2017, to and the Grand Gulf and Waterford 3 sale and leaseback refinance the outstanding bonds originally issued to finance the transactions) amounted to $81.3 million in 2004, $84.3 million in purchase of the undivided interests by the lessors. In May 2004, 2003, and $92.2 million in 2002. System Energy caused the Grand Gulf lessors to refinance the outstanding bonds that they had issued to finance the purchase of 77-I-
Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued -J K their undivided interest in Grand Gulf. Both refinancings are at COMPONENTS OF NET PENSION COST lower interest rates, and Entergy Louisiana's and System Energy's Total 2004, 2003, and 2002 pension costs of Entergy Corporation lease payments have been reduced to reflect the lower interest costs. and its subsidiaries, including amounts capitalized, included the As of December 31,2004, Entergy Louisiana and System Energy following components (in thousands): had future minimum lease payments, recorded as long-term debt 2004 2003 2002 (reflecting an overall implicit rate of 7.45% and 5.01%, respectively) Service cost - benefits as follows (in thousands): earned during the period S 76,946 S 70,337 S 56,947 Entergy System Interest cost on projected Year Louisiana Energy benefit obligation 148,092 134,403 128,387 2005 S 14,554 S 45,423 Expected return on assets (153,584) (155,460) (158,202) 2006 18,261 46,019 Amortization of transition asset (763) (763) (763) 2007 18,754 46,552 Amortization of prior service cost 5,143 5,886 5,993 2008 22,606 47,128 Recognized net loss 21,687 6,399 5,504 2009 32,452 47,760 Curtailment loss - 14,864 - Years thereafter 334,062 302,402 Special termination benefits - 32,006 Minimum lease payments S440,689 $535,284 Less: Amount representing interest Net pension costs S 97,521 S 107,672 S 37,866 192,964 138,165 Present value of net PENSION OBLIGATIONS, PLAN ASSETS, FUNDED minimum lease payments 5247,725 S397,119 STATUS, AMOUNTS NOT YET RECOGNIZED AND RECOGNIZED IN THE BALANCE SHEET AS OF NOTE 10. RETIREMENT, OTHER POSTRETIREMQENT DECEMBER 31, 2004 AND 2003 (IN THOUSANDS): BENEFITS, AND DEFINED CONTRIBUTION PLANS PENSION PLANS 2004 2003 Entergy has seven pension plans covering substantially all of Change in Projected Benefit its employees: "Entergy Corporation Retirement Plan for Obligation (PBO) Non-Bargaining Employees," 'Entergy Corporation Retirement Balance at beginning of year 52,349,565 $1,992,207 Service cost 76,946 70,337 Plan for Bargaining Employees,""Entergy Corporation Retirement Interest cost 148,092 134,403 Plan II for Non-Bargaining Employees," "Entergy Corporation Amendments 3,709 227 Retirement Plan II for Bargaining Employees," 'Entergy Actuarial loss 171,146 205,949 Corporation Retirement Plan III," "Entergy Corporation Benefits paid (117,234) (97,574) Retirement Plan IV for Non-Bargaining Employees," and "Entergy Employee contributions 1,212 1,059 Curtailment loss - 10,951 Corporation Retirement Plan IV for Bargaining Employees." Special termination benefits - 32,006 Except for the Entergy Corporation Retirement Plan III, the Balance at end of year 52,633,436 S2,349,565 pension plans are noncontributory and provide pension Change in Plan Assets benefits that are based on employees' credited service and Fair value of assets at compensation during the final years before retirement. The Entergy beginning of year 51,744,975 S1,451,802 Corporation Retirement Plan III includes a mandatory employee Actual return on plan assets 170,964 355,043 contribution of 3% of earnings during the first 10 years of plan Employer contributions 72,825 34,645 participation, and allows voluntary contributions from 1% to 10% of Employee contributions 1,212 1,059 earnings for a limited group of employees. Entergy Corporation and Benefits paid (117,234) (97,574) its subsidiaries fund pension costs in accordance with contribution Fair value of assets at end of year $1,872,742 S1,744,975 guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code Funded status S (760,694) S (604,590) of 1986, as amended. The assets of the plans include common and Amounts not yet recognized in the balance sheet preferred stocks, fixed-income securities, interest in a money Unrecognized transition asset (662) (1,426) market fund, and insurance contracts. As of December 31,2004 and Unrecognized prior service cost 29,053 30,467 2003, Entergy recognized an additional minimum pension liability Unrecognized net loss 542,391 410,321 for the excess of the accumulated benefit obligation over the fair Accrued pension cost recognized market value of plan assets. In accordance with SFAS 87, an in the balance sheet S (189,912) S (165,228) offsetting intangible asset, up to the amount of any unrecognized Amounts recognized in prior service cost, was also recorded, with the remaining offset to the balance sheet Accrued pension cost S (189,912) S (165,228) the liability recorded as a regulatory asset reflective of the recovery Additional minimum mechanism for pension costs in Entergy's jurisdictions or to other pension liability (244,280) (180,212) comprehensive income for Entergy's non-regulated business. Intangible asset 26,167 30,832 Entergy's domestic utility companies' and System Energy's pension Accumulated other costs are recovered from customers as a component of cost of comprehensive income 10,781 15,359 Regulatory asset 207,332 134,021 service in each of its jurisdictions. Entergy uses a December 31 Net amount recognized S (189,912) S (165,228) measurement date for its pension plans. Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued K OTHER POSTRETIRENIENT BENEFITS OTHER POSTRETIRENIENT BENEFIT OBLIGATIONS, Entergy also currently provides health care and life insurance bene- PLAN ASSETS, FUNDED STATUS, AND AMiOUNTS NOT fits for retired employees. Substantially all domestic employees may YET RECOGNIZED AND RECOGNIZED IN THE BALANCE become eligible for these benefits if they reach retirement age SHEET AS OF IECEMBER 31, 2004 AND 2003 while still working for Entergy. Entergy uses a December 31 (IN THOUSANDS): measurement date for its postretirement benefit plans. 2004 2003 Effective January 1, 1993, Entergy adopted SFAS 106, which Change in APBO required a change from a cash method to an accrual method Balance at beginning of year S 941,803 S 799,506 of accounting for postretirement benefits other than pensions. Service cost 30,947 37,799 At January 1, 1993, the actuarially determined accumulated Interest cost 53,801 52,746 postretirement benefit obligation (APBO) earned by retirees and Actuarial loss 73,890 115,966 Benefits paid (66,456) (48,379) active employees was estimated to be approximately S241.4 million Plan amendments"' (60,231) (84,722) for Entergy (other than Entergy Gulf States) and 8128 million for Plan participant contributions 9,312 7,074 Entergy Gulf States. Such obligations are being amortized over a - 56,369 Curtailment 20-year period that began in 1993. For the most part, the domestic Special termination benefits - 5,444 utilities and System Energy recover SFAS 106 costs from customers Balance at end of year S 983,066 S 941,803 and are required to fund postretirement benefits collected in rates to Change in Plan Assets an external trust. Fair value of assets at beginning of year S 227,446 S 182,692 COMPONENTS OF NET POSTRETIRENIENT Actual return on plan assets 15,550 22,794 BENEFIT COST Employer contributions 63,399 63,265 Total 2004, 2003, and 2002 other postretirement benefit costs of Plan participant contributions 9,312 7,074 Entergy Corporation and its subsidiaries, including amounts Benefits paid (66,455) (48,379) capitalized and deferred, included the following components Fair value of assets (in thousands): at end of year S 249,252 S 227,446 Funded status S(733,814) S (714,357) 2004 2003 2002 Amounts not yet recognized Service cost - benefits earned in the balance sheet during the period 530,947 S 37,799 S 29,199 Unrecognized transition obligation 5,594 44,815 Interest cost on APBO 53,801 52,746 44,819 Unrecognized prior service cost (39,560) (20,746) Expected return on assets (18,825) (15,810) (14,066) Unrecognized net loss 391,940 336,005 Amortization of Accrued other postretirement benefit transition obligation 9,429 15,193 17,874 cost recognized in the balance sheet S(375,840) S(354,283) Amortization of prior service cost (5,222) (925) 992 (a) Reflects plan design changes, including a change in the participation assumptionforthe majority of non-bargainingemployees effective August 1, Recognized net (gain)Iloss 15,546 12,369 1,874 2003 and certain bargainingemployees and additionalnon-bargaining Curtailment loss - 57,958 employees effective January 1, 2004. Special termination benefits - 5,444 Net other postretirement PENSION AND OTHER POSTRETIRENIENT benefit cost 585,676 $164,774 S 80,692 PLANS' ASSETS Entergy's pension and postretirement plans weighted-average asset allocations by asset category at December 31, 2004 and 2003 are as follows: Pension Postretirement 2004 2003 2004 2003 Domestic Equity Securities 46% 56% 38% 37% International Equity Securities 21% 14% 14% 0% Fixed-Income Securities 31% 28% 47% 60% Other 2% 2% 1% 3%
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Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued -I K Entergy's trust asset investment strategy is to invest the assets in Estimated Future Benefits Payments a manner whereby long-term earnings on the assets (plus cash Years Pension Postretirement contributions) provide adequate funding for retiree benefit 2005 S115,203 S 60,932 payments. The mix of assets is based on an optimization study that 2006 5116,894 S 59,761 identifies asset allocation targets in order to achieve the maximum 2007 5119,092 5 62,392 return for an acceptable level of risk, while minimizing the 2008 5122,728 S 64,381 expected contributions and pension and postretirement expense. 2009 5127,877 S 66,444 In the optimization study, Entergy formulates assumptions (or 2010 - 2014 S780,295 5360,191 hires a consultant to provide such analysis) about characteristics, such as expected asset class investment returns, volatility (risk), and CONTRIBUTIONS correlation coefficients among the various asset classes. The future Entergy expects to contribute $185.9 million (excluding about market assumptions used in the optimization study are determined
$1.2 million in employee contributions) to its pension plans and by examining historical market characteristics of the various asset
$63.3 million to other postretirement plans in 2005.
classes, and making adjustments to reflect future conditions expected to prevail over the study period. ADDITIONAL INFORMATION The optimization analysis utilized in Entergy's latest study produced the following approved asset class target allocations. The change in the minimum pension liability included in other comprehensive income and regulatory assets was as follows for 2004 Pension Postretirement and 2003 (in thousands): Domestic Equity Securities 45% 37% 2004 2003 International Equity Securities 20% 14% Increase/(decrease) in the minimum Fixed-Income Securities 31% 49% pension liability included in: Other (Cash and GACs) 4% 0% Other comprehensive income S(4,578) S (1,639) Regulatory assets 573,311 S(23,768) These allocation percentages combined with each asset class' ACTUARIAL ASSUMPTIONS expected investment return produced an aggregate return expectation for the five years following the study of 7.6% for The assumed health care cost trend rate used in measuring the APBO of Entergy was 10% for 2005, gradually decreasing each pension assets, 5.40% for taxable postretirement assets, and 7.2% successive year until it reaches 4.5% in 2011 and beyond. The for non-taxable postretirement assets. These returns are not assumed health care cost trend rate used in measuring the Net inconsistent with Entergy's disclosed expected pre-tax return on Other Postretirement Benefit Cost of Entergy was 10% for 2004, assets of 8.50% over the life of the respective liabilities. gradually decreasing each successive year until it reaches 4.5% in Since precise allocation targets are inefficient to manage security 2010 and beyond. A one percentage point change in the assumed investments, the following ranges were established to produce an health care cost trend rate for 2004 would have the following effects acceptable economically efficient plan to manage to targets: (in thousands): Pension Postretirement 1 Percentage Point Increase 1 Percentage Point Decrease Domestic Equity Securities 45% to 55% 32% to 42% Impact Impact International Equity Securities 15% to 25% 9% to 19% on the sum of on the sum of Fixed-Income Securities 25% to 35% 44% to 54% Impact on service costs and Impact on service costs and 2004 the APBO interest cost the APBO interest cost Other 0% to 10% 096 to 5% Entergy Corporation 599,271 511,587 5(89,801) 5(10,061) AcCUMULATED PENSION BENEFIT OBLIGATION The accumulated benefit obligation for Entergy's pension plans was The significant actuarial assumptions used in determining the
$2.3 billion and $2.1 billion at December 31, 2004 and 2003, pension PBO and the SFAS 106 APBO for 2004, 2003, and 2002 respectively.
were as follows: ESTIMATED FUTURE BENEFIT PAYMENTS 2004 2003 2002 Based upon the assumptions used to measure the company's Weighted-average discount rate: pension and postretirement benefit obligation at December 31, Pension 6.00% 6.25% 6.75% 2004, and including pension and postretirement benefits Other postretirement 6.00% 6.71% 6.75% attributable to estimated future employee service, Entergy expects Weighted-average rate of increase that benefits to be paid over the next ten years will be as follows in future compensation levels 3.25% 3.25% 3.25% (in thousands): Expected long-term rate of return on plan assets: Taxable assets 5.50% 5.50% 5.50% Non-taxable assets 8.50% 8.75% 8.75% II IN I
Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued -I The significant actuarial assumptions used in determining the net In 2004, Entergy continued to record an estimate of the effects periodic pension and other postretirement benefit costs for 2004, of the Act in accounting for its postretirement benefit plans. In 2003, and 2002 were as follows: mid-2004, the Financial Accounting Standards Board issued Staff Position No. FAS 106-2, Accounting and Disclosure Requirements 2004 2003 2002 Related to the Medicare Prescription Drug, Improvement and Weighted-average discount rate Modernization Act of 2003, which was effective for Entergy's June Pension 6.25% 6.75% 7.50% 30,2004 interim reporting. Other postretirement 6.71% 6.75% 7.50% In August 2004, the Centers for Medicare and Medicaid Services Weighted-average rate of increase issued proposed regulations to implement the new Medicare law. in future compensation levels 3.25% 3.25% 4.60% A ruling from the Centers for Medicare and Medicaid Services Expected long-term rate of was issued in late January 2005 with final guidance expected later return on plan assets: this year. Taxable assets 5.50% 5.50% 5.50% The actuarially estimated effect of future Medicare subsidies Non-taxable assets 8.75% 8.75% 9.00% reduced the December 31, 2003 and 2004 Accumulated Postretirement Benefit Obligation by $128 million and $161 Entergy's remaining pension transition assets are being million, respectively, and reduced the 2004 other postretirement amortized over the greater of the remaining service period of active benefit cost by $23.3 million. participants or 15 years ending in 2005, and its SFAS 106 transition obligations are being amortized over 20 years ending in 2012. DEFINED CONTRIBUTION PLANS Entergy sponsors the Savings Plan of Entergy Corporation and VOLUNTARY SEVERANCE PROGRAM Subsidiaries (System Savings Plan). The System Savings Plan is a As part of an initiative to achieve productivity improvements with a defined contribution plan covering eligible employees of Entergy goal of reducing costs, primarily in the Non-Utility Nuclear and and its subsidiaries. Through January 31,2004, the System Savings U.S. Utility businesses, in the second half of 2003 Entergy offered a Plan provided that the employing Entergy subsidiary: voluntary severance program to employees in various departments.
- make matching contributions to the System Savings Plan in an Approximately 1,100 employees, including 650 employees in amount equal to 75% of the participants' basic contributions, up nuclear operations from the Non-Utility Nuclear and US. Utility to 6% of their eligible earnings, in shares of Entergy businesses, accepted the offers. As a result of this program, in the Corporation common stock if the employees direct their fourth quarter of 2003 Entergy recorded additional pension company-matching contribution to the purchase of Entergy and postretirement costs (including amounts capitalized) of Corporation's common stock; or S110.3 million for special termination benefits and plan curtailment
- make matching contributions in the amount of 50% of the charges. These amounts are included in the net pension cost and net participants' basic contributions, up to 6% of their eligible postretirement benefit cost for the year ended December 31, 2003. earnings, if the employees direct their company-matching contribution to other investment funds.
MEDICARE PRESCRIPTION DRUG, IMPROVEMENT AND MODERNIZATION ACT OF 2003 Effective February 1,2004, the employing Entergy subsidiary began In December 2003, the President signed the Medicare Prescription making matching contributions for non-bargaining employees to the System Savings Plan in an amount equal to 70% of the Drug, Improvement and Modernization Act of 2003 into law. The participants' basic contributions, up to 6% of their eligible Act introduces a prescription drug benefit cost under Medicare earnings. The 70% match is allocated to investments as directed (Part D), starting in 2006, as well as federal subsidy to employers by the employee. who provide a retiree prescription drug benefit that is at least Entergy also sponsors the Savings Plan of Entergy Corporation actuarially equivalent to Medicare Part D. and Subsidiaries II (established in 2001), the Savings Plan of At December 2003, specific authoritative guidance on the Entergy Corporation and Subsidiaries III (established in 2002), and accounting for the federal subsidy was pending. As allowed by the Savings Plan of Entergy Corporation and Subsidiaries V Financial Accounting Standards Board Staff Position No. FAS (established in 2002). The plans are defined contribution plans that 106-1, Entergy elected to record an estimate of the effects of the cover eligible employees, as defined by each plan, of Entergy and its Act in accounting for its postretirement benefit plans at December subsidiaries. The employing Entergy subsidiary makes matching 31, 2003, under SFAS 106 and in providing disclosures required by contributions equal to 50% of the participants' participating SFAS No. 132 (revised 2003), Employers' Disclosures about contributions for each of these plans. Effective September 30,2004, Pensions and Other Postretirement Benefits. At December 31, employees participating in the Savings Plan of Entergy 2003, based on actuarial analysis of prescription drug benefits, Corporation and Subsidiaries III (Savings Plan III) were estimated future Medicare subsidies were expected to reduce the transferred into the System Savings Plan and Savings Plan III December 31, 2003 Accumulated Postretirement Benefit Obligation by $56 million. For the year ended December 31, 2003, was terminated. Entergy's subsidiaries' contributions to defined contribution the impact of the Act on net postretirement benefit cost was plans collectively were £32.9 million in 2004, $31.5 million in 2003, immaterial, as it reflected only one month's impact of the Act. and $29.6 million in 2002. The majority of the contributions were to the System Savings Plan. 81 - 1
Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued -I NOTE 11. BUSINESS SEGMENT INFORMATION customers the electric power produced by power plants that it owns Entergy's reportable segments as of December 31, 2004 are U.S. while it focuses on improving performance and exploring sales or Utility, Non-Utility Nuclear, and Energy Commodity Services. restructuring opportunities for its power plants. Such opportunities U.S. Utility generates, transmits, distributes, and sells electric power are evaluated consistent with Entergy's market-based point-of-in portions of Arkansas, Louisiana, Mississippi, and Texas, and view. Results from Entergy-Koch are reported as equity in earnings provides natural gas utility service in portions of Louisiana. of unconsolidated equity affiliates in the financial statements. Non-Utility Nuclear owns and operates five nuclear power plants Entergy's operating segments are strategic business units managed and is primarily focused on selling electric power produced by those separately due to their different operating and regulatory plants to wholesale customers. Energy Commodity Services environments. Entergy's chief operating decision maker is includes Entergy-Koch, LP and Entergy's non-nuclear wholesale its Office of the Chief Executive, which consists of its assets business. Entergy-Koch engaged in two major businesses: highest-ranking officers. energy commodity marketing and trading through Entergy-Koch "All Other" includes the parent company, Entergy Corporation, Trading, and gas transportation and storage through Gulf South and other business activity, including the Competitive Retail Pipeline. Entergy-Koch sold both of these businesses in the fourth Services business, which has higher revenues in 2004 as its number quarter of 2004, and Entergy-Koch is no longer an operating of customers has increased, and earnings on the proceeds of sales of entity. The non-nuclear wholesale assets business sells to wholesale previously-owned businesses. Entergy's segment financial information is as follows (in thousands): Energy Non-Utility Commodity U.S. Utility Nuclear' Services' All Other' Eliminations Consolidated 2004 Operating revenues S 8,142,808 $1,341,852 S 216,450 S 486,804 S (64,190) S 10,123,724 Deprec., amort. & decomm. 915,667 106,408 16,311 6,736 1,045,122 Interest income 40,831 63,569 17,875 42,729 (55,195) 109,809 Equity in loss of unconsolidated equity affiliates (78,727) (78,727) Interest charges 383,032 53,657 15,560 81,916 (55,142) 479,023 Income taxes (credits) 406,864 142,620 (155,840) (27,736) 365,908 Net income 666,691 245,029 3,778 17,606 (55) 933,049 Total assets 22,937,237 4,531,604 2,223,961 199,233 (1,581,258) 28,310,777 Investments in affiliates - at equity 207 512,571 (280,999) 231,779 Cash paid for long-lived asset additions 1,152,167 242,822 2,022 13,604 (5) 1,410,610 2003 Operating revenues S 7,584,857 51,274,983 S 184,888 S 188,228 S (38,036) S 9,194,920 Deprec., amort. & decomm. 890,092 87,825 13,681 5,005 996,603 Interest income 43,035 36,874 18,128 27,575 (38,226) 87,386 Equity in earnings (loss) of unconsolidated equity affiliates (3) 271,650 271,647 Interest charges 419,111 34,460 15,193 75,787 (38,225) 506,326 Income taxes (credits) 341,044 88,619 105,903 (45,492) 490,074 Cumulative effect of accounting change (21,333) 154,512 3,895 137,074 Net income (loss) 492,574 300,799 180,454 (23,360) 950,467 Total assets 22,402,314 4,171,777 2,076,921 1,495,903 (1,619,527) 28,527,388 Investments in affiliates - at equity 211 1,081,462 (28,345) 1,053,328 Cash paid for long-lived asset additions 1,233,208 281,377 44,284 10,074 1,568,943 2002 Operating revenues S 6,773,509 51,200,238 S 294,670 S 40,729 S (4,111) S 8,305,035 Deprec., amort. & decomm. 800,257 88,733 21,465 5,143 915,598 Interest income 23,231 71,262 26,140 35,433 (37,741) 118,325 Equity in earnings (loss) of unconsolidated equity affiliates (2) 183,880 183,878 Interest charges 465,703 47,291 61,632 35,579 (37,741) 572,464 Income taxes (credits) 313,752 132,726 (141,288) (11,252) 293,938 Net income (loss) 606,963 200,505 (145,830) (38,566) 623,072 Total assets 21,630,523 4,482,308 2,167,472 1,327,354 (2,103,291) 27,504,366 Investments in affiliates - at equity 214 823,995 824,209 Cash paid for long-lived asset additions 1,131,734 169,756 210,297 18,514 1,530,301 Businesses marked with *are referredto as the 'competitive businesses,' 'with the exception of the parentcompany, Entergy Corporation,which is included in 111 Other' Eliminations ar" primarily intersegment activity. Substantiallyall ofEntergy's recordedassetfor goodwill is in its US. Utility segment. _1
Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued 21 In the fourth quarter of 2004, Entergy recorded a charge of GEOGRAPHIC AREAS approximately 555 million ($36 million net-of-tax) as a result of an For the years ended December 31, 2004 and 2003, Entergy derived impairment of the value of the Warren Power plant. Entergy less than 1% of its revenue from outside of the United States. For concluded that the value of the plant, which is owned in the the year ended December 31, 2002 Entergy derived 3% of its non-nuclear wholesale assets business, was impaired. Entergy revenue from outside of the United States. reached this conclusion based on valuation studies prepared in As of December 31, 2004 and 2003, Entergy had almost no connection with the sale of preferred stock in a subsidiary in the long-lived assets located outside of the United States. non-nuclear wholesale assets business. Energy Commodity Services' net loss for the year ended NOTE 12. EQUITY METHOD INVESTMENTS December 31, 2002 includes net charges of $428.5 million to As of December 31,2004, Entergy owns investments in the follow-operating expenses ($238.3 million net-of-tax). These charges ing companies that it accounts for under the equity method of reflect the effect of Entergy's decision to discontinue additional accounting: greenfield power plant development and the asset impairments resulting from the deteriorating economics of wholesale power Company Ownership Description markets in the United States and the United Kingdom. The net Entergy-Koch, LP 50% partnership Engaged in two major busi-charges consist of the following: interest nesses: energy commodity
- The power development business obtained contracts in October marketing and trading through Entergy-Koch 1999 to acquire 36 turbines from General Electric. Entergy's Trading, and gas transporta-rights and obligations under the contracts for 22 of the turbines tion and storage through Gulf were sold to an independent special-purpose entity in May South Pipeline. Entergy-2001. $178.0 million of the charges, including an offsetting Koch sold both of these busi-benefit of $28.5 million ($18.5 million net-of-tax) related to the nesses in the fourth quarter of sale of four turbines to a third party, is a provision for the net 2004, and Entergy-Koch is no costs resulting from cancellation or sale of the turbines subject longer an operating entity to purchase commitments with the special-purpose entity. RS Cogen LLC 50% member Co-generation project that
* $204.4 million of the charges result from the write-off of interest produces power and steam Entergy Power Development Corporation's equity investment in on an industrial and the Damhead Creek project and the impairment of the values of merchant basis in the Lake the Warren Power power plant, the Crete project, and the RS Charles, Louisiana area.
Cogen project. This portion of the charges reflects Entergy's Top Deer 50% member Wind-powered electric gener-estimate of the effects of reduced spark spreads in the United interest ation joint venture. States and the United Kingdom. These estimates are based on various sources of information, including discounted cash flow Following is a reconciliation of Entergy's investments in equity projections and current market prices. affiliates (in thousands):
* $39.1 million of the charges relate to the restructuring of the 2004 2003 2002 non-nuclear wholesale assets business, including impairments of Beginning of year 51,053,328 S 824,209 S 766,103 administrative fixed assets, estimated sublease losses, and Additional investments 157,020 4,668 36,372 employee-related costs for approximately 135 affected Income (loss) from the investments (78,727) 271,647 183,878 employees. These restructuring costs, which are included in the Other income 6,232 45,583 21,462 "Provision for turbine commitments, asset impairments, and Distributions received (888,260) (105,142) (73,902) restructuring charges" in the accompanying consolidated Dispositions and other adjustments (17,814) 12,363 (109,704) statement of income, were comprised of the following End of year S 231,779 51,053,328 S 824,209 (in millions): Paid in Remaining Cash Accrual The following is a summary of combined financial information Restructuring through Non-Cash as of reported by Entergy's equity method investees (in thousands):
Costs Dec. 2004 Portion Dec. 31, 2004 Fixed asset impairments 522.5 5 - 522.5 5 - 2004 2003 2002 Sublease losses 10.7 5.6 - 5.1 Income Statement Items Severance and related costs 5.9 5.9 - Operating revenues S 270,177 S 585,404 S 551,853 Total $39.1 511.5 522.5 S5.1 Operating income 5(111,535) S 207,301 S 159,342 Net income S 739,858"' S 172,595 S 68,095
* $32.7 million of the charges result from the write-off of Balance Sheet Items capitalized project development costs for projects that will not Current assets S 540,386 52,576,630 be completed. Noncurrent assets S 418,038 51,675,334
- The net charges include a gain of $25.7 million ($15.9 million Current liabilities S 180,009 51,757,663 net-of-tax) on the sale of projects under development in Spain Noncurrent liabilities S 463,899 51,166,540 in August 2002 and the after-tax gain of $31.4 million realized (1) Includes gains recorded by Entergy-Koch on the sales of its energy trading and on the sale of Damhead Creek in December 2002. pipeline businesses.
Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued I/ RELATED-PARTY TRANSACTIONS AND GUARANTEES ASSET DISPOSITIONS During 2004, 2003, and 2002, Entergy procured various services Entergy-Koch Businesses from Entergy-Koch consisting primarily of pipeline transportation In the fourth quarter of 2004, Entergy-Koch sold its energy trading services for natural gas and risk management services for electricity and pipeline businesses to third parties. The sales came after a and natural gas. The total cost of such services in 2004, 2003, and review of strategic alternatives for enhancing the value of Entergy-2002 was approximately $9.5 million, $15.9 million, and $11.2 mil- Koch, LP. Entergy received $862 million of cash distributions in lion, respectively. In 2003, Entergy Louisiana and Entergy New 2004 from Entergy-Koch after the business sales, and Entergy Orleans entered purchase power agreements with RS Cogen, and ultimately expects to receive total net cash distributions exceeding purchased a total of $26.0 million of capacity and energy from RS $1 billion, comprised of the after-tax cash from the distributions of Cogen in 2003. In 2004, Entergy Louisiana and Entergy New the sales proceeds and the eventual liquidation of Entergy-Koch. Entergy currently expects the net cash distributions that it will Orleans purchased a total of $43.6 million of capacity and energy receive will exceed its equity investment in Entergy-Koch, and from RS Cogen. Entergy's operating transactions with its other expects to record a $60 million net-of-tax gain when it receives the equity method investees were not material in 2004, 2003, or 2002. remaining cash distributions, which it expects will occur in 2006. In the purchase agreements for the energy trading and the pipeline business sales, Entergy-Koch has agreed to indemnify the Other respective purchasers for certain potential losses relating to any In January 2004, Entergy sold its 50% interest in the Crete project, breaches of the sellers' representations, warranties, and obligations which is a 320 MW power plant located in Illinois, and realized an under each of the purchase agreements. Entergy Corporation has insignificant gain on the sale. guaranteed up to 50% of Entergy-Koch's indemnification In the fourth quarter of 2004, Entergy sold undivided interests in obligations to the purchasers. Entergy does not expect any material the Warren Power and the Harrison County plants at a price that claims under these indemnification obligations, but to the extent approximated book value. that any are asserted and paid, the gain that Entergy expects to In the first quarter of 2002, Entergy sold its interests in projects record in 2006 may be reduced. in Argentina, Chile, and Peru for net proceeds of $135.5 million. During the fourth quarter of 2004, an Entergy subsidiary After impairment provisions recorded for these Latin American purchased from a commercial bank holder $16.3 milion of RS interests in 2001, the net loss realized on the sale in 2002 was Cogen subordinated indebtedness, due October 2017, bearing insignificant. interest at Libor + 4.50%. The debt was purchased at a discount In August 2002, Entergy sold its interest in projects under of approximately $2.4 million that will be amortized over the development in Spain for a realized gain on the sale of remaining life of the debt. $25.7 million. In December 2002, Entergy sold its 800 MW Damhead Creek power plant in the UK resulting in an increase in NOTE 13. ACQUISITIONS AND DISPOSITIONS net income of S31.4 million. The Damhead Creek buyer assumed ASSET AcQuISITIONS all market and regulatory risks associated with the facility. Vermont Yankee NOTE 14. RISK MANAGEMENT AND FAIR VALUES In July 2002, Entergy's Non-Utility Nuclear business purchased the MARKET AND COMMODITY RISKS 510 MW Vermont Yankee nuclear power plant located in Vernon, In the normal course of business, Entergy is exposed to a number of Vermont, from Vermont Yankee Nuclear Power Corporation for market and commodity risks. Market risk is the potential loss that
$180 million. Entergy received the plant, nuclear fuel, inventories, Entergy may incur as a result of changes in the market or fair and related real estate. The liability to decommission the plant, as value of a particular instrument or commodity. All financial and well as related decommissioning trust funds of approximately commodity-related instruments, including derivatives, are subject to $310 million, was also transferred to Entergy. The acquisition market risk. Entergy is subject to a number of commodity and included a 10-year power purchase agreement (PPA) under which market risks, including:
the former owners will buy the power produced by the plant, which is through the expiration of the current operating license for Type of Risk Primary Affected Segments the plant. The PPA includes an adjustment clause which provides Power price risk All reportable segments that the prices specified in the PPA will be adjusted downward Fuel price risk All reportable segments annually, beginning in December 2005, if power market prices drop Foreign currency exchange rate risk All reportable segments below the PPA prices. Equity price and interest The acquisition was accounted for using the purchase method. rate risk - investments US. Utility, Non-Utility Nuclear The results of operations of Vermont Yankee subsequent to the purchase date have been included in Entergy's consolidated results Entergy manages these risks through both contractual of operations. The purchase price has been allocated to the assets arrangements and derivatives. Contractual risk management tools acquired and liabilities assumed based on their estimated fair values include long-term power and fuel purchase agreements, capacity contracts, and tolling agreements. Entergy also uses a variety of on the purchase date. Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS continued commodity and financial derivatives, including natural gas and Fair Values electricity futures, forwards, swaps, and options; foreign currency FinancialInstruments forwards; and interest rate swaps as a part of its overall risk The estimated fair value of Entergy's financial instruments is management strategy. Except for the energy trading activities determined using bid prices reported by dealer markets and by conducted through December 2004 by Entergy-Koch, Entergy nationally recognized investment banking firms. The estimated fair enters into derivatives only to manage natural risks inherent in its value of derivative financial instruments is based on market quotes. physical or financial assets or liabilities. Considerable judgment is required in developing some of the Entergy's exposure to market risk is determined by a number of estimates of fair value. Therefore, estimates are not necessarily factors, including the size, term, composition, and diversification of indicative of the amounts that Entergy could realize in a current positions held, as well as market volatility and liquidity. For market exchange. In addition, gains or losses realized on financial instruments such as options, the time period during which the instruments held by regulated businesses may be reflected in future option may be exercised and the relationship between the current rates and therefore do not necessarily accrue to the benefit or market price of the underlying instrument and the option's detriment of stockholders. contractual strike or exercise price also affects the level of market Entergy considers the carrying amounts of most of its financial risk. A significant factor influencing the overall level of market risk instruments classified as current assets and liabilities to be a to which Entergy is exposed is its use of hedging techniques to reasonable estimate of their fair value because of the short maturity mitigate such risk. Entergy manages market risk by actively of these instruments. Additional information regarding financial monitoring compliance with stated risk management policies as instruments and their fair values is included in Notes 5 and 6 to the well as monitoring the effectiveness of its hedging policies and consolidated financial statements. strategies. Entergy's risk management policies limit the amount of total net exposure and rolling net exposure during the stated NOTE 15. DECOMMISSIONING TRUST FUNDS periods. These policies, including related risk limits, are regularly Entergy holds debt and equity securities, classified as available-for-assessed to ensure their appropriateness given Entergy's objectives. sale, in nuclear decommissioning trust accounts. The securities held at December 31, 2004 and 2003 are summarized as follows Hedging Derivatives (in millions): Entergy classifies substantially all of the following types of Total Total derivative instruments held by its consolidated businesses as Unrealized Unrealized 2004 Fair Value Gains Losses cash flow hedges: Equity S 995 $166 $17 Business Segment Debt Securities 1,457 33 6 Instrument Non-Utility Nuclear, Total 52,452 $199 $23 Natural gas and electricity futures and forwards Energy Commodity Services, Competitive Retail Services 2003 Equity S 896 S 81 $11 Foreign currency forwards U.S. Utility, Non-Utility Nuclear Debt Securities 1,383 27 3 Total 52,279 S108 $14 Cash flow hedges with net unrealized losses of approximately
$99 million at December 31, 2004 are scheduled to mature during The fair value and gross unrealized losses of available-for-sale 2005. Net losses totaling approximately $13 million were realized equity and debt securities, summarized by investment type and during 2004 on the maturity of cash flow hedges. Unrealized gains length of time that the securities have been in a continuous loss or losses result from hedging power output at the Non-Utility position, are as follows at December 31, 2004 (in millions):
Nuclear power stations and foreign currency hedges related to Euro-denominated nuclear fuel acquisitions. The related gains or Equity Securities Debt Securities losses from hedging power are included in revenues when realized. Gross Gross Unrealized Unrealized The realized gains or losses from foreign currency transactions are Fair Value Losses Fair Value Loss es included in the cost of capitalized fuel. The maximum length of Less than 12 months S 29 S2 $334 time over which Entergy is currently hedging the variability in More than 12 months 115 15 37 1 future cash flows for forecasted transactions at December 31, 2004 Total 5144 517 $371 $6 is approximately four years. The ineffective portion of the change in the value of Entergy's cash flow hedges during 2004 was insignificant. Entergy Corporation and Subsidiaries 2004 NOTES to CONSOLIDATED FINANCIAL STATEMENTS concluded -J Entergy evaluates these unrealized gains and losses at the end of NOTE 16. QUARTERLY FINANCIAL DATA each period to determine whether an other-than-temporary (UNAUDITED) impairment has occurred. This analysis considers the length of time Operating results for the four quarters of 2004 and 2003 were that a security has been in a loss position, the current performance (in thousands): Net of that security, and whether decommissioning costs are recovered Operating Operating Income in rates. Due to the regulatory treatment of decommissioning Revenues Income (Loss) collections and trust fund earnings, Entergy Arkansas, Entergy 2004 Gulf States, Entergy Louisiana, and System Energy record First Quarter $2,251,549 $378,834 $213,016 regulatory assets or liabilities for unrealized gains and losses on trust Second Quarter $2,485,097 $494,312 $271,011 investments. For the unregulated portion of River Bend, Entergy Third Quarter $2,963,581 $571,472 $288,047 Gulf States has recorded an offsetting amount of unrealized gains Fourth Quarter $2,423,497 $208,946 $160,975 2003 or losses in other deferred credits. No significant impairments were First Quarter S2,037,723 $363,403 S400,923"' recorded in 2004 and 2003 as a result of these evaluations. Second Quarter $2,353,909 $461,576 $211,517 The fair value of debt securities, summarized by contractual Third Quarter S2,700,125 S619,005 $371,650 maturities, at December 31, 2004 is as follows (in millions): Fourth Quarter $2,103,163 S 40,571 S (33,623) (a) Net income before the cumulative effect ofaccounting changesfor thefirst Fair Value quarterof2003 was *258,001. Less than 1 year $ 134 1 year - 5 years 592 EARNINGS PER AVERAGE COMMON SHARE 5 years - 10 years 425 10 years - 15 years 158 2004 2003 15 years - 20 years 60 Basic Diluted Basic Diluted 20 years + 88 First Quarter $0.90 $0.88 $ 1.77r') S 1.73(b) Total $1,457 Second Quarter $1.16 $1.14 $ 0.91 S 0.89 Third Quarter $1.24 $1.22 S 1.60 S 1.57 During the year ended December 31, 2004, the proceeds from Fourth Quarter $0.71 $0.69 S(0.19) 5(0.18) the dispositions of securities amounted to $37 million with gross (b) Basic and diluted earnings per average common share before the cumulative gains of $0.7 million and gross losses of $0.7 million, which were effect of accounting changesfor thefirst quarter of 2003 were *1.13 and reclassified out of other comprehensive income into earnings during *1.10, respectively. the period.
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Entergy Corporation and Subsidiaries 2004 INVESTOR INFORMATION ,2I AN-The 2005 Annual Meeting of Shareholders will be held on Friday, DIVIDEND PAYMENTS May 13, at The Peabody Hotel, Three Statehouse Plaza, Little The entire amount of dividends paid during 2004 is taxable as Rock, Arkansas. The meeting will begin at 10 a.m. (CDT). ordinary income. The Board of Directors declares dividends quarterly and sets the record and payment dates. Subject to Board SHAREHOLDER NEWS discretion, those dates for 2005 are: Entergy's quarterly earnings results, dividend action, and other news and information of investor interest may be obtained by calling Declaration Date Record Date Payment Date Entergy Shareholder Direct at 1-888-ENTERGY (368-3749). January28 February11 Marchi You may also use this service to receive a printed copy of the April 12 May 12 June 1 quarterly earnings release by fax or mail. Updated quarterly July 29 August 12 September 1 earnings results can be expected in late January, April, July, and October 28 November 10 December 1 October. Dividend information will be updated according to the declaration schedule. Quarterly dividend payments (in cents-per-share): This and other information, including Entergy's Corporate Quarter 2005 2004 2003 2002 2001 Governance Guidelines, Board Committee Charters for the 1 54 45 35 33 31% Corporate Governance, Audit, and Personnel Committees, and 2 45 35 33 31% Entergy's Code of Conduct is available on Entergy's home page on 3 45 45 33 31% the internet at wwvwventergycom. 4 54 45 35 33 For copies of the above and copies of Entergy's 10-K and 10-Q reports filed with the Securities and Exchange Commission or for other investor information, call 1-800-292-9960 or write to: DIVIDEND REINVESTMENT/STOCK PURCHASE Entergy Corporation Entergy offers an automatic Dividend Reinvestment and Stock Investor Relations Purchase Plan administered by Mellon Investor Services. The plan P.O. Box 61000 is designed to provide Entergy shareholders and other investors New Orleans, LA 70161 with a convenient and economical method to purchase shares of the Securities analysts and representatives of financial institutions company's common stock. The plan also accommodates payments may contact Michele Lopiccolo at 504-576-4879 or of up to $3,000 per month for the purchase of Entergy common mlopicc@entergy.com. shares. First-time investors may make an initial minimum purchase SHAREHOLDER ACCOUNT INFORMATION of $1,000. Contact Mellon by telephone or internet for information and an enrollment form. Mellon Investor Services, LLC is Entergy's transfer agent, registrar, dividend disbursing agent, and dividend reinvestment and stock DIRECT REGISTRATION SYSTEM purchase plan agent. Shareholders of record with questions about Entergy has elected to participate in a Direct Registration System lost certificates, lost or missing dividend checks, or notifications of that provides investors with an alternative method for holding change of address should contact. shares. DRS will permit investors to move shares between the Mellon Investor Services company's records and the broker dealer of their choice. 85 Challenger Road This option, available to every shareholder who chooses to have Ridgefield Park, NJ 07660 shares registered in his or her name on the books of the company, Telephone: 1-800-333-4368 will be offered by broker dealers at the time an investor purchases Internet address: www.melloninvestor.com shares and requests that they be registered. An additional feature of DRS enables existing registered holders to deposit physical shares COMMON STOCK INFORMATION into a book account. The company's common stock is listed on the New York, Chicago, and Pacific exchanges under the symbol 'ETR." The Entergy share ENTERGY COMIMON STOCK PRICES price is reported daily in the financial press under 'Entergy" in most The high and low trading prices for each quarterly period in 2004 listings of New York Stock Exchange securities. Entergy common and 2003 were as follows (in dollars): stock is a component of the following indices: S&P 500, S&P Utilities Index, and the NYSE Composite Index, among others. 2004 2003 In June 2004, Entergy's Chief Executive Officer certified to the Quarter High Low High Low New York Stock Exchange that he was not aware of any 1 60.20 56.01 49.55 42.26 violation of the NYSE corporate governance listing standards. Also, 2 59.92 50.64 54.38 45.90 Entergy filed certifications regarding the quality of the company's 3 61.98 54.43 54.99 47.75 public disclosure, required by Section 302 of the Sarbanes-Oxley 4 68.67 60.08 57.24 51.06 Act of 2002, as exhibits to its Report on Form 10-K for the fiscal year ended December 31, 2004. ENVIRONMENTAL INFORMATION At year-end 2004 there were 216,829,059 shares of Entergy Entergy's Sustainability Report and other information on Entergy's common stock outstanding. Shareholders of record totaled 51,572, environmental policy is available on Entergy's home page and approximately 81,000 investors held Entergy stock in 'street at www.entergy.com. name" through a broker. 87 -
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Entergy Corporation and Subsidiaries 2004 DIRECTORS and OFFICERS -I K DIRECTORS Maureen S. Bateman Bismark A. Steinhagen Partner, Holland & Knight, Boston, Massachusetts. An Entergy Chairman of the Board of Steinhagen Oil Company, Inc., director since 2000. Age, 61 Beaumont, Texas. An Entergy director since 1993. Age, 70 W.Frank Blount Steven V.Wilkinson Chairman and Chief Executive Officer, JI Ventures, Inc., Retired Audit Partner, Arthur Andersen LLP, Watersmeet, TTS Management Corp., Atlanta, Georgia. An Entergy Michigan. An Entergy director since 2003. Age, 63 director since 1987. Age, 66 Simon D.deBree OFFICERS Retired Director and Chief Executive Officer of DSM, The Netherlands. An Entergy director since 2001. Age, 67 J. Wayne Leonard Chief Executive Officer. Joined Entergy in 1998 as President and Claiborne P.Deming Chief Operating Officer, appointed CEO on January 1, 1999. President and Chief Executive Officer and Director of Murphy Oil Former executive of Cinergy. Age, 54 Corporation, El Dorado, Arkansas. An Entergy director since 2002. Age, 50 Leo P. Denault Executive Vice President and Chief Financial Officer. Joined Entergy Alexis Herman in 1999 as Vice President of corporate development. Former Vice Chair and Chief Executive Officer of New Ventures, Inc., President of Cinergy. Age, 45 McLean, Virginia. An Entergy director since 2003. Age, 57 Richard J. Smith Donald C. Hintz Group President, Utility Operations. Joined Entergy in 2000. Former President, Entergy Corporation, Punta Gorda, Florida. Former President of Cinergy Resources, Inc. Age, 53 Joined the Entergy Board in 2004. Age, 61 Curtis L. HFbert J. Wayne Leonard Executive Vice President, External Affairs. Joined Entergy in 2001. Entergy Chief Executive Officer. Joined Entergy in April 1998 as Former Chairman of the Federal Energy Regulatory Commission. President and Chief Operating Officer; appointed CEO and elected Age, 42 to the Board of Directors on January 1, 1999. New Orleans, Louisiana. Age, 54 Mark T. Savoff Executive Vice President, Operations. Joined Entergy in 2003. Robert v.d. Luft Former President, General Electric Power Systems - GE Nuclear Entergy Chairman. Member of Entergy Board of Directors since Energy. Age, 48 1992; elected Chairman of the Board on May 26, 1998. Also served as acting CEO from May 26 until December 31, 1998. Chadds Ford, Robert D.Sloan Pennsylvania. Age, 69 Executive Vice President, General Counsel and Secretary. Joined Entergy in 2003. Former Vice President and General Counsel at Kathleen A. Murphy GE Industrial Systems. Age, 57 Former Senior Vice President and Chief Financial Officer, Connell Limited Partnership, Stamford, Connecticut. An Entergy director Gary J. Taylor since 2000. Age, 54 Executive Vice President and Chief Nuclear Officer. Joined Entergy in 2000. Former Vice President of nuclear operations at South Paul W.Murrill Carolina Electric & Gas Company. Age, 51 Professional Engineer, Baton Rouge, Louisiana. An Entergy director since 1993. Age, 70 Joseph T. Henderson Senior Vice President and General Tax Counsel. Joined Entergy in James R. Nichols 1999. Former Associate General Tax Counsel for Shell Oil. Age, 47 Partner, Nichols & Pratt (family trustees), Attorney and Chartered Financial Analyst, Boston, Massachusetts. An Entergy director since Nathan E. Langston 1986. Age, 66 Senior Vice President and Chief Accounting Officer. Joined Entergy in 1971 and advanced through various accounting and finance William A. Percy, 11 positions before being promoted to VP & CAO in 1998. Age, 56 Chairman and Chief Executive Officer of Greenville Compress Company, Greenville, Mississippi. An Entergy director since 2000. William E. Madison Age, 65 Senior Vice President, Human Resources and Administration. Joined Entergy in 2001. Former Senior Vice President for Dennis H.Reilley Avis Group Holdings, Inc. Age, 58 Chairman, President and Chief Executive Officer of PRAXAIR, Inc., II Danbury, Connecticut. An Entergy director since 1999. Age, 51 Steven C. McNeal Vice President and Treasurer. Joined Entergy in 1982 as a financial Wm. Clifford Smith analyst and was given increased responsibility in areas of finance, Chairman of the Board of T. Baker Smith & Son, Inc., treasury, and risk management before being promoted to VP & Houma, Louisiana. An Entergy director since 1983. Age, 69 Treasurer in 1998. Age, 48 Entergy Corporation and Subsidiaries 2004 DIRECTORS aI . Maureen S. Bateman W. Frank Blount Simon D. deBree Claiborne P. Deming Alexis Herman Donald C. Hintz J. Wayne Leonard Robert v.d. Luft Kathleen A. Murphy Paul W. Murrill James R. Nichols William A. Percy, 11 W=- i 11 I I 11 i I o I Dennis H. Reilley Wm. Clifford Smith Bismark A. Steinhagen Steven V. Wilkinson With a wealth of experience and talent, our Board of Directors provides steady guidance for our company ensuring our corporate governance is strong and our strategic direction is clear. The business and affairs of Entergy Corporation are managed under the direction of the Board of Directors, acting either as a body or through its committees. In 2004, the Board met 11 times. The Board committees are as follows (number of meetings in 2004 indicated in parentheses): Audit (10), Corporate Governance (6), Executive (1), Finance (6), Nuclear (7), Personnel (7). I h ENTERGY CORPORATION POST OFFICE BOX 61000 NEW ORLEANS, LA 70161 WWW.ENTERGY.COM Entergy I IinmLr I I - I
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 2004 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission Registrant, State of Incorporation, IRS Employer File Number Address of Principal Executive Offices and Telephone Number Identification No. 1-11299 ENTERGY CORPORATION 72-1229752 (a Delaware corporation) 639 Loyola Avenue New Orleans, Louisiana 70113 Telephone (504) 576-4000 1-10764 ENTERGY ARKANSAS, INC. 71-0005900 (an Arkansas corporation) 425 West Capitol Avenue Little Rock, Arkansas 72201 Telephone (501) 377-4000 1-27031 ENTERGY GULF STATES, INC. 74-0662730 (a Texas corporation) 350 Pine Street Beaumont, Texas 77701 Telephone (409) 838-6631 1-8474 ENTERGY LOUISIANA, INC. 72-0245590 (a Louisiana corporation) 4809 Jefferson Highway Jefferson, Louisiana 70121 Telephone (504) 840-2734 1-31508 ENTERGY MISSISSIPPI, INC. 64-0205830 (a Mississippi corporation) 308 East Pearl Street Jackson, Mississippi 39201 Telephone (601) 368-5000 0-5807 ENTERGY NEW ORLEANS, INC. 72-0273040 (a Louisiana corporation) 1600 Perdido Street, Building 505 New Orleans, Louisiana 70112 Telephone (504) 670-3674 1-9067 SYSTEM ENERGY RESOURCES, INC. 72-0752777 (an Arkansas corporation) Echelon One 1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 368-5000
Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange Registrant Title of Class on Which Registered Entergy Corporation Common Stock, $0.01 Par Value - 213,145,161 New York Stock Exchange, Inc.
- 1. shares outstanding at February 28, 2005 Chicago Stock Exchange Inc.
Pacific Exchange Inc. Entergy Arkansas, Inc. Mortgage Bonds, 6.7% Series due April 2032 New York Stock Exchange, Inc. Mortgage Bonds, 6.0% Series due November 2032 New York Stock Exchange, Inc. Entergy Gulf States, Inc. Preferred Stock, Cumulative, $100 Par Value:
$4.40 Dividend Series New York Stock Exchange, Inc.
$4.52 Dividend Series New York Stock Exchange, Inc.
$5.08 Dividend Series New York Stock Exchange, Inc.
Adjustable Rate Series B (Depository Receipts) New York Stock Exchange, Inc. Entergy Gulf States Capital I 8.75% Cumulative Quarterly Income Preferred New York Stock Exchange, Inc. Securities, Series A (guaranteed by Entergy Gulf States, Inc.) Entergy Louisiana, Inc. Mortgage Bonds, 7.6% Series due April 2032 New York Stock Exchange, Inc. Entergy Mississippi, Inc. Mortgage Bonds, 6.0% Series due November 2032 New York Stock Exchange, Inc. Mortgage Bonds, 7.25% Series due December 2032 New York Stock Exchange, Inc. Securities registered pursuant to Section 12(g) of the Act: Registrant Title of Class Entergy Arkansas, Inc. Preferred Stock, Cumulative, $100 Par Value Preferred Stock, Cumulative, $0.01 Par Value Entergy Gulf States, Inc. Preferred Stock, Cumulative, $100 Par Value Entergy Louisiana, Inc. Preferred Stock, Cumulative, $100 Par Value Preferred Stock, Cumulative, $25 Par Value Entergy Mississippi, Inc. Preferred Stock, Cumulative, $100 Par Value Entergy New Orleans, Inc. Preferred Stock, Cumulative, $100 Par Value
Indicate by check mark whether the registrants (1) have filed all reports tequired to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes 4 No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [4] Indicate by check mark whether the registrant is an accelerated filer. (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
, . 1 Yes No Entergy Corporation Entergy Arkansas, Inc. 4 Entergy Gulf States, Inc. -
Entergy Louisiana, Inc. 4 Entergy Mississippi, Inc. 4 Entergy New Orleans, Inc. 4 System Energy Resources, Inc. i The aggregate market value of Entergy Corporation Common Stock, $0.01 Par Value, held by non-affiliates as of the end of the second quarter of 2004, was $12.7 billion based on the reported last sale price of $56.01 per share for such stock on the New York Stock Exchange on June 30, 2004. Entergy Corporation is the sole holder of the common stock of Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., and System Energy Resources, Inc. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders, to be held May 13, 2005, are incorporated by reference into Parts I and III hereof.
TABLE OF CONTENTS SEC Form 10-K Page Reference Number Number Definitions . i Entergy's Business , Part I. Item 1. 1 Financial Information for U.S. Utility, Non-Utility Nuclear, and Energy 2 Commodity Services Strategy - 3 Report of Management 4 Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Part II. Item 7. Results of.Operations. . 5 Liquidity and Capital Resources 12 Significant Factors and Known Trends 22 Critical Accounting Estimates .33 Selected Financial Data - Five-Year Comparison Part II. Item 6. 41 Report of Independent Registered Public Accounting Firm 42 Consolidated Statements of Income For the Years Ended December 31, 2004, Part II. Item 8. 43 2003, and 2002 Consolidated Statements of Cash Flows For the Years Ended December 31, Part II. Item 8. 44 2004, 2003, and 2002 1 Consolidated.Balance Sheets, December 31, 2004 and 2003 Part II. Item 8. :46 Consolidated Statements of Retained Earnings, Comprehensive Income, and Part II. Item 8. 48 Paid in Capital for the Years Ended December 31, 2004, 2003, and 2002 Notes to Consolidated Financial Statements . Part II. IItem 8. 49 U.S. Utility ' Part I. It,em1. 105 Customers 105 Electric Energy Sales 105 Retail Rate Regulation *: 107 Property and Other Generation Resources 113 Fuel Supply 116 Federal Regulation 119 Service Companies 128 Earnings Ratios 128 Non-Utility Nuclear *.Part I. It em 1. 129 Property 129 Energy and Capacity Sales 129 Fuel Supply 130 Other Business Activities 131 Energy Commodity Services Part I. It em 1. 131 Non-Nuclear Wholesale Assets Business 132 Entergy-Koch, LP. 132 Regulation of Entergy's Business Part I. It em l.. 133 PUHCA 133 Federal Power Act * -133 State Regulation 134 Regulation of the Nuclear Power Industry 135 Environmental Regulation .: 137 Litigation 142 Research Spending 146 Employees 146
Entergy Arkansas, Inc. Management's Financial Discussion and Analysis Part II. Item 7. Results of Operations 147 Liquidity and Capital Resources 147 Significant Factors and Known Trends 150 Critical Accounting Estimates 154 Report of Independent Registered Public Accounting Firm 164 Income Statements For the Years Ended December 31, 2004, 2003, and 2002 Part II. Item 8. 165 Statements of Cash Flows For the Years Ended December 31, 2004, 2003, Part II. Item 8. 167 and 2002 Balance Sheets, December 31, 2004 and 2003 Part II. Item 8. 168 Statements of Retained Earnings for the Years Ended December 31, 2004, Part II. Item 8. 170 2003, and 2002 Selected Financial Data - Five-Year Comparison Part II. Item 6. 171 Entergy Gulf States, Inc. Management's Financial Discussion and Analysis Part II. Item 7. Results of Operations 172 Liquidity and Capital Resources 176 Significant Factors and Known Trends 179 Critical Accounting Estimates 188 Report of Independent Registered Public Accounting Firm 193 Income Statements For the Years Ended December 31, 2004, 2003, and 2002 Part
, I Item 8. 194 Statements of Cash Flows For the Years Ended December 31, 2004, 2003, Part II. Item 8. 195 and 2002 Part II. Item 8.
Balance Sheets, December 31, 2004 and 2003
- 196 Statements of Retained Earnings and Comprehensive Income for the Years Part H. Item 8. 198 Ended December 31, 2004, 2003, and 2002 Selected Financial Data - Five-Year Comparison Part II. Item 6. 199 Entergy Louisiana, Inc.
Management's Financial Discussion and Analysis Part II. Item 7. Results of Operations 200 Liquidity and Capital Resources 203 Significant Factors and Known Trends
- 207 Critical Accounting Estimates 213 Report of Independent Registered Public Accounting Firm 218 Income Statements For the Years Ended December 31, 2004, 2003, and 2002 Part II. Item 8. 219 Statements of Cash Flows For the Years Ended December 31, 2004, 2003, Partil. Item 8. 221 and 2002 Balance Sheets, December 31, 2004 and 2003 Part II. Item 8. 222 Statements of Retained Earnings for the Years Ended December 31, 2004, Part II. Item 8. 224 2003, and 2002 Selected Financial Data - Five-Year Comparison Part II. Item 6. 225 Entergy Mississippi, Inc.'
Management's Financial Discussion and Analysis Part II. Item 7. Results of Operations 226 Liquidity and Capital Resources 228 Significant Factors and Known Trends .231 Critical Accounting Estimates 236 Report of Independent Registered Public Accounting Firm 239 Income Statements For the Years Ended December 31, 2004, 2003, and 2002 Part II. Item 8. 240 Statements of Cash Flows For the Years Ended December 31, 2004, 2003, Part II. Item 8. 241 and 2002 Balance Sheets, December 31, 2004 and 2003 Part II. Item 8. 242 Statements of Retained Earnings for the Years Ended December 31, 2004, Part II. Item 8. 244 2003, and 2002 Selected Financial Data - Five-Year Comparison Part II. Item 6. 245
Entergy New Orleans, Inc. Management's Financial Discussion and Analysis Part II. Item 7. Results of Operations 246 Liquidity and Capital Resources Significant Factors and Known Trends . 251 Critical Accounting Estimates , , ,. 257 Report of Independent Registered Public Accounting Firm 260 Statements of Operations For the Years Ended December 31, 2004, 2003, and Part II. Item 8. 261 2002 , Statements of Cash Flows For the Years Ended December 31, 2004, 2003, Part H.Item, -,263
,and 2002 Balance Sheets, December 31, 2004 and 2003 Part JI, Item 8.
- 264, 4 Statements of Retained Earnings for the Years Ended December 31, 2004, Part II. Item 8; 266i..
2003, and 2002 26. 7 Selected Financial Data - Five-Year Comparison Part II. Item 6. 267 System Energy Resources, Inc. Management's Financial Discussion and Analysis Part II. Item 7. Results of Operations 268 Liquidity and Capital Resources 268 Significant Factors and Known Trends 271 Critical Accounting Estimates 272 Report of Independent Registered Public Accounting Firm 276 Income Statements For the Years Ended December 31, 2004, 2003, and 2002 Part II. Item 8. 277 Statements of Cash Flows For the Years Ended December 31, 2004, 2003, Part II. Item 8. 279 and 2002 Balance Sheets, December 31, 2004 and 2003 Part II. Item 8. 280 Statements of Retained Earnings for the Years Ended December 31, 2004, Part II. Item 8. 282 2003, and 2002 Selected Financial Data - Five-Year Comparison Part II. Item 6. 283 Notes to Respective Financial Statements for the Domestic Utility Companies Part II. Item 8. 284 and System Energy Properties Part I. Item 2. 349 Legal Proceedings Part I. Item 3. 349 Submission of Matters to a Vote of Security Holders Part I. Item 4. 349 Directors and Executive Officers of Entergy Corporation Part III. Item 10. 349 Market for Registrants' Common Equity and Related Stockholder Matters Part II. Item 5. 351 Selected Financial Data Part II. Item 6. 352 Management's Discussion and Analysis of Financial Condition and Results of Part II. Item 7. 352 Operations Quantitative and Qualitative Disclosures About Market Risk Part II. Item 7A. 352 Financial Statements and Supplementary Data Part II. Item 8. 353 Changes in and Disagreements with Accountants on Accounting and Financial Part II. Item 9. 353 Disclosure Controls and Procedures Part II. Item 9A. 353 Attestation Report of Registered Public Accounting Firm Part II. Item 9A. 354 Other Information Part II. Item 9B. 368 Directors and Executive Officers of the Registrants Part III. Item 10. 369 Executive Compensation Part III. Item 11. 373 Security Ownership of Certain Beneficial Owners and Management Part III. Item 12. 383 Certain Relationships and Related Transactions Part III. Item 13. 386 Principal Accountant Fees and Services Part IV. Item 14 387 Exhibits, Financial Statement Schedules, and Reports on Form 8-K Part IV. Item 15. 390 Signatures 391 Consent of Independent Registered Public Accounting Firm 398 Report of Independent Registered Public Accounting Firm 400 Index to Financial Statement Schedules S-1 Exhibit Index E-1
This combined Form 10-K is separately filed by Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., and System Energy Resources, Inc. Information contained herein relating to any Individual company is filed by such company on Its own behalf. Each company makes representations only as to itself and makes no other representations whatsoever as to any other company. The report should be read in its entirety as it pertains to each respective registrant. No one section of the report deals with all aspects of the subject matter. Separate Item 6, 7, and 8 sections are provided for each registrant, except for the Notes to the financial statements. The Entergy Corporation Notes to the financial statements are separately presented, but the Notes to the financial statements for the other registrants are combined. These two sets of Notes are marked by headers. All other Items are combined for the registrants.
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FORWARD-LOOKING INFORMATION In this filing and from time to time, Entergy makes statements concerning its expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Although Entergy believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in the statements. Some of those factors (in addition to others described elsewhere in this report and in subsequent securities filings) include:
- resolution of pending and future rate cases and negotiations, including various performance-based rate discussions, and other regulatory proceedings, including those related to Entergy's System Agreement and Entergy's utility supply plan i
- Entergy's ability to manage its operation and maintenance costs, particularly at its Non-Utility Nuclear generating facilities
- the performance of Entergy's generating plants, and particularly the capacity factors at its nuclear generating facilities
- prices for power generated by Entergy's unregulated generating facilities, the ability to extend or replace the existing purchased power agreements for those facilities, including the Non-Utility Nuclear plants, and the prices and availability of power Entergy must purchase for its utility customers
- Entergy's ability to develop and execute on a point of view regarding prices of electricity, natural gas, and other energy-related commodities
- changes in the financial markets, particularly those affecting the availability of capital and Entergy's ability to refinance existing debt, execute its share repurchase program, and fund investments and acquisitions
- actions of rating agencies, including changes in the ratings of debt and preferred stock, and changes in the rating agencies' ratings criteria
- changes in inflation and interest rates
- Entergy's ability to purchase and sell assets at attractive prices and on other attractive terms
- volatility and changes in markets for electricity, natural gas, uranium, and other energy-related commodities
- changes in utility regulation, including the beginning or end of retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, the establishment of a regional transmission organization that includes Entergy's utility service territory, and the application of market power criteria by the FERC
- changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown of Indian Point or other nuclear generating facilities -
- uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel storage and disposal
- resolution of pending or future applications for license extensions or modifications of nuclear generating facilities
- changes in law resulting from proposed energy legislation
- changes in environmental, tax, and other laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, mercury, and other substances
- the economic climate, and particularly growth in Entergy's service territory
- variations in weather and the occurrence of hurricanes and other storms and disasters
- advances in technology
- the potential effects of threatened or actual terrorism and war
- the effects of Entergy's strategies to reduce current tax payments
- the effects of litigation and government investigations
- changes in accounting standards, corporate governance, and securities law requirements
- Entergy's ability to attract and retain talented management and directors
DEFINITIONS., . Certain abbreviations or acronyms used in the text1lnd n6tes are defined below:
, Term, Abbreviation or Acronym -? . Term "
AFUDC Allowance for Funds Used During Construction ALJ Administrative Law Judge A'NO 1 and2 Units '1' and' 2 of Arkansas"'Nuclear One Steam' Electric Generating Station i (nuclear), owned by Entergy'Aikansas APSC Arkansas Public Service Comm ission' - Board. - Board of Directors of Entergy Corporation. Cajun . Cajun Electric-Power Cooperative, Inc.;-I capacity factor Actual plant output divided by maximum potential plant output for the period City Council or Council Council of the City of New Orleans, Louisiana! CPI-U Consumer Price Index - Urban DOE United States Department of Energy domestic utility companies Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, collectively EITF FASB's Emerging Issues Task Force. Energy Commodity Services, Entergy's business segment that includes Entergy-Koch, LP and Entergy's non-nuclear wholesale assets business Entergy Entergy Corporation and its direct and indirect subsidiaries Entergy Corporation . Entergy Corporation, a Delaware corporation Entergy-Koch Entergy-Koch, LP, a joint. venture equally owned by subsidiaries of Entergy and Koch Industries, Inc. EPA United States Environmental Protection Agency EPDC Entergy Power Development Corporation, a wholly-owned subsidiary of Entergy Corporation FASB Financial Accounting Standards Board FEMA i Federal Emnergency Management Agency FERC Federal En'erg' Regulator'y'Commission firm liquidated damrages Transactioni that requires receipt or delivery of energy at a specified delivery point (usually at a market hib not associated with a specific asset); if a party fails to deliver or receive energy, the defaulting party must compensate the other party as specified in tlhe contract - ! FSP FASB Staff Position Grand Gulf Unit No. I of Grand Gulf Steam Electric Generating Station (nuclear), 90% owned or leased by System Energy GWh ' Gigawatt-hour(s); which equals one million kilowatt-hours Independence Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi; and 7% by Entergy Power - IRS . - Intemal Revenue Service ISO Independent System Operator kV Kilovolt ; . . . . , kW Kilowatt, kWh Kilowatt-hour(s) (I Ior .ji. I.-, A -'1. i
DEFINITIONS (Continued) Abbreviation or Acronym Term LDEQ Louisiana Department of Environmental Quality LPSC Louisiana Public Service Commission Mcf 1,000 cubic feet of gas MMBtu One million British Thermal Units MPSC Mississippi Public Service Commission MW Megawatt(s), which equals one thousand kilowatt(s) MWh Megawatt-hour(s) Nelson Unit 6 Unit No. 6 (coal) of the Nelson Steam Electric Generating Station, owned 70% by Entergy Gulf States Net debt ratio Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents Net MW in operation Installed capacity owned or operated Net revenue Operating revenue net of fuel, fuel-related, and purchased power expenses; and other regulatory credits Non-Utility Nuclear Entergy's business segment that owns and operates five nuclear power plants and sells electric power produced by those plants to wholesale customers NRC Nuclear Regulatory Commission NYPA New York Power Authority PPA Purchased power agreement production cost Cost in $IMMBtu associated with delivering gas, excluding the cost of the gas PRP Potentially responsible party (a person or entity that may be responsible' for remediation of environmental contamination) PUCT Public Utility Commission of Texas PUHCA Public Utility Holding Company Act of 1935, as amended PURPA Public Utility Regulatory Policies Act of 1978 Ritchie Unit 2 Unit 2 of the R.E. Ritchie Steam Electric Generating Station (gas/oil) River Bend River Bend Steam Electric Generating Station (nuclear), owned by Entergy Gulf States SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards as promulgated by the FASB SMEPA South Mississippi Electric Power Agency, which owns a 10% interest in Grand Gulf spark spread Dollar difference between electricity prices per unit and natural gas prices after assuming a conversion ratio for the number of natural gas units necessary to generate one unit of electricity System Agreement Agreement, effective January 1, 1983, as modified, among the domestic utility companies relating to the sharing of generating capacity and other power resources System Energy System Energy Resources, Inc. System Fuels System Fuels, Inc. ii
DEFINITIONS (Concluded) Abbreviation or Acronym Term TWh Terawatt-hour(s), which. equals one billion kilowatt-hours ' unit-contingent Transaction under which, power is supplied from a specific generation asset; if the specified generation asset is unavailable as a result of forced outage 'or unanticipated event or circumstance, the: seller is not liable to the buyer for any damages resulting from the selldes failure to deliver power : unit-contingent with Transaction under which power is supplied from a specific generation asset; if the availability guarantees specified generation asset is unavailable as a result of forced outage 'or unanticipated event or circumstance, the seller is not liable to the buyer for any damages resulting from the seller's failure to deliver power unless the actual availability, over a specified period of time is below an availability threshold specified in the contract Unit Power Sales Agreement Agreement, dated as of June 10, 1982, as amended and approved by FERC, among Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, relating to. the, sale of capacity and energy from System Energy's share of Grand Gulf UK The United Kingdom of Great Britain and Northern Ireland U.S. Utility Entergy's business segment that generates,, transmits, distributes, and sells electric power, with a small amount of natural gas distribution Waterford 3 Unit No. 3 (nuclear) of the Waterford Steam Electric Generating Station, 100% owned or leased by Entergy Louisiana weather-adjusted usage Electric usage excluding the effects of deviations from normal weather White Bluff White Bluff Steam Electric Generating Station, 57% owned by Entergy Arkansas
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ENTERGY'S BUSINESS Entergy Corporation is an integrated energy company engaged primarily in electric power production and retail electric distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of electric generating capacity, and it is the second-largest nuclear power generator in the United States. Entergy delivers electricity to 2.7 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy generated annual revenues of over $10 billion in 2004 and had approximately 14,400 employees as of December 31, 2004. Entergy operates primarily through three business segments: U.S. Utility, Non-Utility Nuclear, and Energy Commodity Services.
- U.S. Utility generates, transmits, distributes, and sells electric power in a four-state service territory that includes portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operates a small natural gas distribution business.
- Non-Utility Nuclear owns and operates five nuclear power plants located in the northeastern United States and sells the electric power produced by those plants to wholesale customers. This business also provides services to other nuclear power plant owners.
- Energy Commodity Services includes Entergy-Koch and Entergy's non-nuclear wholesale assets business.
Entergy-Koch engaged in two major businesses: energy commodity marketing and trading through Entergy-Koch Trading, and gas transportation and storage through Gulf South Pipeline. Entergy-Koch sold both of these businesses in the fourth quarter of 2004, and Entergy-Koch is no longer an operating entity. The non-nuclear wholesale assets business sells to wholesale customers the electric power produced by power plants that it owns while it focuses on improving performance and exploring sales or restructuring opportunities for its power plants. Such opportunities are evaluated consistent with Entergy's market-based point-of-view. The non-nuclear wholesale assets business terminated new greenfield power development activity in 2002. I
OPERATING INFORMATION For the Years Ended December 31, 2004, 2003, and 2002 Energy Non-Utility Commodity Entergy U.S. Utility Nuclear Services Consolidated (a) (In Thousands) 2004 Operating revenues $8,142,808 $1,341,852 $216,450 $10,123,724 Operating expenses $6,795,146 $978,688 $308,226 $8,470,160 Other income $108,925 $78,141 ($44,727) $124,416 Interest and other charges $383,032 $53,657 $15,560 $479,023 Income taxes $406,864 $142,620 ($155,840) $365,908 Net income $666,691 $245,029 $3,778 $933,049 2003 Operating revenues $7,584,857 $1,274,983 $184,888 $9,194,920 Operating expenses $6,274,830 $1,039,614 $224,567 $7,710,365 Other income ($35,965) $33,997 S337,334 $325,238 Interest and other charges $419,111. $34,460 $15,193 $506,326 Income taxes $341,044 $88,619 $105,903 $490,074 Cumulative effect of accounting change ($21,333) $154,512 $3,895 $137,074 Net income S492,574 $300,799 $180,454 $950,467 2002 Operating revenues $6,773,509 $1,200,238 $294,670 $8,305,035 Operating expenses $5,434,694 $868,288 $769,834 $7,163,314 Other income $47,603 $48,572 $249,678 $347,753 Interest and other charges S465,703 ' $47,291 $61,632. $572,464 Income taxes $313,752 $132,726 ($141,288) $293,938 Net income (loss) $606,963 $200,505 ($145,830) $623,072 CASH FLOW INFORMATION For the Years Ended December 31, 2004, 2003, and 2002 Energy
- Non-Utility Commodity Entergy U.S. Utility _ Nuclear Services Consolidated (a)
II (in Thousands) 2004 Net cash flow provided by operating activities $2,207,876 S414,518 $479,91! 9 $2,929,319 Net cash flow provided by (used in) investing activities ($1,198,009) ($386,023) $248,61, 2 ($1,140,075) Net cash flow used in financing activities ($824,579) ($37,894) ($724,53' 4) ($1,671,859) 2003 Net cash flow provided by (used in) operating activities $1,675,069 $182,524 ($111,291) $2,005,820 Net cash flow used in investing activities ($l,441,992) ($184,913) ($78,120) ($1,783,130) Net cash flow provided by (used in) financing activities ($919,983) ($6,672) $166,165 ($869,130) 2002 Net cash flow provided by (used in) operating activities S2,341,161 $281,589 ($3,714) $2,181,703 Net cash flow used in investing activities (S1,020,087) (S438,664) ($760) ($1,388,463) Net cash flow provided by (used in) financing activities ($688,201) $176,162 ($66,151) ($212,610) FINANCIAL POSITION INFORMATION As of December 31, 2004 and 2003 Energy Non-Utility Commodity Entergy U.S. Utility Nuclear Services Consolidated (a) (In Thousands) 2004 Current assets $2,323,801 $590,580 $1,282,578 $3,108,118 Other property and investments $1,200,246 $1,403,222 $569,975 $2,995,894 Property, plant and equipment - net $16,502,155 $1,850,481 $310,793 $18,695,631 Deferred debits and other assets $2,911,035 $687,321 $60,632 $3,511,134 Current liabilities $1,756,011 $787,668 $205,348 $2,470,770 Non-current liabilities $15,214,095 $1,694,090 $279,730 $17,543,320 Shareholders' equity $5,967,131 $2,049,847 $1,738,900 $8,296,687 2003 Current assets $2,117,260 $542,837 $466,132 $2,919,244 Other property and investments $1,151,538 $1,326,347 $1,137,069 $3,746,926 Property, plant and equipment - net $16,242,775 $1,557,025 $463,403 $18,298,797 Deferred debits and other assets $2,890,741 $745,568 $10,317 $3,562,421 Current liabilities $1,671,607 $330,684 $478,693 $2,282,223 Non-current liabilities $15,309,482 $1,891,805 $41,450 S17,568,329 Shareholders! equity $5,448,047 S1,949,288 $1,614,620 $8,703,658 (a) In addition to the 3 operating segments presented here, Entergy Consolidated also includes Entergy Corporation (parent company), other business activity, and intercompany eliminations. 2
The following shows the principal subsidiaries and affiliates within Entergy's business segments. Companies that file reports and other information with the SEC under the Securities Exchange Act of 1934 are identified in bold-faced type. l Entergy Corporation U. S.Utility Non-Utilit Nuclear l Ener Commodi Services Entergy Arkansas, Inc. Entergy Nuclear Operations, Inc. Entergy-Koch, LP Non-Nuclear Wholesale Assets Entergy Gulf States, Inc. Entergy Nuclear Finance, Inc. (50% ownership) Entergy Louisiana, Inc. Entergy Nuclear Generation Co. (Pilgrim) .Entergy Power Development Corp. Entergy Mississippi, Inc. Entergy Nuclear FitzPatrick LLC -Entergy Asset Management, Inc. Entergy New Orleans, Inc. Entergy Nuclear Indian Point 2, LLC Entergy Power, Inc. System Energy Resources, Inc. Entergy Nuclear Indian Point 3, LLC Entergy Operations, Inc. Entergy Nuclear Vermont Yankee, LLC Entergy Services, Inc. Entergy Nuclear, Inc. System Fuels, Inc. Entergy Nuclear Fuels Company Entergy Nuclear Nebraska LLC In addition to its three primary operating segments, Entergy's Competitive Retail Services business markets and sells electricity, thermal energy, and related services in competitive markets, primarily the ERCOT region in Texas, where it has over 105,000 customers. Competitive Retail Services contributed approximately 5% of Entergy's revenue in 2004, but does not currently have significant levels of net income or loss, or total assets, and Entergy reports this business as part of All Other in its segment disclosures. Stratev Entergy aspires to achieve industry leading total shareholder returns by leveraging the scale and expertise inherent in its core nuclear and utility operations. Entergy's scope includes electricity generation, transmission and distribution as well as natural gas transportation and distribution. Entergy focuses on operational excellence with an emphasis on safety, reliability, customer service, sustainability, cost efficiency and risk management. Entergy also focuses on portfolio management to make periodic buy, build, hold, or sell decisions based upon its analytically-derived points of view which are continuously updated as market conditions evolve. Availability of SEC filings and other information on Entergy's website Entergy's internet address is www.entergy.com. Entergy's annual reports on Form 10-K, quarterly reports on Form 1O-Q, current reports on Form 8-K, and amendments to any of these reports, are available free of charge through Entergy's website as soon as reasonably practicable after filing with the SEC. Financial presentations and news releases are also available through Entergy's. website. Additionally, Entergy's Corporate Governance Guidelines, Board Committee Charters for the Corporate Governance, Audit, and Personnel Committees, and Entergy's Codes of Conduct are posted on Entergy's website. This information is also available in print to any investor that requests it. In June 2004, Entergy's chief executive officer certified to the New York Stock Exchange that he was not aware of any violation by Entergy of the New York Stock Exchange corporate governance listing standards. Part I, Item I is continued on page 105. 3
ENTERGY CORPORATION AND SUBSIDIARIES REPORT OF MIANAGENIENT Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document. To meet this responsibility, management establishes and maintains a system of internal control designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and the training of personnel. This system is also tested by a comprehensive internal audit program. Entergy management assesses the effectiveness of its internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation. As a supplement to management's assessment, Entergy's independent auditors conduct an objective assessment of the degree to which management meets its responsibility for fairness of financial reporting and issue an attestation report on the adequacy of management's assessment. They evaluate Entergy's internal control over financial reporting and perform such tests and other procedures as they deem necessary to reach and express an opinion on the fairness of the financial statements. ; In addition, the Audit Committee of. the Board of Directors, composed solely of independent Directors, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal controls, and auditing and financial reporting matters. The Audit Committee appoints the independent auditors annually, and reviews with the independent auditors the scope and results of the audit effort. The Committee also meets periodically with the independent auditors and the chief internal auditor without management, providing free access to the Committee. Based on management's assessment of internal controls using the COSO. criteria, management believes that Entergy maintained, effective internal control over*financial reporting as of December 31, 2004. Management further believes that this assessment, combined with the policies and procedures noted above provide reasonable assurance that Entergy's financial statements are fairly and accurately presented in accordance with generally accepted accounting principles. J. WAYNE LEONARD LEO P. DENAULT Chief Executive Officer of Entergy Corporation Executive Vice President and Chief Financial Officer of Entergy Corporation - HUGH T. MCDONALD JOSEPH F. DOMINO Chairman, President, and Chief Executive Officer of Entergy Chairman of Entergy Gulf States, Inc., President and Chief Arkansas, Inc. Executive Officer - Texas of Entergy Gulf States, Inc. E. RENAE CONLEY CAROLYN C. SHANKS Chairiman, President, and Chief Executive Officer of Entergy Chairmaan, President, and Chief Executive Officer of Entergy Louisiana, Inc.; President and Chief Executive Officer- Mississippi, Inc. Louisiana of Ehtergy Gulf States, Inc. DANIEL F. PACKER GARY J. TAYLOR Chairman, President, and Chief Executive Officer of Entergy Chairman, President, and Chief Executive Officer of System, New Orleans, Inc. Energy Resources, Inc. THEODORE H. BUNTING, JR. JAY A. LEWIS Vice President and Chief Financial Officer of System Energy Vice President and Chief Financial Officer of Entergy Arkansas, Resources, Inc. Inc., Entergy Gulf States, Inc., Entergy Louisiana, Inc., Entergy Mississippi, Inc., and Entergy New Orleans, Inc. 4
ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS Entergy Corporation is an investor-owned public utility holding company that operates primarily through three business segments.,
- U.S. Utility generates, transmits, distributes, and sells electric power in a four-state service territory that includes portions of Arkansas, Mississippi, Texas, and-Louisiana, including the City of New Orleans; and
- operates a small natural gas distribution business.
- Non-Utility Nuclear owns and operates five nuclear power plants located in the northeastern United States and sells the electric power produced by those plants to wholesale customers. This business also provides services to other nuclear power plant owners.
- Energy Commodity Services includes Entergy-Koch and Entergy's non-nuclear wholesale assets business.
Entergy-Koch engaged in two major businesses:en ergy commodity marketing and trading through Entergy-Koch Trading, and gas transportation and storage through Gulf South Pipeline. Entergy-Koch sold both of these businesses in the fourth quarter of 2004, and Entergy-Koch is no longer an operating entity., The non-nuclear wholesale assets business sells to wholesale customers the electric power produced by power plants that it owns while it focuses on improving performance and exploring sales or restructuring opportunities f9r its power plants. Such opportunities are evaluated consistent with Entergy's market-based point-of-view. The non-nuclear wholesale assets business terminated new greenfield power development activity in 2002. - Following are the percentages of Entergy's consolidated revenues and net income generated by these segments and the percentage of total assets held by them:
% of Revenue e%of Net Income % of Total Assets
, Segment 2004 2003 2002 2004 2003 2002 2004 2003 2002 U.S. Utility 81 82 82 72 52 97 80 79 79 Non-Utility Nuclear 13 ,14 14 26 32 32 16 15 16 Energy Commodity Services 2 .2 4 - 19 (23) 3 . 7 8 Parent & Other 4 .2 - 2 (3) (6). 1 - (1) (3)
Results of Operations Earnings applicable to common stock for the years ended December 31, 2004, 2003, and 2002 by operating segment are as follows: - , Operating Segment . 2004 (T 2003 a 2002 -
- I (In Thousands) .
U.S. Utility $643,408 $469,050 $583,251 Non-Utility Nuclear .245,029 300,799 200,505 Energy Commodity Services 3,481 180,454 (145,830) Parent & Other 17,606 (23,360) (38,566) Total $909,524; $926,943 .,$599,360 Following is a discussion of Entergy's income before taxes according to the business segments listed above. Earnings for 2004 include a $97 million tax benefit that resulted from the sale of preferred stock and less than 1% of the common stock in a subsidiary in the non-nuclear wholesale assets business; and a $36 million net-of-tax impairment charge in the non-nuclear wholesale assets business, both of which are discussed below. 5
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Earnings for 2003 include the $137.1 million net-of-tax cumulative effect of changes in accounting principle that increased earnings in the first quarter of 2003, almost entirely resulting from the implementation of SFAS 143. Earnings were negatively affected in the fourth quarter of 2003 by voluntary severance program expenses of $122.8 million net-of-tax. As part of an initiative to achieve productivity improvements with a goal of reducing costs, primarily in the Non-Utility Nuclear and U.S. Utility businesses, in the second half of 2003 Entergy offered a voluntary severance program to employees in various departments. Approximately 1,100 employees, including 650 employees in nuclear operations from the Non-Utility Nuclear and U.S. Utility businesses, accepted the offers. Earnings for 2002 were negatively affected by net charges ($238.3 million net-of-tax) reflecting the effect of Entergy's decision to discontinue additional greenfield power plant development and asset impairments resulting from the deteriorating economics of wholesale power markets principally in the United States and the United Kingdom. The net charges are discussed more fully below in the Energy Commodity Services discussion. See Note 11 to the consolidated financial statements for further discussion of Entergy's business segments and their financial results in 2004, 2003, and 2002. Refer to "SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES" which accompanies Entergy Corporation's consolidated financial statements in this report for further information with respect to operating statistics. U.S. UTILITY - The increase in earnings for the U.S. Utility for 2004 from $469 million to $643 million was primarily due to the following:
- the $107.7 million ($65.6 million net-of-tax) accrual in 2003 of the loss that Would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. Refer to Note 2 to the consolidated financial statements for more details regarding the River Bend abeyed plant costs;
- .* l ower other operation and maintenance expenses primarily due to $99.8 million ($70.1 million net-of-tax) of charges recorded in 2003 in connection with the voluntary severance program;
- the $21.3 million net-of-tax cumulative effect of a change in accounting principle that reduced earnings at Entergy Gulf States in the first quarter of 2003 upon implementation of SFAS 143. See "Critical Actounting Estimates - SFAS 143" below for discussion of the implementation of SFAS 143;
- miscellaneous other income of $27.7 million (pre-tax) in 2004 resulting from a revision of the decommissioning liability for River Bend, as discussed in Note 8 to the consolidated financial statements;
- higher net revenue; and
- lower interest charges.
The decrease in earnings for the U.S. Utility for 2003 from $583 million to $469 million was primarily due to:
- the $107.7 million ($65.6 million net-of-tax) accrual in 2003 of the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs;
* $99.8 million ($70.1 million net-of-tax) of charges recorded in 2003 in connection with the voluntary severance program; and
- the $21.3 million net-of-tax cumulative effect of a change in accounting principle that reduced earnings at Entergy Gulf States in the first quarter of 2003 upon implementation of SFAS 143. See "Critical Accounting Estimates - SFAS 143" below for discussion of the implementation of SFAS 143.
Partially offsetting the decrease in earnings in 2003' were higher net revenue and lower interest charges. 6
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Net Revenue ; I 2004 Compared to 2003 Net revenue, which is Entergy's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2004 to 2003. (In Millions) 2003 net revenue $4,214.5 Volumne/weather 68.3 Summer capacity charges 17.4 Base rates 10.6 Deferred fuel cost revisions (46.3) Price applied to unbilled sales (19.3) Other . (1.2) 2004 net revenue . $4,244.0 The volume/weather variance resulted primarily from increased usage, partially offset by the effect of milder weather on sales during 2004 compared to 2003. Billed usage increased a total of 2,261 GWh in the industrial and commercial sectors. The summer capacity charges variance was due to the amortization in 2003 at Entergy Gulf States and Entergy Louisiana of deferred capacity charges for the summer of 2001. Entergy Gulf States' amortization began in June 2002 and ended in May 2003. Entergy Louisiana's amortization began in August 2002 and ended in July 2003.i Base rates increased net revenue due to a base rate increase at Entergy New Orleans that became effective in June 2003. - The deferred fuel cost revisions variance resulted primarily'from a revision in 2003 to an unbilled sales pricing estimate to more closely align the fuel component of that pricing with expected recoverable fuel costs at Entergy Louisiana. Deferred fuel cost revisions also decreased net revenue due to a revision in 2004 to the estimate of fuel costs filed for recovery at Entergy Arkansas in the March 2004 energy cost recovery rider. - The price applied to unbilled sales variance resulted from a dedrease in fuel price in 2004 caused primarily by the effect of nuclear plant outages in 2003 on average fuel costs. Grossoperatingrevenues andregulatorycredits
.; Gross operating revenues include an increase in fuel cost recovery revenues of $475 million and $18 million in electric and gas sales, respectively, primarily due to higher fuel rates in 2004 resulting from increases in the market prices of purchased power and natural gas. As such, this revenue increase is offset by increased fuel and purchased power expenses. -
Other regulatory credits increased primarily due to the following:
- cessation of the Grand Gulf Accelerated Recovery Tariff that was suspended in July 2003;
-* the amortization in 2003 of deferred capacity charges for summer 2001 power purchases at Entergy Gulf States and Entergy Louisiana;
* - the deferral in 2004 of $14.3 million of capacity charges related to generation resource planning as allowed by the LPSC;
- the deferral in 2004 by Entergy Louisiana of $11.4 million related to the voluntary severance program, in accordance with a proposed stipulation entered into with the LPSC staff; and 7
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis
- the deferral in August 2004 of $7.5 million of fossil plant maintenance and voluntary severance program costs at Entergy New Orleans as a result of a stipulation approved by the City Council.
2003 Compared to 2002 Net revenue, which is Entergy's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2003 to 2002. (In Millions) 2002 net revenue $4,209.6-'- Base rate increases 66.2 Base rate decreases (23.3) Deferred fuel cost revisions 56.2 Asset retirement obligation 42.9 Net wholesale revenue 23.2-March 2002 Ark. settlement agreement (154.0) Other (6.3) 2003 net revenue $4,214.5 Base rates increased net revenue due to base rate increases at Entergy Mississippi and Entergy New Orleans that became effective in January 2003 and June 2003, respectively. Entergy Gulf States implemented base rate decreases in its Louisiana jurisdiction effective June 2002 and January 2003. The January 2003 base rate decrease of $22.1 million had a minimal impact on net income due to a corresponding reduction in nuclear depreciation and decommissioning expenses associated with the change in accounting estimate to reflect an assumed extension of River Bend's useful life. The deferred fuel cost revisions variance was due to a revised unbilled sales pricing estimate made in December 2002 and further revision of that estimate in the first quarter of 2003 to more closely align the fuel component of that pricing with expected recoverable fuel costs at Entergy Louisiana. The asset retirement obligation variance, was due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," adopted in January 2003. See "Critical Accounting Estimates - Nuclear Decommissioning Costs" for more details on SFAS 143. The increase was offset by increased depreciation and decommissioning expenses and had an insignificant effect on net income. The increase in net wholesale revenue was primarily due to an increase in sales volume to municipal and cooperative customers. The March 2002 settlement agreement variance reflects the absence in 2003 of the effect of recording the ice storm settlement approved by the APSC in 2002. This settlement resulted in previously deferred revenues at Entergy Arkansas per the transition cost account mechanism being recorded in net revenue in the second quartet of 2002. The decrease was offset by a corresponding decrease in other operation and maintenance expenses and had a. minimal effect on net income. Gross operatingrevenues andregulatorycredits
- Gross operating revenues include an increase in fuel cost recovery revenues of $682 million and $53 million in electric and gas sales, respectively, primarily due to higher fuel rates in 2003 resulting from increases in the market prices of purchased power and natural gas. As such, this revenue increase was offset by increased fuel and purchased power expenses. £ 8
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Other regulatory credits decreased primarily due to the APSC-approved March 2002 settlement agreement mentioned above, which increased other regulatory credits in 2002 to offset other operation and maintenance expenses of $159.9 million related to the December 2000 ice storms. The decrease was partially offset by the asset retirement obligation mentioned above, which increased other regulatory credits in 2003 to offset the increases in depreciation and decommissioning expenses. Other Income Statement Variances 2004 Compared to 2003 Other operation and maintenance expenses decreased from $1.613 billion in 2003 to $1.569 billion in 2004 primarily due to voluntary severance program accruals of $99.8 million in 2003 partially offset by an increase of $30.5 million as a result of higher customer service support costs in 2004 and an increase of approximately $33 million as a result of higher benefits costs in 2004. Entergy expects benefit costs to continue to increase in 2005. See "Critical Accounting Estimates - Pension and Other Retirement Benefits" and Note 10 to the consolidated financial statements for further discussion of benefit costs. Depreciation and amortization expenses increased from $797.6 million in 2003 to $823.7 million in 2004 primarily due to higher depreciation of Grand Gulf due to a higher scheduled sale-leaseback principal payment in addition to an increase in plant in service. Other income (deductions) changed from ($36.0 million) in 2003 to $108.9 million in 2004 primarily due to the following:
- the $107.7 million accrual in the second quarter of 2003 for the loss that would be associated with a final,
- non-appealable decision disallowing abeyed River Bend plant costs. See Note 2 to the consolidated financial statements for more details regarding the River Bend abeyed plant costs;
- a reduction in the decommissioning liability for River Bend in 2004, as discussed in Note 8 to the consolidated financial statements; and
- a $10 million reduction in the loss provision for an environmental clean-up site.
Interest on long-term debt decreased from $433.5 million in 2003 to $390.7 million in 2004 primarily due to the net retirement and refinancing of long-term debt in 2003 and the first six months of 2004. See Note 5 to the consolidated.financial statements for details on long-term debt. 2003 Compared to 2002 Other operation and maintenance expenses decreased from $1.679 billion in 2002 to $1.613 billion in 2003 primarily due to decreased expenses at Entergy Arkansas. The March 2002 settlement agreement that became final in the second quarter of 2002, allowing Entergy Arkansas to recover a large majority of 2000 and 2001 ice storm repair expenses through the previously-collected transition cost account amounts, increased Entergy Arkansas' expenses by
$159.9 million in 2002. This increase in expenses in 2002 was offset by a regulatory credit resulting in no effect on net income. The decrease was partially offset by an increase of $99.8 million in benefit costs as a result of voluntary severance program accruals in 2003.
Decommissioning expense increased from $30.5 million in 2002 to $92.5 million in 2003 primarily due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations." The increase in decommissioning expense was offset by increases in other regulatory credits and interest and dividend income and had an insignificant effect on net income. Depreciation and amortization expenses increased from $769.8 million in 2002 to $797.6 million in 2003 primarily due to an increase in plant in service. The increase was also due to the implementation of SFAS 143. The increase in depreciation and amortization expense due to SFAS 143 implementation was offset by increases in other regulatory credits and interest and dividend income and has an insignificant effect on net income. 9
Entergy Corporation and Subsidiaries Maiiagemenfs Financial Discussion and Analysis
-Other income (deductions) 'changed from $4,7.6imillibn in 2002 to ($36.0 million) in 2003 primarily due to a decrease in "miscellaneous -net" as a result of a $107.7 million accrual in the second quarter of 2003 for the, loss that would be associated with 'a' final, non-appealable' decision disallowing abeyed River Bend plant costs. See Note 2 to the consolidated financial statements for more details regarding the River Bend abeyed plant costs. The decrease was partially offset by an increase in interest and dividend income as a result of the implementation of SFAS 143.
Interest on long-term debt decreased from $462.0 million in 2002 to $433.5 million in 2003 primarily due to the redemption and refinancing of long-term debt. r I; ' , ' NON-UTIL1TYNUCLEAR Following are key performance measures for Non-Utility Nuclear; -
- 'e204 -- 2003 2002 Net MW in operation at December 31 4,058 4,001 3,955
"-;Average realized price per MNMh -*$4X.26 I $39.38 $40.07 i Generation in GWh for the year . , 32,524 -32,379 ; 29,953 Capacity factor for the year 92% 92% 93%
2004'Coniparedto2003 i " The decrease in earnings for Non-Utility Nuclear from $300.8 million to $245.0 million was primarily due to the $1545 imillion net-of-tax cumulative effect of a change in accounting principle that increased earnings in the first quarter of 2003 upon implementatiohn'of SEAS' 143.' See "Crtical 'Accountin! Estimates'- SFAS 143" below for discussion of the implementation'of SFAS'143. Earnings before the cumulative effect of accounting change increased by $98.7 million primarily due to the following:-
- lower operation and maintenance expenses, which decreased from $681.8 million in 2003 to $595.7 million in 2004, primarily resulting from charges recorded in 2003 in connection with the voluntary severance program; ' , ' ' . '
higherifevenues,I-which increased from $1.275 billion'in 2)03 to $1.342 billion in 2004, primarily'resulting' from higher contract pricing. The addition of a support- services contract for the Cooper Nuclear Station and increased generation in 2004 due to power uprates completed in 2003 and fewer planned and unplanned outages in 2004 also contributed to the higher revenues; and
- miscellaneous income resulting from a reduction in the decommissioning liability for a plant, as discussed in Niot'et8 to the consolidated financiat statements.' - .
- Partially offsetting this increase were the following: e' ' ' ' -
' higher income taxies, which increased from $88.6 million in 2003 to $142.6 million in 2004; and
' 'higher'!d'epreciatio'n expense, which increased from $34.3' million in 2003 to'$48.nmillion in 2004, due to' additions to plant in service. i ; ,
2003Comnpared to 2002 ' i
, ,c ." .. . . !aam tlt Nu Cg'fr
,o- 'Qkt' lir' . ,'.
' The increase i earnings for Non-Utility Nuclear from $200.5 million to $300.8 million was primarily due to the $154.5 million net-of-tax cumulative effect of a change in accounting principle recognized in the- first quarter of 2003 upon implementation of SFAS 143. See "Critical Accountin! Estimates - SFAS 143" below for discussion of th 'implementatibn of SPAS 143. Income before the cumulative effect of accounting change decreased by $54.2 million. 'The decrease was pritnarily dueto $83,0 million ($5(.6 million net-of-tax) of charges recorded in conhection with the voluntary severice 'program. Except for the'effect of the voluntary severance program, operation and maintenance expenses in 2003 per MWh of generation were iine with 2002 operation and maintenance expenses.'
10
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis ENERGY COMMODITY SERVICES Sales of Entergy-Koch Businesses In the fourth quarter of 2004, Entergy-Koch sold its energy trading and pipeline businesses to third parties. The sales came after a review of strategic alternatives for enhancing the value of Entergy-Koch, LP. Entergy received $862 million of cash distributions in 2004 from Entergy-Koch after the business sales, and Entergy ultimately expects to receive total net cash distributions exceeding $1 billion, comprised of the after-tax cash from the distributions of the sales proceeds and the eventual liquidation of Entergy-Koch. Entergy currently expects that it will receive the remaining cash distributions in 2006, and expects that the net cash distributions will exceed its equity investment in Entergy-Koch. Entergy expects to record a $60 million net-of-tax gain when the remainder of the proceeds are received in 2006. In the purchase agreements for the energy trading and the pipeline business sales, Entergy-Koch has agreed to indemnify the respective purchasers for certain potential losses relating to any breaches of the sellers' representations, warranties, and obligations under each of the purchase agreements. Entergy Corporation has guaranteed up to 50% of Entergy-Koch's indemnification obligations to the purchasers.. Entergy does not expect any material claims under these indemnification obligations, but to the extent that any are asserted and paid, the gain that Entergy expects to record in 2006 may be reduced. Results of Operations 2004 Compared to 2003 The decrease in earnings for Energy Commodity Services from $180.5 million to $3.5 million was primarily due to:
- earnings from Entergy's investment in Entergy-Koch were $254 million lower in 2004, primarily as a result of Entergy-Koch's trading business reporting a loss from its operations in 2004; and,
- Entergy recorded a charge in 2004 of approximately $55 million ($36 million net-of-tax) as a result of an impairment of the value of the Warren Power plant, which is owned in the non-nuclear wholesale assets business. Entergy concluded that the plant is impaired based on valuation studies prepared in connection with the Entergy Asset Management stock sale discussed below.
Partially offsetting the decrease in earnings is a tax benefit resulting from the sale of preferred stock and less than 1% of the common stock of Entergy Asset Management, an Entergy subsidiary. In December 2004, an Entergy subsidiary sold the stock to a third party for $29.75 million. The sale resulted in a capital loss for tax purposes of
$370 million, producing a net tax benefit of $97 million that Entergy recorded in the fourth quarter of 2004.
2003 Compared to 2002 The increase in earnings for Energy Commodity Services in 2003 from a $145.8 million loss to $180.5 million in earnings was primarily due to net charges recorded to operating expenses in 2002, as discussed below. Higher earnings from Entergy's investment in Entergy-Koch also contributed to the increase in earnings. The income from Entergy's investment in Entergy-Koch was $73 million higher in 2003 primarily as a result of higher earnings in its trading business. In 2002, Entergy recorded charges to reflect the effect of Entergy's decision to discontinue additional greenfield power plant development and to reflect asset impairments resulting from the deteriorating economics of wholesale power markets principally in the United States and the United Kingdom. The net charges of $428.5 million ($238.3 million net-of-tax) consisted of the following: 11
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis
- The power development business obtained contractsin October 1999 to acquire 36 turbines from General Electric. Entergy's rights and obligations under the contracts for 22 of the turbines were sold to an independent special-purpose entity in May 2001. $178.0 million of the charges, including an offsetting net-of-tax benefit of $18.5 million related to the subsequent sale of four turbines to a third party, was a provision for the net costs resulting from cancellation or sale of the turbines subject to purchase commitments with the special-purpose entity;' -
* $204.4 million of the charges resulted from the write-off of Entergy Power Development Corporation's equity investment in the Damhead Creek project and the impairment of the values of its Warren Power power plant and its Crete and RS Cogen projects, This portion of the charges reflected Enterg'is estimate of the effects of reduced spark spreads in the United States and the United Kingdom. Damhead Creek was sold in December 2002, resulting in net income of $31.4 million;
* $39.1 million of the charges related to the restructuring of the non-nuclear wholesale assets business, which was comprised of $22.5 million of impairments of administrative fixed assets, $10.7 million of estimated sublease losses, and $5.9 million of employee-related costs; i $32.7 million of the charges resulted from the write-off of capitalized project devel6pment costs for projects that would not be completed; and i ; ,
- a gain of $25.7 million ($15.9 million net-of-tax) realized on the sale in August 2002 of an interest in-projects under development in Spain. '
PARENT & OTHER 2004 Compared to 2003 The increase in earnings for Parent'& Other from a $23.4 million loss to $17.6 million-in earnings was primarily due to the following:
- realization of $16.7 million of tax benefits related to the Entergy-Koch investment; and i
*Entergy's competitive retail business earned a very small profit in 2004 compared to reporting a $14.4 million loss in 2003.
2003 Compared to 2002 The loss from Parent & Other decreased in 2003 from $38.6 million to $23.4 million primarily due to lower income tax expense..
- . . . - .. X, . .. - , F. ;. .. ,.., , -. i:
Income' Taxes I ' j..', The effective income tax rates for 2004, 2003, and 2002 were 28.2%, 37.9%, and 32.1%, respectively. See Note 3 to the consolidated financial statements for a reconciliation of the federal statutory rate of 35.0% to' the effective income tax rates. The lower effective income tax rate in 2004 is primarily due to the tax benefits resulting from the Entergy Asset Management' stock sale discussed above. Liquidity and Capital Resources 'I* This section discusses Entergy's capital structure, capital spending plans and other, uses of capital, sources of capital, and the cash flow activity presented in the cash flow statement. Capital Structure ,- - ' ' Entergy's capitalization is balanced between equity and debt, as shown in, the following table. The reduction in the debt to capital percentage from 2002 to 2003 is the result of reduced debt outstanding in the U.S. 12
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Utility and Non-Utility Nuclear businesses, and an increase in shareholders' equity, primarily due to increased retained earnings. 2004 2003 2002 Net debt to net capital at the end of the year 44.7% 45.3% 47.7% Effect of subtracting cash from debt 2.7% 2.2% 4.1% Debt to capital at the end of the year 47.4% 47.5% 51.8% Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable, capital lease obligations, preferred stock with sinking fund, and long-term debt, including the currently maturing portion. Capital consists of debt, common shareholders' equity, and preferred stock without sinking fund. Net capital consists of capital less cash and cash equivalents. The preferred stock with sinking fund is included in debt pursuant to SFAS 150, which Entergy implemented in the third quarter of 2003. The 2002 ratio does not reflect that type of security as debt, but does include it in net capital, which is how Entergy presented those securities prior to implementation of SFAS 150. Entergy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy's financial condition. Long-term debt, including the currently maturing portion, makes up over 90% of Entergy's total debt outstanding. Following are Entergy's long-term debt principal maturities as of December 31, 2003 and 2004 by operating segment. The figures below include principal payments on the Entergy Louisiana and System Energy sale-leaseback transactions, which are included in long-term debt on the balance sheet. Long-term debt maturities 2004 2005 2006 2007 2008-2009 after 2009 (In Millions) As of December 31. 2003 U.S. Utility $450 $355 $28 $573 $721 $4,305 Non-Utility Nuclear 74 72 76 80 40 173 Energy Commodity Services Parent and Other - 60 - - 539 301 Total $524 $487 $104 $653 $1,300 $4,779 As of December 31. 2004 U.S. Utility $359 $27 $98 $749 $4,880 Non-Utility Nuclear - 77 76 80 40 173 Energy Commodity Services Parent and Other - 60 - 50 539 301 Total $496 $103 $228 $1,328 $5,354 Note 5 to the consolidated financial statements provides more detail concerning long-term debt. In May 2004, Entergy Corporation replaced its 364-day bank credit facility with two separate facilities, a new 364-day credit facility and 'a three-year credit facility. The three-year credit facility, which expires in May 2007, has a borrowing capacity of $965 million, of which $50 million was outstanding at December 31, 2004. In December 2004, Entergy Corporation refinanced the 364-day bank credit facility by entering into a five-year credit facility. The five-year credit facility, which expires in December 2009, has a borrowing capacity of $500 million, none of which was outstanding at December 31, 2004. Entergy also has the ability to issue letters of credit against the total borrowing capacity of both credit facilities, and $50 million of letters of credit had been issued against the three-year facility at December 31, 2004. Entergy Corporation's credit facilities require it to maintain a consolidated debt ratio of 65% or' less of its total capitalization, and maintain an interest coverage ratio of 2 to 1. If Entergy fails to meet these limits, or if 13
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Entergy or the domestic utility companies default on other indebtedness or are in bankruptcy or insolvency proceedings, an acceleration of the credit facilities' maturity dates may occur. : Capital lease obligations, including nuclear fuel leases, are a minimal part of Entergy's overall capital structure, and are discussed further in Note 9 to the consolidated financial statements. Following are Entergy's payment obligations under those leases: 2005 2006 2007 2008-2009 after 2009 (In Millions) Capital lease payments, including nuclear fuel leases $136 $143 $3 $2 $3 Notes payable, which include borrowings outstanding on credit facilities with original maturities of less than one year, were less than $1 million as of December 31, 2004. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans each have 364-day credit facilities available as follows: Amount of Amount Drawn as of Company Expiration Date Facility Dec. 31, 2004 Entergy Arkansas April 2005 $85 million Entergy Louisiana April 2005 $15 million (a) Entergy Mississippi May 2005 $25 million Entergy New Orleans April 2005 $14 million (a) (a) The combined amount borrowed by Entergy Louisiana and Entergy New Orleans under these facilities at any one time cannot exceed $15 million. Onerating Lease Obligations and Guarantees of Unconsolidated Obligations ! Entergy has a minimal amount of operating lease obligations and guarantees in support of unconsolidated obligations. Entergy's guarantees in support of unconsolidated obligations are not likely to have a material effect on Entergy's financial condition or results of operations. Following are Entergy's payment obligations as of December 31, 2004 on non-cancelable operating leases with a term over one year: 2005 2006 2007 2008-2009 after.2009 (In Millions) Operating lease payments $99 $86 $69 $100 $210 The operating leases are discussed more thoroughly in Note 9 to the consolidated financial statements. Summarv of Contractual Obligations of Consolidated Entities Contractual Obligations 2005 2006-2007 2008-2009 after2009 ; -Total (InMillions) Long-term debt (I) $496 $331 $1,328 $5,354 $7,509 Capital lease payments (2) $136 $146 $2 $3 $287 Operating leases (2) $99 $155, $100 $210 I $564 Purchase obligations (3) $1,160 $1,402 $962 $1,156 $4,680 (1) Long-term debt is discussed in Note 5 to the consolidated financial statements. d s N 9 to t (2) Capital lease payments include nuclear fuel leases. Lease obligations are discussed in Note 9 to the consolidated financial statements. 14
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis (3) Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Approximately 99% of the total pertains to fuel and purchased power obligations that are recovered in the normal course of business through various fuel cost recovery mechanisms in the U.S. Utility business. In addition to these contractual obligations, Entergy expects to contribute $185.9 million to its pension plans and $63.3 million to other postretirement plans in 2005. Capital Funds Agreement Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:
- maintain System Energy's equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);
permit the continued commercial operation of Grand Gulf;
- pay in full all System Energy indebtedness for borrowed money when due; and
- enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy's rights in the agreement as security for the specific debt.
Capital Expenditure Plans and Other Uses of Capital Following are the amounts of Entergy's planned construction and other capital investments by operating segment for 2005 through 2007: Planned construction and capital investments 2005 2006 2007 (In Millions) Maintenance Capital: U.S. Utility $734 $699 $763 Non-Utility Nuclear 72 72 60 Energy Commodity Services 3 4 6 Parent and Other 11 19 11 820 794 840 Capital Commitments: U.S. Utility 571 349 201 Non-Utility Nuclear 90 67 43 Energy Commodity Services Parent and Other 661 416 244 Total $1,481 $1,210 $1,084 Maintenance Capital refers to amounts Entergy plans to spend on routine capital projects that are necessary to support reliability of its service, equipment, or systems and to support normal customer growth. Capital Commitments refers to non-routine capital investments for which Entergy is either contractually obligated, has Board-approval, or is otherwise required to make pursuant to a regulatory agreement or existing rule or law. Amounts reflected in this category include the following: Replacement of the ANO I steam generators and reactor vessel closure head. Management estimates the cost of the ANO I project to be approximately $235 million, of which approximately $96 million has been 15
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis incurred through 2004. $115 million is expected to be incurred in 2005, with the remainder expected to be spent in 2006. Entergy expects the replacement to occur during a planned refueling outage in 2005. Entergy Arkansas filed with the APSC in January 2003 a request for a declaratory order that the investment in the replacement is in the public interest. The APSC issued the requested order in May 2003. This order is analogous to the order received in 1998 prior to the replacement of the ANO 2 steam generators.
- Purchase of the Perryville power plant in Louisiana. In January 2004, Entergy Louisiana signed a definitive agreement to acquire the 718 MW Perryville power plant for $170 million. The agreement has subsequently been amended to allow the current plant owner to retain the interconnection facilities associated with the plant, resulting in a decrease in the acquisition price to $162 million. As a result of the amended terms, the FERC issued an order in October 2004 disclaiming jurisdiction over the acquisition. This order currently is subject to rehearing by the FERC. The plant is owned by a subsidiary of Cleco Corporation, which subsidiary submitted a bid in response to Entergy's Fall 2002 request for proposals for supply-side resources. The signing of the agreement followed a voluntary Chapter 11 bankruptcy filing by the plant's owner. Entergy expects that Entergy Louisiana will own 100 percent of the Perryville plant, and that Entergy Louisiana will sell 75 percent of the output to Entergy Gulf States under a long-term cost-of-service power purchase agreement. In addition, Entergy Louisiana and Entergy (ulf States executed an interim power purchase agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by December 2005) for 100 percent of the output of the Perryville power plant. In April 2004, the bankruptcy court approved Entergy Louisiana's agreement to acquire the plant. In March 2004, Entergy Gulf States and Entergy Louisiana filed with the LPSC for its approval of the acquisition and long-term cost-of-service power purchase agreement. Entergy is seeking approval from the LPSC of cost recovery for the acquisition, giving consideration to the need for the power and the prudence of Entergy Louisiana and Entergy Gulf States in engaging in the transaction. Hearings are scheduled for March 2005. Assuming regulatory approval by the LPSC, Entergy Louisiana expects the Perryville acquisition to close in mid-2005.
- Transmission expansion designed to address immediate load growth needs and to provide improved transmission flexibility for the southeastern Louisiana and Texas regions of Entergy's service territory.
Entergy expects to spend $170 million on high voltage transmission infrastructure to be completed in phases between mid-2005 to mid-2007.
- Purchase-of additional generation supply sources within the U.S. Utility's service territory.
- Nuclear power plant uprates, dry cask spent fuel storage, and license renewals.
From time to time, Entergy considers other capital investments as potentially being necessary or desirable in the future,, including additional nuclear plant power uprates, generation supply assets, various transmission upgrades, environmental compliance expenditures, or investments in new businesses or assets. Because no contractual obligation, commitment, or Board-approval exists to pursue these investments, they are not included in Entergy's planned construction and capital investments. These potential investments are also subject to evaluation and approval in accordance with Entergy's policies before amounts may be spent. In addition, Entergy's capital spending plans do not include spending for transmission upgrades requested by merchant generators, other than projects currently underway. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, and the ability to access capital. Dividends and Stock Repurchases Declarations of dividends on Entergy's common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy's common stock dividends based upon Entergy's earnings, financial strength, and future investment opportunities. At its October 2004 meeting, the Board increased Entergy's quarterly dividend per share by 20%, to $0.54. In 2004, Entergy paid approximately $428 million in cash dividends on its common stock. In accordance with Entergy's stock-based compensation plan, Entergy periodically grants stock options to its employees, which may be exercised to obtain shares of Entergy's common stock. According to the plan, these 16
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis shares can be -newly issued shares, treasury stock, or shares purchased on the open market. Entergy's management has been authorized to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans. In addition to this authority, the Board has approved a program under which Entergy will repurchase up to $1.5 billion of its common stock through 2006. The amount of repurchases under the program may vary as a result of material changes in business results or capital spending, or as a result of material new investment opportunities. In 2004, Entergy repurchased 16,631,800 shares of common stock under both programs for a total purchase price of $1.018 billion. PUHCA Restrictions on Uses of Capital Entergy's ability to invest in electric wholesale generators and foreign utility companies is subject to the SEC's regulations under PUHCA. As authorized by the SEC, Entergy is allowed to invest earnings in electric wholesale generators and foreign utility companies in an amount equal to 100% of its average consolidated retained earnings. As of December 31, 2004, Entergy's investments subject to this rule totaled $2.7 billion constituting 55.9% of Entergy's average consolidated retained earnings. Entergy's ability to guarantee obligations of Entergy's non-utility subsidiaries is also limited by SEC regulations under PUHCA. In August 2000, the SEC issued an order, effective through December 31, 2005, that allows Entergy to issue up to $2 billion of guarantees for the benefit of its non-utility companies. In February 2005, Entergy requested that the SEC increase this limit to $4 billion. Under PUHCA, the SEC imposes a limit equal to 15% of consolidated capitalization on the amount that may be invested in "energy-related" businesses without specific SEC approval. Entergy has made investments in energy-related businesses, including power marketing and trading. Entergy's available capacity to make additional investments at December 31, 2004 was approximately $1.9 billion. Sources of Capital Entergy's sources to meet its capital requirements and to fund potential investments include:
- internally generated funds;
- cash on hand ($808 million as of December 31, 2004);
- securities issuances;
- bank financing under new or existing facilities; and
- sales of assets.
The majority of Entergy's internally generated funds come from the U.S. Utility. Circumstances such as weather patterns, price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the level of internally generated funds in the future. In the following section, Entergy's cash flow activity for the previous three years is discussed. Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation's subsidiaries restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2004, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. All debt and common and preferred stock issuances by the domestic utility companies and System Energy require prior regulatory approval and their preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. The domestic utility companies and System Energy have sufficient capacity under these tests to meet foreseeable capital needs. The short-term borrowings of Entergy's subsidiaries are limited to amounts authorized by the SEC. The current limits authorized are effective through November 30, 2007. In addition to borrowing from commercial banks, Entergy's subsidiaries are authorized under the SEC order to borrow from Entergy's money pool. The 17
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis money pool is an inter-company borrowing arrangement designed to reduce Entergy's subsidiaries' dependence on external short-term borrowings. Borrowings from the money pool and external borrowings combined may not exceed the SEC authorized limits. As of December 31, 2004, Entergy's subsidiaries' aggregate authorized limit was $1.6 billion and the aggregate outstanding borrowing from the money pool was $151.6 million. There were no borrowings outstanding from external sources. Under the SEC order and without further SEC authorization, the domestic utility companies and System Energy cannot issue new short-term indebtedness unless (a) Entergy Corporation and the issuer each maintain common equity of at least 30% of its capital and (b) with the exception of money pool borrowings, the debt security to be issued (if rated) and all outstanding securities of the issuer and Entergy Corporation that are rated must be rated investment grade. See Note 4 to the consolidated financial statements for further discussion of Entergy's short-term borrowing limits. The short and long-term securities issuances of Entergy Corporation also are limited to amounts authorized by the SEC. Under its current SEC order, and without further SEC authorization, Entergy Corporation cannot incur additional indebtedness or issue other securities unless (a) Entergy Corporation and each of its public utility subsidiaries maintain common equity ratios of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of Entergy Corporation that are rated, are rated investment grade. The long-term securities issuances of Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and System Energy also are limited to amounts authorized by the SEC. Under the current SEC orders of Entergy Gulf States, Entergy Louisiana, and Entergy Mississippi, and without further SEC authorization, the issuer cannot incur additional indebtedness or issue other securities unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of the issuer (other than preferred stock of Entergy Gulf States), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. Cash Flow Activity As shown in Entergy's Statements of Cash Flows, cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows: 2004 2003' 2002 (In Millions) Cash and cash equivalents at beginning of period $692 $1,335 $752 Cash flow provided by (used in): Operating activities 2,929 2,006 2,181 Investing activities (1,140) (1,783) (1,388) Financing activities (1,672) (869) (213) Effect of exchange rates on cash and cash equivalents (1) 3 3 Net increase (decrease) in cash and cash equivalents 116 (643) 583 Cash and cash equivalents at end of period $808 $692 $1,335 18
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Operating Cash Flow Activity 2004 Compared to 2003 Entergy's cash flow provided by operating activities increased in 2004 primarily due to the following:
- The U.S. Utility provided $2,208 million in cash from operating activities compared to providing
$1,675 million in 2003. The increase resulted primarily from the receipt of intercompany income tax refunds from the parent company, Entergy Corporation. Income tax refunds/payments contributed approximately $400 million of the increase in cash from operating activities in 2004. Improved recovery Qf fuel costs and a reduction in interest paid also contributed to the increase in 2004.
- The Non-Utility Nuclear business provided $415 million in cash from operating activities compared to providing $183 million in 2003. The increase resulted primarily from lower intercompany income tax payments and Increases in generation and contract pricing that led to an increase in revenues.
- Entergy's investment in Entergy-Koch, LP provided $526 million in cash from operating activities compared to using $41 million in 2003. Entergy received dividends from Entergy-Koch of $529 million in 2004 compared to $100 million in 2003. 'In addition, tax payments related to the investment were higher in 2003 because the investment had higher net income in 2003. '
- The non-nuclear wholesale asset business used $46 million in'cash from operating activities compared to using $70 million in 2003. The decrease in cash used resulted primarily from a one-time $33 million' payment in 2003 related to a generation contract in the non-nuclear wholesale assets business.
- The parent company, Entergy Corporation, used $146 million in cash from operating activities in 2004 compared to providing $209 million in 2003 primarily due to higher intercompany income tax payments.
As discussed in Note 3 to the consolidated financial statements, in 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The cash benefit from the method change was $74 million on a consolidated basis in 2004.' This accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. As of December 31, 2004, Entergy has a consolidated net operating loss (NOL) carryforward for tax purposes of $2.9 billion, principally resulting from the change in tax accounting method related to cost of goods sold. If the tax accounting method change is sustained, Entergy expects tofiully utilize the NOL carryforward through 2006. 2003 Compared to 2002 Entergy's cash flow provided by operating activities decreased in 2003 primarily due to the following:
- The U.S. Utility provided $1,675 million in operating cash flow in 2003 compared to providing $2,341 million in 2002. The decrease primarily resulted from the tax'accounting election made by Entergy Louisiana, as discussed below. Also contributing to the decrease were higher payments for fuel during the period, which also significantly increas&d the amount of deferred fuel costs.
- The non-nuclear wholesale assets business used $70 million in operating cash flow in 2003 compared to providing $43 million in 2002 primarily due to a decrease of $64 million in the income tax refund received in 2003 compared to 2002. Also contributing to the increase in cash used was a one-time $33 million paymeft in 2003 related to a generation'contract in the non-nuclear wholesale'assets business.
- The Non-Utility Nuclear segment provided $183 million in operating'cash flow in 2003 compared to providing $282 million in 2002 primarily due to higher tax payments and unplanned outages.
- Operating cash flow used by the investment in Entergy-Koch, LP decreased by $6 million in 2003. This decrease in cash flow used was due to the receipt of $100 million in dividends from Entergy-Koch in 2003.
Almost entirely offsettink the dividends received was an increase in tax payments related to Entergy's investment in Entergy-Koch due to increased income from the investment. Partially offsetting the decrease in cash flow in 2003 was an increase due to the parent company providing $209 million in operating cash flow in 2003 compared to using $439 million in 2002 primarily due to the payment that 19
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Entergy Corporation made to Entergy Louisiana in 2002 pursuant to the tax accounting election made by Entergy Louisiana. In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts. The most significant of these is the contract to purchase power from the Vidalia project (the contract is discussed in Note 8 to the consolidated financial statements). The new tax accounting method has provided a cumulative cash flow benefit of approximately $790 million through 2004, which is expected to reverse in the years 2005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. Approximately half of the consolidated cash flow benefit of the election occurred in 2001 and the remainder occurred in 2002. In accordance with Entergy's intercompany tax allocation agreement, the cash flow benefit for Entergy Louisiana occurred in the fourth quarter of 2002. In a September 2002 settlement of an LPSC proceeding that concerned the Vidalia contract, the LPSC approved Entergy Louisiana's proposed treatment of the regulatory impact of the tax accounting election. In general, the settlement permits Entergy Louisiana to keep a portion of the tax benefit in exchange for bearing the risk associated with sustaining the tax treatment. The LPSC settlement divided the term of the Vidalia contract into two segments: 2002-2012 and 2013-2031. During the first eight years of the 2002-2012 segment, Entergy Louisiana agreed to credit rates by flowing through its fuel adjustment calculation $11 million each year, beginning monthly in October 2002. Entergy Louisiana must credit rates in this way;,and by this amount even if Entergy Louisiana is unable to sustain the tax deduction. Entergy Louisiana also must credit rates by $11 million each year for an additional two years unless either the tax accounting method elected is retroactively repealed or the Internal Revenue Service denies the entire deduction related to the tax accounting method.. Entergy Louisiana agreed to credit ratepayers additional amounts unless the tax accounting election is not sustained if it is challenged. During 2013-2031, Entergy Louisiana and its ratepayers would share the remaining benefits of this tax accounting election. Investing Activities' 2004 Compared to 2003 Net cash used in investing activities decreased in 2004 primarily due to the following:
- Construction expenditures were $158 million lower in 2004 than in 2003, including decreases of
$81 million in the U.S. Utility business, $39 million in the Non-Utility Nuclear business, and $42 million in the non-nuclear wholesale assets business.
- Entergy received net returns of invested capital from Entergy-Koch of $284 million in 2004 after the sale by Entergy-Koch of its trading and pipeline businesses. This activity is reported in the "Decrease in other investments" line in the cash flow statement.
- Approximately $60 million of the cash collateral for a letter of credit that secures the installment obligations owed to NYPA for the acquisition of the FitzPatrick and Indian Point 3 nuclear power plants was released to Entergy in 2004. Approximately $172 million of this cash collateral was released to Entergy in 2003, and the letter of credit is no longer secured by cash collateral. This activity is reported in the "Decrease in other investments" line in the cash flow statement.
- The non-nuclear wholesale assets business realized $75 million in net proceeds from sales of portions of three of its power plants in 2004.
- Entergy made temporary investments of $50 million in 2003, and these investments matured in the,first quarter of 2004.
- Entergy Arkansas used $7 million, Entergy Gulf States used $77 million, and Entergy Mississippi used $73 million for other regulatory investments in 2003 as a result of fuel cost under-recovery. In 2004, Entergy Arkansas used $4 million and Entergy Gulf States used $50 million for other regulatory investments related to fuel cost under-recovery. See Note I to the consolidated financial statements for discussion of the accounting treatment of these fuel cost under-recoveries.,L 20
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis 2003 Compared to 2002 Net cash used in investing activities increased in 2003 primarily due to the following:
- The non-nuclear wholesale assets business realized $215 million in net proceeds from sales of businesses in 2002.
- Temporary investments of $150 million matured in 2002, which provided cash flow in 2002.
- Temporary investments of $50 million were made in 2003, which used cash flow in 2003.
- Entergy Gulf States had $77 million and Entergy Mississippi had $73 million of other regulatory investments in 2003 as a result of fuel cost under-recoveries. See Note I to the consolidated financial statements for discussion of the accounting treatment of these fuel cost under-recoveries. See Note 2 to the consolidated financial statements for discussion of the change in Entergy Mississippi's energy cost recovery rider.
Partially offsetting these uses of cash, approximately $172 million of the cash collateral for a letter, of credit that secures the installment obligations owed to NYPA for the acquisition of the FitzPatrick and Indian Point 3 nuclear power plants was released to Entergy during 2003. Financing Activities - 2004 Compared to 2003 Net cash used in financing activities increased in 2004 primarily due to the following:
- Entergy Corporation issued $538 million of long-term notes in 2003.
- Entergy Corporation repurchased $1.018 billion of its common stock in 2004, as discussed above in the "Uses of Capital" section.
- Entergy Corporation paid $65 million more in common stock dividends in 2004 than in 2003.
Offsetting the factors that caused an increase in cash used in financing activities in 2004 were the following:
- Retirements of long-term debt net of issuances by the U.S. Utility segment used $345 million in 2004 and used $359 million in 2003. See Note 5 to the consolidated financial statements for the details of the long-term debt activity in 2004.
- In 2003, Entergy Corporation decreased the net borrowings on its credit facility by $500 million, while in
'2004, net borrowings on its credit facilities increased by $50 million.
i The non-nuclear wholesale assets business retired the $79 million Top of Iowa wind project debt at its maturity in January 2003. 2003 Compared to 2002 Net cash used in financing activities increased in 2003 primarily due to the following:
- Net long-term debt retirements by the U.S: Utility segment were approximately $470 million in 2003 compared to net issuances of approximately $76 million in 2002. See Note 5 to the consolidated financial statements for the details of Entergy's long-term debt outstanding.
- The net borrowings under Entergy Corporation's credit facilities decreased $500 million in 2003 compared to an increase of $244 million in 2002.
The items causing cash used to increase in 2003 were partially offset by the following:
- Entergy Corporation issued $538 million of long-term notes in 2003 compared to $267 million in 2002.
- The non-nuclear wholesale assets business retired $268 million of long-term debt in 2002 related to the repurchase of the rights to acquire turbines discussed in "Results of Operations" above. Partially 21
Entergy Corporation and Subsidiaties Managemenfs Financial Discussion and Analysis offsetting this was the retirement of the $79 million Top of Iowa wind project debt at its maturity in January 2003.
- Entergy repurchased $8 million of its common stock in 2003'compared to $118 million in 2002.
In a non-cash transaction in 2002, long-term debt was reduced by -$488 million in the sale bf the Damhead Creek plant when the purchaser assumed the Damhead Creek debt along with the acquisition of the plant. Signiflcant Factors and Known Trend' Following are discussions of significant factors. and known trends affecting Entergy's business, including rate regulation and fuel-cost recovery, federal regulation, market and credit risks, and nuclear matters. State and Local Rate Regulation and Fuel-Cost Recovery r 'The rates that the' domestic utility companies and System Energy charge for their services are an important item influencing Entergy's financial position results of operations, and liquidity.' These companies are closely regulated and the rates charged to their customers are determined in regulatory proceedings, except for a portion of Entergy Gulf States' operations. Governmental agencies, including the APSC, the City Council, the LPSC, the MPSC, the PUCT, and the FERC, are primarily responsible for approval of the rates charged to customers. The status of material retail rate proceedings is summarized below and described in more detail in Note 2 to the consolidated financial statements. Authorized I ' ' P, en' ' !I . ',Pr o ceedi , 1 Company ROE Pending Proceedings/Events Entergy Arkansas ...... 11.0% *No base rate cases are pending;. Transition cost. recovery rider approved to collect $8.5 million effective October 2004 with recovery expected over subsequent 16 months. It is likely that a rate filing will-be made i 2005 in connection with the ANO I steam generator and reactor vessel head replacement. - :; , i *. Entergy Gulf States- 10. 9 5 %/ Base rates are currently set, at rates approved. by the: PUCT in June 1999. Texas....................... Entergy Gulf States filed a retail electric rate case with the PUCT. in August 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case. indicating that fntergy Gulf States is still subject to a pte freeze based on an agreement,. approved by PUCT order in 2001, stipulating that a
.. I rate freeze would remain in effect until retail open, access, commenced in Entergy Gulf States' service territory, unless lifted by the PUCT prior thereto.
Entergy Gulf States has appealed this decision and intends to pursue other available remedies, including legislation that would clarify that it is no longer operating under a rate freeze. In February 2005, bills were filed in the Texas legislature that would clarify that Entergy Gulf Stateq isnp longer operating under a rate freeze and specify that retail open access will not commence in Entergy Gulf States' territory until the PUCT.certifies a powerregion. Entergy Gulf States- 11.1% In December 2003, the LPSC staff recommended a $30.6 million rate refund Louisiana.............. and a prospective rate reduction of approximately $50 million as a result of the ninth post-merger earnings analysis (2002). Hearings concluded in May 2004. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement that would resolve, among other dockets, Entergy Gulf States' ninth postmrnerger review, and dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, 2003, and 2004. The proposed settlement currently includes an offer to refind $76 million to Entergy Gulf States' 22
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Louisiana customers through a credit on bills rendered in March 2005, with no immediate change in the current base rates. The settlement also proposes a formula rate plan with an ROE mid-point of 10.65%. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005. Entergy Louisiana ..... 9.7%- In January 2004, Entergy Louisiana filed with the LPSC an application for a 11.3%(1) $167 million base rate increase and an ROE of 11.4%. The currently authorized ROE midpoint is 10.5%. Hearings in this matter concluded in December 2004. Based on the evidence submitted at the hearing, the LPSC staff is recommending approximately a $7 million base rate increase. The LPSC staff proposed the implementation of a formula rate plan that includes a provision for the recovery of incremental capacity costs, including those related to the proposed Perryville acquisition. A decision by the LPSC is expected in mid- to late-March 2005 on these issues. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement with the LPSC that would resolve, among other dockets, dockets established to consider issues concerning the companies' power purchases for the summers of 2001, 2002, 2003, and 2004. The proposed settlement currently includes an offer to refund
$14 million to Entergy Louisiana's customers. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.
Entergy Mississippi... 9.3%- An annual formula rate plan is in place. Entergy Mississippi made its annual 12.2%(2 formula rate plan filing in March 2004 based on a 2003 test year. There was no change in rates based on an adjusted ROE midpoint of 10.77%. Entergy New Orleans 10.25%- The midpoint ROE of the electric and gas plans is 11.25%, with a target equity 12.25%(2 component of the capital structure of 42%. Entergy New Orleans made a formula rate plan filing in April 2004. The City Council ordered that electric and gas rates remain unchanged from levels set in 2003. Entergy New Orleans will file its formula rate plan for the year ended December 31, 2004 by May 1, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in effect based on the December 31, 2004 test year shall continue. System Energy ..10.94% ROE approved by July 2001 FERC order. No cases pending before FERC. (1) Entergy Louisiana's formula rate plan expired with the 2001 test year. Under the expired formula, if Entergy Louisiana earned outside of the bandwidth range, rates would be adjusted on a prospective basis. If earnings were above the bandwidth range, rates would be reduced by 60 percent of the amount necessary to bring earnings down to the top of the bandwidth, and if earnings were below the bandwidth range, rates would be increased by 60 percent of the corresponding shortfall. (2) Under Mississippi law and Entergy Mississippi's formula rate plan, if Entergy Mississippi's earned ROE is above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's rates are reduced by 50 percent of the difference between the earned ROE and the top of the bandwidth. In such circumstaice, Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the point halfway between such earned ROE and the top of the bandwidth - Entergy Mississippi's retail rates are set at that halfway-point ROE; level. (Before the comparison is made of the earned ROE to the bandwidth, the bandwidth can be 'adjusted for performance measures by as much as 1%. Rates are adjusted pursuant to 23
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Entergy Mississippi's formula rate plan, on a prospective basis, only.) In the situation where Entergy Mississippi's earned ROE is not above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the top of the range-of-no-change at the top of the bandwidth. If earnings are below the bandwidth range, rates are increased by 50 percent of
*thedifference between the earned ROE and the bottom of the bandwidth. Under the provisions of Entergy Mississippi's formula rate plan, each annual formula rate plan filing incorporates a revised calculation of the benchmark ROE.
(3) If Entergy New Orleans earns outside the bandwidth range, rates will be adjusted on a prospective basis. Under the gas formula rate plan, if earnings are above the bandwidth range, rates are reduced by 100 percent of the overage, and if below, increased by 100 percent of the shortfall. In addition, if the ROE falls between 11.5% and 12.25%, rates are reduced by 60 percent of the difference (between 11.5% and 12.25%), and if the ROE falls between 10.25% and 11%, rates are increased by 40 percent of the difference (between 10.25% and 11%). Under the electric formula rate plan, rates are adjusted accordingly by 100 percent of the amount of any overage or shortfall. Entergy New Orleans may earn up to. 13.25% under the electric formula rate plan provided that the increase is caused by its share of energy cost savings under the generation performance-based recovery plan. In addition to the regulatory scrutiny connected with base rate proceedings, the domestic utility companies' fuel and purchased power costs recovered from customers are subject to regulatory scrutiny. The domestic utility companies' significant fuel and purchased power cost proceedings are described in Note 2 to the consolidated financial statements. . Federal Regulation - - l : The FERC regulates wholesale rates (including Entergy intrasystem sales pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy's sales of capacity and energy from Grand Gulf I to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power. Sales Agreement. System Agreement Litigation The domestic utility companies historically have engaged in the coordinated planning, construction, and operation of generating and transmission facilities under the terms of an agreement called the System Agreement that has been approved by the' FERC. Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions, of. imprudence by the domestic utility companies in their execution of the System Agreement, and, seek support for local regulatory authority over System Agreement issues. Regarding the proceeding. at the LPSC, Entergy believes that state and local regulators are preempted by federal law from reviewing and deciding System Agreement issues for, themselves. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting FERC rate schedules that are part of the System Agreement, and from subsequently enforcing that 'interpretation. The LPSC interpreted a System Agreement rate schedule in the unrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed the LPSC's decision. In 2003, the U.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the decisions of the LPSC and the Louisiana Supreme rCourt. In February 2004, a FERC ALJ issued, an Initial Decision in the LPSC-initiated proceeding at the FERC. The Initial Decision decided some issues in favor of the relief sought by the LPSC, and decided sonme issues against the relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALJ's Initial. Decision. . Entergy's exceptions to the ALUs Initial Decision include: the practical effect of the Initial Decision is fill. production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the-Initial Decision is inconsistent with the history, structure, and. precedent regarding the Systemir-Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards 24
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis proposed in the Initial Decision are arbitrary and are so complex that they would be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method. If the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average. If the FERC adopts the AL's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALUs Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost. An assessment of the potential effects of the AL's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi; or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mrnBtu for the 1995-2004 period, and averaging $3.43/mmBtu during the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the AL's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mnmBtu in 2005 declining to $4.97/mmBtu by 2009: Average Annual Range of Annual Payments Payments or (Receipts) or (Receipts) for 2005-2009 Period (In Millions) (In Millions) Entergy Arkansas $154 to $281. $215 Entergy Gulf States ($130) to ($15) ($63) Entergy Louisiana ($199) to ($98) ($141) Entergy Mississippi ($16) to $8 $1 Entergy New Orleans ($17) to ($5) ($12) Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. The timing of recovery of these costs in rates could be the subject of additional proceedings at the APSC and elsewhere, however, and a delay in full recovery of any increased allocation of production costs could result in additional financing requirements. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation. In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC AL's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement 25
Entergy Corporation and Subsidiaries Managemenfs Financial Discussion and Analysis is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas.": Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the ALJ's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; and states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate. In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the ALJ's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations. In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a, declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Louisiana, as well as the named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity. Transmission In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs. In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations. Entergy also proposed to have the ICTi administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's 26
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences. In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become
- a. "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the petition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005.
In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion of the proposal currently scheduled for August 2005. FERC's Supply Margin Assessment In November 2001, FERC issued an order that established a new generation market power screen (called Supply Margin Assessment) for purposes of evaluating a utility's request for market-based rate authority, applied that new screen to the Entergy System (among others), determined that Entergy and the others failed the screen within their respective control areas, and ordered these utilities to implement certain mitigation measures as a condition to their continued ability to buy and sell at market-based rates. Among other things, the mitigation measures would require that Entergy transact at cost-based rates when it sells in the hourly wholesale market within its control area. Entergy requested rehearing of the order, and FERC delayed the implementation of certain mitigation measures until such time as it had the opportunity to consider the rehearing request. In June 2003, the FERC proposed and ultimately adopted new market behavior rules and tariff provisions that would be applied to any market-based sale. Entergy modified its market-based rate tariffs to reflect the new provisions but requested rehearing of FERC's order. In April 2004, the FERC issued its Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy. In its April 2004 order, the FERC established a new interim generation market power analysis that will consider two indicative market power screens: (1) the pivotal supplier screen that is designed to measure an applicant's market power based on the applicant's share of uncommitted capacity at the time of the control area market's annual peak demand; and (2) the market share screen that is designed to evaluate an 27
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis applicant's market share of uncommitted capacity on a seasonal basis.- An integrated utility's native load obligation will be reflected in both screens; however, the proxy for native load obligation differs between the screens. For the uncommitted pivotal supplier screen, the proxy for native load is the ayerage of the daily native load peaks during the month in which the annual peak load day occurs; for the uncommitted market share screen the proxy for native load is the minimum peak load day for each season. In the event an applicant fails either of these screens, there will be a rebuttable presumption that market power exists. The applicant will then have the opportunity to either: (1) submit a more detailed market power analysis that reflects market prices and measures an applicant's "economic capacity" and "available economic capacity" under the "delivered price test;" or (2) propose case-specific mitigation tailored to the applicant's specific circumstances or adopt cost-based rates for sales within the applicant's control area . -jC; +/- . l'. i.jŽ;.. *A. i.i _: . Ai .
--j In its April 2004 order, the FERC also: (1) determined that trans-missiobnmaiket pow& and the need to employ an independent entity to operate and administer an applicant's OASIS site is more properly considered in other proceedings, to the extent appropriate, and would not be considered in evaluating an applicant's generation market power for purposes of granting market-based rate authority; and (2) eliminated the exemption from the generation market power analysis for sales within an RTO/ISO that had approved market monitoring, Several parties, including Entergy, filed for rehearing of the April 2004 order. Among other things, Entergy argued that the market share screen is overly conservative and overstates vertically integrated utilities' ability to exercise market power. -- .-< Lu. - ol< i. ' -,. - . I:; f m In July 2004, the FERC issued an order on rehearing reaffirming the use of the pivotal supplier and market share screens and clarified certain instructions for performing such analysis. With regard to the delivered price test analysis, the FERC declined to make a determination on whether an applicant's native load obligations will be reflected when evaluating an applicant's generation market power, but instead indicated that it would evaluate the arguments of both the applicant and intervenors as to which measure (one with or without native load obligations) more accurately reflects market conditions. Entergy appealed the April 2004 and July 2004 orders to the United States Court of Appeals for the District of Columbia Circuit. In February 2005, the D.C. Circuit granted the FERC's motion to dismiss Entergy'sappeal on the grounds that Entergy's claims were premature. The D.C. Circuit found that Entergy's petition w~as prematute because the D.C. Circuit was not yet in a position to evaluate the manner in which the FERC will apply its new market power te'sts r whether the tests will have adverse consequences for Entergy. Thus, the D.C. Circuit did not rule on the-merits of Entergy's appeal. t J
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Entergy filed with the FERC its generation market power analysis pursuant to the two indicative scieens in August 2004. Entergy's analysis indicated that it passed the pivotal supplier screen for all relevant geographical regions, but failed the market share screen within its control area. At the same time, Entergy submitted the results of the delivered price test for Entergy, which indicate that Entergy does not have market power in any wholesale market when Entergy's native load obligations are reflected. I- - I In December 2004, the FERC issued an order pursuant to Section 206 of the Federal Power Act: (1) finding that Entergy failed the market share sciren; (2) indicating that the FERC is continuing to review the delivered price test analysis submitted by Entergy; (3) establishing a refund effective date for Entergy's market-based wholesale sales within its control area; and (4) indicating that the FERC believes that it can reach a decision concerning Entergy's market-based rate authority by the second quarter of 2005. * .
' int;'
s .'tr i.. inuiv' . Jtu ii r:,jZ .3,. . ae tVtsj .-- f'jJ j-,j.a, . i If the FERC were to revoke Entergy's or the domestic utility companies' market-based rate authority for wholesale sales within the Entergy control area, these entities would be limited to making wholesale sales pursuant to cost-based rate schedules approved by the FERC. The wholesale sales of the domestic utility companies and their affiliates, including Entergy's non-nuclear wholesale assets business, within the Entergy control area could either be cost-justified or are of such a limited amount that management does not believe that the revo6ation of their market-based rate authority would have a material effect on the financial results of Entergy. Because Entergy believes that it does not possess market power and that the FERC's tests are flawed, Enteigy intends to vigorously defend its market-based rate authority. . i -fJ,4x 'i; . . L The FERC has also initiated a rulemaking proceeding to address, among other things, whether the FERC should retain or modify its existing four-prong test-for evaliating market-based rate applications (i.e., whether the 28
Entergy Corporation and Subsidiarie's Manageme'nt's Financial Discussion and Analysis applicant has generation or transinissibn market power, whether the applicant can erect barriers to' entty/' and whether there are affiliate abuse or reciprocal dealing concerns), and whether the FERC should adopt different approaches for affiliate transactions. The FERC has held a series of technical conferences to discuss these issues. Additionally, in February 2005 the FERC adopted revised repotiing obligations for changes in statas'that apply to public utilities authorized"to mftake wholesale sales of Oowef at market-based rates. The FERC determined'fb replace the current triennial reporting requirement with more detailed guidelines concerning the types of events that will trigger a reporting obligation and the timing and format for such reports. The new rules will become 'part of all existing market-based rate tariffs during March 2005. Interconnection Orders
" the doiimestic utility -^'cao p (e~xce~pt'e -diOsB ar& 'defendants to sevra '--tritly cditinpjfaints 'and iehe'a#r i' eTh before the FARC in indepini&
iwhich 'tgeneration entities (GeniCos)' ar' eeking a refund of moriies "taithe tGehdsCy' to'ti n 'fb# fhcil ities sary t 'cAle"'t their generitio-n faacilities t6 Enitfts 'fismismo'n sys er.ii:'TheMF Cfihas issuid initial oriders in responsiie it {o of thecomplai'ns and 'ialifother dock ori ordering to refinda pproximatly ' 100 million in ex anid&tax ligaiions previously paid byfhe' G' . rTh're'fuids wit bein ihe form of transission credits th'ai will 6 ver' 'the' GeCI os take tiaAnimi'ssihn eriefrom it.,' I'.-i-' ' 3 me< Ei~ ~~~-',~_', Lf;
;.e:£'
btiW ) ;! i, I1---I,- be' tilized jin4~e's , J al: J v, In addition, Entergy Louisiana was recently directed, effective as of March 2001, to provide transmission credits, with interest, associated with a specific generator that asserted to the FERC that it ietainea In its c hoiracl' fr interconnection a right to execute the latest form of Entergy's standagd interconnection agreement in lieu of its existig contract, whcn thereby wo{uld apply iC's most recent intericoTnnehion cost allocatiin oiicies to that generator. Fowing an ALJ' s nitial Decision and an order afining such decision by FERC, approximately $iJ million in expenses and tax obligations previously paid by the generator have been ordered refunded in the form of transmission credits, to be utilized over time and applied to Entergy transmission service bills incurred after March 260 l.has sougtehst re e rif.g of the BERGC s - .order'. V I< To the exytent the tergy copmpanles are 'ordered to provide such refund§, these kosts will qualify for iin :ithe Eni iis i6n amesni& raties The-re66V~ry' Oi &6-c'ostsfis' not autoratic, howvi' - ii , ' eYiaslly at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal av nuievva iIb1le1 it 'ii ' 16rt'hp"liote veh" thes' 6de )'W irse1 ! the affected int"Er'oTiec'fio
'~dnl!& t teirhst ad'es reed to oiginalfybyt~e gbfenerators.
).
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Available Flowgate Capacity Proceeding On December 17, 2004, the FERC issued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised in a FERC audit report finding 'errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmissicn' requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation Of the AFC program;,1(fi) whether Efifergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's prtvision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory. Entergy has submitted an Eniergency Interim Request for Reheating requesting the FERC to defer ihe hearing process 'and instead proceed initially with an independent audit of the AFC program 'atd the expansion of the current process involving other mark-et participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC' pTrhfit.I Following the completion of the independent audit and process involving other market participants, the FERC could determine'
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis whether other procedural steps are necessary. The FERC has not yet ruled on the, Emergency Interim Request for Rehearing submitted by Entergy. Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the AFC proceeding is currently scheduled to commence in August 2005. Federal Legislation Federal legislation intended to facilitate wholesale competition in the electric power industry has been seriously considered by the United States Congress for the past several years. In the last Congress, both the House and Senate passed separate versions of comprehensive energy legislation, negotiated a conference package, and fell two votes short of bringing the conferenced bill up for a vote in the Senate. The bill contained electricity provisions that would, among other things, allow for participant funding of transmission interconnections and upgrades, repeal PUHCA, repeal or modify PURPA, enact a mechanism for establishing enforceable reliability standards, provide the FERC with new authority over utility mergers and acquisitions, and codify the FERC's authority over market-based rates. It is expected that the United States House and Senate will again craft and consider energy legislation in the 109th Congress. Market and Credit Risks Market risk is the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Entergy is exposed to the following significant market risks:
- The commodity price risk associated with Enterg6's Non-Utility Nuclear and Energy Commodity'Services segments.
- The foreign currency exchange rate risk associated with certain of Entergy's contractual obligations.
- The interest rate and equity price risk associated with Entergy's investments in decommissioning trust funds.
Entergy is also exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Where it is a significant consideration, counterparty credit risk is addressed in the discussions that follow. Commodity Price Risk Power Generation The sale of electricity from the power generation plants owned by Entergy's Non-Utility Nuclear business and Energy Commodity Services, unless otherwise contracted, is subject to the fluctuation of market power prices. Entergy's Non-Utility Nuclear business has entered into PPAs and other contracts to sell the power produced. by its power plants at prices established in the PPAs. Entergy continues to pursue opportunities to extend the existing PPAs and to enter into new PPAs with other parties. Following is a summary of the amount of the Non-Utility Nuclear business' output that is currently sold forward under physical or financial contracts at fixed prices:- 2005 2006 2007 2008 2009 1Non-Utility Nuclear: Percent of planned generation sold forward: Unit-contingent 36% 20% 17% 1% 0% Unit-contingent with availability guarantees 54% - 52%, .38% 25% 0% Firm liquidated damages 4%
- 4% 2% 0%
- 0%
Total 94%. 76% 1 57% 26% 0% ' Planned generation (TWh) 34 35.: 34 34 35 Average contracted price per MWh $39 $41 $42 $44 N/A 30
Entergy Corporati on and Subsidiaries Management's Financial Discussion and Analysis The Vermont Yankee acquisition included a-10-year PPA under which the formerowners will buy the power produced by the plant, which is through the expiration in 2012 of the current operating license for the plant. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward monthly, beginning in November 2005, if power market prices drop below PPA prices. Accordingly, because the price is not fixed, the table above does not report power from that plant as sold forward after November 2005. A sale of power on a unit contingent basis coupled with an availability guarantee provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. To date, Entergy has not incurred any payment obligation to any power purchaser pursuant to an availability guarantee. All of Entergy's outstanding availability guarantees provide for dollar limits on Entergy's maximum liability under such guarantees. Some of the agreements to sell the power produced by Entergy's Non-Utility,Nuclear power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary may be required to provide collateral based upon the difference between the current market and contracted power prices in the regions where the Non-Utility Nuclear business sells its power. The primary form of the collateral to-satisfy these requirements would be an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At December 31, 2004, based on power prices at that time, Entergy had in place as collateral $545.5 million of Entergy Corporation guarantees and $47,5 million of letters of credit. In the event of a decrease in Entergy Corporation's credit rating to specified levels below investment grade, Entergy may be required to replace Entergy Corporation guarantees with cash or letters of credit, under some of the agreements. In addition to selling the power produced by its plants, the Non-Utility Nuclear business sells installed capacity to load-serving distribution companies in order for those companies to meet requirements placed on them by the ISO in their area. Following is a summary of the amount of the Non-Utility Nuclear business' installed capacity that is currently sold forward, and the blended amount of the Non-Utility Nuclear business' planned generation output and installed capacity that is currently sold forward: 2005 2006 2007 2008 2009 Non-Utility Nuclear: Percent of capacity sold forward: Bundled capacity and energy contracts 13% .13% 13% 13% 13% Capacity contracts i . 58% 67% 36% 22% 10% 8 0%/ 49% 35% 23% Total, ;; . - , 71% Planned net MW in operation , - 4,155 4,200 ,200 - 4,200 4,200 Average capacity contract price per kW per month. $1.2- $1.1 $1.1 $1.0 $0.9 Blended Capacity and Energy (based on revenues), % of planned generation and capacity sold forward 93%. 87% 65% 36% 12% Average contract revenue per MWh $40 , $42 -.$43 $44 $43 As of December 31, 2004, approximately 99%/o of Entergy's counterparties to Non-Utility Nuclear's energy and capacity contracts have investment grade credit ratings. 31
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Following is a summary of the amount of Energy Commodity Services' output and installed capacity that is currently sold forward under physical or financial contracts at fixed prices:
-2005 2006 2007 2008 2009 Energy Commodity Services:
Capacity Planned MW in operation 1,578 1,578 1,578 1,578 1,578 % of capacity sold forward 44% 33% 29% 29% 19% Energy Planned generation (TWh) 3 3 3 3 4 % of planned generation sold forward 69% 54% 45% 45% 35% Blended Capacity and Energy (based on revenues! % of planned energy and capacity sold forward 63% 44% 38% 39% 22% Average contract revenue per MWh $24 $24 $28 $28 $21 Entergy continually monitors industry trends in order to determine whether asset impairments or other losses could result from a decline in value, or cancellation, of merchant power projects, and records provisions for impairments and losses accordingly.: As discussed in "Results of Operations" above, in 2004 Entergy determined that the value of the Warren power plant owned by the non-nuclear wholesale assets business was impaired, and recorded the appropriate provision for the loss. Foreign Currency Exchange Rate Risk Entergy Gulf States, System Fuels, and Entergy's Non-Utility Nuclear business enter into foreign currency forward contracts to hedge the Euro-denominated payments due under certain purchase- contracts. The notional amounts of the foreign currency forward contracts are 95.5 million Euro and the forward currency rates range from
.8641 to 1.33020. The maturities of these forward contracts depend on the purchase contract payment dates and range in time from January 2005 to January 2007. The mark-to-market valuation of the forward contracts at December 31, 2004 was a net asset of $28.1 million. The counterparty banks obligated on these agreements are rated by Standard & Poor's Rating Services at AA on their senior debt obligations as of December 31, 2004.
Interest Rate and Eguitv Price Risk - Decommissioning Trust Funds Entergy's nuclear decommissioning trust funds are exposed to fluctuations in equity prices and interest rates. The NRC requires Entergy to maintain trusts to fund the costs of decommissioning ANO 1, ANO 2, River Bend, Waterford 3, Grand Gulf, Pilgrim, Indian Point I and 2, and Vermont Yankee (NYPA currently retains the decommissioning trusts and liabilities for Indian Point 3 and FitzPatrick). The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Managemenit believes that exposure of the various funds to market fluctuations will not affect Entergy's financial results of operations as it relates to the ANO I and 2, River Bend, Grand Gulf, and Waterford 3 trust funds because of the application of regulatory accounting principles. The Pilgrim, Indian Point 1 and 2, and Vermont Yankee trust funds collectively hold approximately $952 million of fixed-rate, fixed-income securities as of December 31, 2004. These securities have an average coupon rate of approximately 5.4%, an average duration of approximately 5.2 years, and an average maturity of approximately 7.9 years. The Pilgrim, Indian Point l'and 2, and Vermont Yankee trust funds also collectively hold equity securities worth approximately $450 million as of December 31, 2004. These securities are generally held in funds that are designed to approximate or somewhat exceed the return of the Standard & Poor's 500 Index, and a relatively small percentage of the securities are held in a fund intended to replicate the return of the Wilshire 4500 Index. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 15 to the consolidated financial statements. 32
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Nuclear Matters The domestic utility companies, System Energy, and Non-Utility Nuclear subsidiaries own and operate ten nuclear power generating units and the shutdown Indian Point 1 nuclear reactor. Entergy is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks from the use, storage, handling, and disposal of high-level and low-level radioactive materials, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shut-down of any of Entergy's nuclear plants, Entergy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel, in particular in the northeastern United States, which is where the Non-Utility Nuclear units are located. These concerns have led to, and are expected to continue to lead to, various proposals to federal regulators as well as governing bodies in some localities where Entergy owns nuclear plants for legislative and regulatory changes that could lead to the shut-down of nuclear units, denial of license extension applications, municipalization of nuclear units, restrictions on nuclear units as a result of unavailability of sites for nuclear fuel disposal, or other adverse effects on owning and operating nuclear power plants. Entergy believes that its generating units are in compliance with NRC requirements and Entergy vigorously responds to these concerns and proposals. Litigation Entergy and its subsidiaries are involved in the ordinary course of business in a substantial amount of employment, commercial, asbestos, hazardous material, and other environmental and rate-related proceedings and litigation. Entergy uses legal and appropriate means to contest vigorously litigation threatened or filed against it, but litigation poses a significant business risk to Entergy. Critical Accounting Estimates The preparation of Entergy's financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy's financial position or results of operations. Nuclear Decommissioning Costs Entergy owns a significant number of nuclear generation facilities in both its U.S. Utility and Non-Utility Nuclear business units. Regulations require Entergy to decommission its nuclear power plants after each facility is taken out of service, and money is collected and deposited in trust funds during the facilities' operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates:
- Cost Escalation Factors - Entergy's decommissioning revenue requirement studies include an assumption that decommissioning costs will escalate over present cost levels by annual factors ranging from approximately CPI-U to 5.5%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11.0%.
- Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant's retirement must be estimated. The expiration of the plant's operating license is typically used for this purpose, or an assumption could be made that the plant 33
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis will be relicensed and operate for some time beyond the original license term. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore" status for later decommissioning, as'permitted by applicable regulations. While the effect of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can possibly change the present value of these obligations. As discussed in Note 8 to the consolidated financial statements, Entergy recorded revisions in 2004 to its estimated decommissioning cost liability for four of its nuclear power plants to reflect changes in assumptions regarding license renewal. Increases in the probability of decommissioning the plants at a date later than the original license expiration lowered the estimate of the decommissioning cost liability. The changes in probability for the unregulated portion of Entergy Gulf States and Entergy's Non-Utility Nuclear business increased income by approximately $28.9 million net-of-tax for the excess of the reduction in the liability over the amount of undepreciated asset retirement cost at the time of adoption of SFAS 143. The changes in probability for ANO I and ANO 2 had no effect on net income because, as discussed further below, any amounts recorded related to SFAS 143 are offset by the recording of regulatory assets or regulatory liabilities when projected decommissioning costs are collected in rates. Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will affect net income, only to the extent that the estimate of any reduction in the liability exceeds the amount of the undepreciated asset retirement cost at the date of the revision, for unregulated portions of Entergy's business. Any increases in the liability recorded due to such changes are capitalized and depreciated over the asset's remaining economic life in accordance with SFAS 143.
- Spent Fuel Disposal - Federal regulations require the DOE to provide a permanent repository for the storage of spent nuclear fuel, and legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. Until this site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities can have a significant effect (as much as 16% of estimated decommissioning costs). Entergy's decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
- Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. 'As experience is gained and technology changes, cost estimates could also change. If regulations regardin'g nuclear decommissioning were to change, this' could
have a potentially significant effect on cost estimates. The effect of these potential changes' is not presently determinable. Entergy's decommissioning cost studies assume current technologies and regulations.
SFAS 143 ' Entergy implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy's asset retirement obligations, and the measurement and recording of Entergy's decommissioning obligations changed significantly with the impleinentation of SFAS 143. The most 'significant differences in the measurement of these obligations are outlined below:
- Recording of full obligation - SFAS 143 requires that the fair value of an asset'retirement obligation be recorded when it is incurred. This caused the recorded decommissioning obligation in Entergy's U.S.
Utility business to increase significantly, as Entergy had previously only recorded this obligation as the related costs were collected from customers, and as earnings were recorded on the related trust funds.
- Fair value approach - SFAS 143 requires that these obligations be measured using a fair value approach.
Among other things, this entails the assumption that the costs will be incurred by a third party and will therefore include appropriate profit margins and risk' remiums. Entergy's decommissioning studies had been based on Entergy performing the work, and did not include any such margins or ptemiumsn.
- Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted,'risk-fre' rate. - - '
34
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis The net effect on Entergy's financial statements of implementing SFAS 143 for the U.S. Utility and Non-Utility Nuclear businesses follows:
- For the U.S. Utility business, the implementation of SFAS 143 for the rate-regulated business of the domestic utility companies and System Energy was recorded as regulatory assets, with no resulting effect on Entergy's net income. Entergy recorded these regulatory assets because existing rate mechanisms in each jurisdiction are based on the original or historical cost standard that allows Entergy to recover all ultimate costs of decommissioning existing assets from current and future customers. As a result of this treatment, SFAS 143 is expected to be earnings neutral to the rate-regulated business of the domestic utility companies and System Energy. Upon implementation of SFAS 143 in 2003, assets and liabilities increased by $1.1 billion for the U.S. Utility segment as a result of recording the asset retirement obligations at their fair values of $1.1 billion as determined under SFAS 143, increasing utility plant by $288 million, reducing accumulated depreciation by $361 million and recording the related regulatory assets of $422 million. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking decreased earnings by $21 million net-of-tax ($0.09 per share) as a result of a one-time cumulative effect of accounting change. In accordance with ratemaking treatment and as required by SFAS 71, the depreciation provisions for Entergy's utility subsidiaries include a component for removal costs that are not asset retirement obligations under SFAS 143. Approximately 6% of the U.S. Utility's current depreciation rates, on a weighted-average basis, represents a component for the net of salvage value and removal costs.
- For the Non-Utility Nuclear business, the implementation of SFAS 143 in 2003 resulted in a decrease in liabilities of $595 million due to reductions in decommissioning liabilities, a decrease in assets of $340 million, including a decrease in electric plant in service of $315 million, and an increase in earnings of
$155 million net-of-tax as a result of the one-time cumulative effect of accounting change.
Also, beginning in 2003 Entergy's earnings for the Non-Utility Nuclear business have an increase of $18 million after-tax because of the change in accretion of the liability and depreciation of the adjusted plant costs from the 2002 levels. This effect will gradually decrease over future years as the accretion of the liability increases. Management expects that applying SFAS 143 post-implementation will have a minimal effect on ongoing earnings for the U.S. Utility business. In the first quarter of 2004, Entergy Arkansas recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for ANO I and 2 as a result of revised decommissioning costs and changes in assumptions regarding the timing of when the decommissioning of the plants will begin. The revised estimate resulted in a $107.7 million reduction in its decommissioning liability, along with a $19.5 million reduction in utility plant and an $88.2 million reduction in the related regulatory asset. In the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected an expected life extension for the plant. The revised estimate resulted in a $116.8 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $40.1 million reduction in the related regulatory asset, and a regulatory liability of $17.7 million. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million. In the third quarter of 2004, Entergy's Non-Utility Nuclear business recorded a reduction of $20.3 million in its decommissioning cost liability to reflect changes in assumptions regarding the timing of when the decommissioning of a plant will begin. Entergy considered the assumptions as part of recent studies evaluating the economic effect of the plant in its region. The revised estimate resulted in miscellaneous income of $20.3 million, reflecting the excess of the reduction in the liability over the amount of undepreciated asset retirement cost recorded at the time of adoption of SFAS 143. 35
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Unbilled Revenue-As discussed in Note I to the consolidated financial statements, Entergy records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month, including fuel price. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period and fuel price fluctuations, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regarding price such as the fuel cost recovery mechanism. Impairment of Long-lived Assets Entergy has significant investments in long-lived assets in all of its segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment whenever there are indications that impairments may exist. This evaluation involves a significant degree of estimation and uncertainty, and these estimates are particularly important in Entergy's U.S. Utility and Energy Commodity Services segments. In the U.S. Utility segment, portions of River Bend and Grand Gulf are not included in rate base, which could reduce the revenue that would otherwise be recovered for the applicable portions of those units' generation. In the Energy Commodity Services segment, Entergy's investments in merchant generation assets are subject to impairment if adverse market conditions arise. In order to determine if Entergy should recognize an impairment of a long-lived asset that is to be held and used, accounting standards require that the sum of the expected undiscounted future cash flows from the asset be compared to the asset's carrying value. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded; if such cash flows are less than the carrying value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value. These estimates are based on a number of key assumptions, including:
- Future power and fuel prices - Electricity and gas prices have been very volatile in recent years, and this volatility is expected to continue. This volatility necessarily increases the imprecision inherent in the long-,
term forecasts of commodity prices that are a key determinant of estimated future cash flows. There is currently an oversupply of electricity throughout the U.S., including much of Entergy's service territory, and it is necessary to project economic growth and other macroeconomic factors in order to project when this oversupply will cease and prices will rise. Similarly, gas prices have been volatile as a result of recent fluctuations in both supply and demand, and projecting future trends in these prices is difficult.
- Market value of generation assets - Valuing assets held for sale requires estimating the current muarket value of generation assets. While market transactions provide evidence for this valuation, the market for such;'
assets is volatile and the value of individual assets is impacted by factors unique to those assets.'
- Future operating costs - Entergy assumes relatively minor annual increases in operating costs.
Technological or regulatory changes that have a significant impact on operations could cause a significant change in these assumptions. Due to the oversupply of power that existed throughout the U.S. and the UK in 2002, and the resulting decreases in spark spreads, consistent with Entergy's point of view, Entergy's impairment tests indicated that a number of impairments were required to be recognized in 2002 in the Energy Commodity Services segment. These impairments, which were also accompanied by other charges related to the restructuring of Entergy's independent power business, are further detailed in Note 11 to the consolidated financial statements. 36
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis In 2004, Entergy recorded a charge of approximately $55 million ($36 million net-of-tax) as a result of an impairment of the value of the Warren Power plant. Entergy concluded that the value of the plant, which is owned in the non-nuclear wholesale assets business, was impaired. Entergy reached this conclusion based on valuation studies prepared in connection with the Entergy Asset Management stock sale discussed above in "Results of Operations." Pension and Other Postretirement Benefits Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 10 to the consolidated financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate for the U.S. Utility and Non-Utility Nuclear segments. Assumptions Key actuarial assumptions utilized in determining these costs include:
- Discount rates used in determining the future benefit obligations;
- Projected health care cost trend rates;
- Expected long-term rate of return on plan assets; and
- Rate of increase in future compensation levels.
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and worse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions. In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 6.75% in 2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to -a10% increase in health care costs in 2005 gradually decreasing each successive year, until it reaches a 4.5% annual increase in health care costs in 2011 and beyond. In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities and 4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities' and 49% fixed income securities. Based on recent market trends, Entergy reduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 8.75% for 2002 and 2003 to 8.5% in 2004. The assumed rate-of increase in future compensation levels used to calculate benefit obligations was 3.25% in 2002, 2003, and 2004. 37
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Cost Sensitivity The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (in thousands): Change in Impact on 2004 Impact on Projected Actuarial Assumption Assumption Pension Cost Benefit Obligation Increase/(Decrease) Discount rate (0.25%) $10,268 $94,903 Rate of return on plan assets (0.25%) $4,388 Rate of increase in compensation 0.25% $4,928 $29,134 The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (in thousands): Impact on Accumulated Change in Impact on 2004 Postretirement Benefit Actuarial Assumption Assumption Postretirement Benefit Cost Obligation Increase/(Decrease) Health care cost trend 0.25% $4,150 $23,892 Discount rate (0.25%) $2,715 $28,719 Each fluctuation above assumes that the other components of the calculation are held constant. Accounting Mechanisms In accordance with SFAS No. 87, "Employers' Accounting for Pensions," Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into cost only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. Additionally, Entergy accounts for the effect of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted, as previously deferred gains or losses are recognized. As a result, the, losses that the pension plan assets experienced in 2062 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87. Costs and Funding In 2004,. Entergy's total pension cost was $98 million. Entergy anticipates 2005 pension cost to increase to $117 million due to decreases in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75%. to 8.5%) used to calculate benefit obligations. Pension funding was $73 million for 2004 and in 2005 is projected to be $186 million. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, offset by the Pension Funding Equity Act relief passed in April 2004. Entergy's accumulated benefit obligation at December 31, 2004, 2003, and 2002 exceeded plan assets. As a result, Entergy was required to recognize an additional minimum pension liability as prescribed by SFAS 87. At December 31, 2004, Entergy increased its additional minimum pension liability to $244 million ($218 million net of related pension assets) from $180 million ($149 million net of related pension assets) at December 31, 2003. Other comprehensive income decreased to $6.6 million at December 31, 2004 from $9.3 million at December 31, 2003, after reductions for the unrecognized prior service cost, amounts recoverable in rates, and taxes. Net income for 2004, 2003, and 2002 was not affected. 38
Entergy Corporation and Subsidiaries Management's Financial Discussion and Analysis Total postretirement health care and life insurance benefit costs for Entergy in 2004 were $86 million, including $23 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy expects 2005 postretirement health care and life insurance benefit costs to approximate $96 million, including a projected $27 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the decrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate used to calculate benefit obligations. Other Contingencies Entergy, as a company with multi-state domestic utility operations, and which also had investments in international projects, is subject to a number of federal, state, and international laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles. Environmental Entergy must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. Under these various laws and regulations, Entergy could incur substantial costs to restore properties consistent with the various standards. Entergy conducts studies to determine the extent of any required remediation and has recorded reserves based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites could be identified which require environmental remediation for which Entergy could be liable. The amounts of environmental reserves recorded can be significantly affected by the following external events or conditions:
- Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.
- The identification of additional sites or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.
- The resolution or progression of existing matters through the court system or resolution by the EPA.
Litigation Entergy has been named as defendant in a number of lawsuits involving employment, ratepayer, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably estimable, or remote and records reserves for cases which have a probable likelihood of loss and can be estimated. Notes 2 and 8 to the consolidated financial statements include more detail on ratepayer and other lawsuits and management's assessment of the adequacy of reserves recorded for these matters. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, however, the ultimate outcome of the litigation Entergy is exposed to has the potential to materially affect the results of operations of Entergy, or its operating company subsidiaries. Sales Warranty and Tax Reserves Entergy's operations, including acquisitions and divestitures, require Entergy to evaluate risks such as the potential tax effects of a transaction, or warranties made in connection with such a transaction. Entergy believes that it has adequately assessed and provided for these types of risks, where applicable. Any reserves recorded for these types of issues, however, could be significantly affected by events such as claims made by third parties under warranties, additional transactions contemplated by Entergy, or completion of reviews of the tax treatment of certain transactions or issues by taxing authorities. Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued in the financial statements. Entergy does not expect a material adverse effect on earnings from these matters. 39
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ENTERGY CORPORATION AND SUBSIDIARIES SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 2004 2003 2002 2001 2000 (In Thousands, Except Percentages and Per Share Amounts) Operating revenues $10,123,724 $9,194,920 $8,305,035 $9,620,899 $10,022,129 Income before cumulative effect of accounting change $933,049 $813,393 $623,072 $727,025 $710,915 Earnings per share before cumulative effect of accounting change Basic $4.01 $3.48 $2.69 $3.18 $3.00 Diluted $3.93 $3.42 $2.64 $3.13 $2.97 Dividends declared per share $1.89 $1.60 $1.34 $1.28 $1.22 Return on common equity 10.70% 11.21% 7.85% 10.04% 9.62% Book value per share, year-end $38.25 $38.02 $35.24 $33.78 $31.89 Total assets $28,310,777 $28,527,388 $27,504,366 $25,910,311 $25,451,896 Long-term obligations (1) $7,180,291 $7,497,690 $7,488,919 $7,743,298 $8,214,724 (1) Includes long-term debt (excluding currently maturing debt), preferred stock with sinking fund, and noncurrent capital lease obligations. 2004 2003, 2002 2001 2000 (Dollars In Millions) : Electric Operating Revenues: Residential - i $2,842 $2,683 $2,440 $2,613 $2,525 Commercial 2,045 1,882 1,673 1,860 1,700 Industrial 2,311 2,082 1,850 2,299 2,177 Governmental 200, 195 179 205 185 Total retail i 7,398 6,842 6,142 6,977 6,587 Sales for resale 390 371 330 395 424 Other (1) 145 184 174 - (127) 209 Total ' $7,933 $7,397 - $6,646 $7,245 $7,,20 Billed Electric Energy Sales (GWh): Residential 32,897 32,817 32,581 31,080 I 31,998 Commercial 26,468 25,863 25,354 24,706 24,657 Industrial 40,293 38,637 41,018 i '41,577 ' 43,956 Governmental 2,568 2,651 2,678 2,593 2,605 Total retail 102,226 99,968 101,631 99,956 103,216 Sales for resale 8,623 9,248 9,828. 8,896 9,794 Total 110,849 109,216 111,459 108,852 113,010 (1) 2001 includes the effect of a reserve for rate refund at System Energy. 41
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders Entergy Corporation: We have audited the accompanying consolidated balance sheets of Entergy Corporation and subsidiaries (the "Corporation") as of December 31, 2004 and 2003, and the related consolidated statements of income; of retained earnings, comprehensive income, and paid-in capital; and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Entergy-Koch, LP, the Corporation's investment in which is accounted for by the use of the equity method. The Corporation's equity in earnings of unconsolidated equity affiliates for the year ended December 31, 2003 includes $180,110,000 for Entergy Koch, LP, which earnings were audited by other auditors whose report (which as to 2003 included an explanatory paragraph concerning a change in accounting for inventory held for trading purposes and energy trading contracts not qualifying as derivatives) has been furnished to us, and our opinion for the year ended December 31, 2003, insofar as it relates to the amount audited by other auditors included for such company, is based solely on the report of such other auditors. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors- provide a reasonable basis for our opinion. In our opinion, based on our audits and the report of other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. As discussed in Notes 1, 5 and 8 to the Form 10-K consolidated financial statements, Entergy Corporation adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, and Statement of Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable InterestEntities, in 2003, and SFAS No. 142, Goodwill and OtherIntangibleAssets, in 2002. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Corporation's internal control over financial reporting as of Decembler 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Corporation's internal control over financial reporting and an unqualified opinion on the effectiveness of the Corporation's internal control over financial reporting. DELOITTE & TOUCHE LLP New Orleans, Louisiana March 8, 2005 42
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December31, 2004 2003 2002 (I. Thousands, Except Share Data) OPERATING REVENUES Domestic electric $7,932,577 $7,397,175 $6,646,414 Natural gas 208,499 , ,j 186,176 : 125,353 Competitive businesses , 1,982,648 1,611,569 1,533,268 -. TOTAL 10,123,724 9,194,920 8,305,035 OPERATING EXPENSES Operating and Maintenance: Fuel, fuel-related expenses, and gas purchased for resale 2,488,208 *1,987,217 2,154,596 Purchased power 2,092,922 1,728,526 833,829 Nuclear refueling outage expenses 166,072 159,995 105,592 Provisions for turbine commitments, asset impairments and restructuring charges 55,000 (7,743)' - 428,456 Other operation and maintenance 2,303,561 2,453,869 2,486,617 Decommissioning 149,529 146,100 76,417 Taxes other than income taxes 409,886 405,659 380,462 Depreciation and amortization 895,593 850,503 839,181 Other regulatory credits - net (90,611) (13,761) (141,836) TOTAL 8,470,160 7,710,365 7,163,314 OPERATING INCOME 1,653,564 1,484,555 1,141,721, i . . . OTHER-INCOME Allowance for equity funds used during construction 39,582 42,710 31,658 Interest and dividend income 109,809 . 87,386 i 118,325 Equity in earnings (loss) of unconsolidated equity affiliates (78,727) 271,647 183,878 Miscellaneous - net 53,752 (76,505) 13,892 TOTAL - 124,416
- - -325,238 -- - 347,753.
INTEREST AND OTHER CHARGES Interest on long-term debt 463,384 485,964 526,442 Other interest - net 41,380 533,553 ' 70,560 Allowance for borrowed funds used during construction (25,741) (I3,191) (24,538) TOTAL - 479,023 506,326 '- 572,464 I I 9: : .7 . 3 INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGES - 1,298,957 ' 1,303,467 r .' ;917,010' I . Income taxes 365,908 490,074 293,938
,- I . I. .- : I ,
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES 933,049 813,393 i 623,072 CUMULATIVE EFFECT OF ACCOUNTING CHANGES (net of Income taxes of S89,925) 137,074 CONSOLIDATED NET INCOME 933,049 950,467 623,072 Preferred dividend requirements and other 23,525 23,524 23,712 EARNINGS APPLICABLE TO COMMON STOCK $909,524 $926,943 S599,360 Earnings per average common share before cumulative effect ofaccounting changes: Basic $4.01 $3A8 $2.69 Diluted S3.93 S3.42 $2.64 Earnings per average common share: Basic $4.01 $4.09 $2.69 Diluted $3.93 $4.01 $2.64 Dividends declared per common share $1.89 $1.60 $1.34 Average number of common shares outstanding: Basic 226,863,758 226,804,370 223,047,431 Diluted 231.193.686 231.146.040 227.303.103 See Notes to Consolidated Financial Statements. 43
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2004 2003 2002 (In Thousands) OPERATING ACTIVITIES Consolidated net income . .. $933,049 $950,467 $623,072 Adjustments to reconcile consolidated net income to net cash flow provided by operating activities: Reserve for regulatory adjustments 33;533. - 13,090 18,848 Other regulatory credits - net (90,611) (13,761) (141,836) Depreciation, amortization, and decommissioning 1,045,122 996,603 915,597 Deferred income taxes and investment tax credits 275,458 1,189,531 (256,664) Cumulative effect of accounting changes (137,074) Equity in earnings (loss) of unconsolidated equity affiliates - net of dividends 608,141 (176,036) (181,878) Provisions for turbine commitments, asset impairments, and restructuring charges 55,000 (7,743) 428,456 Changes in working capital: Receivables (2 10,419) (140,612), (43,957) Fuel inventory (16,769) (14,015) 1,030 Accounts payable 95,306 (60,164) 286,230 Taxes accrued 75,055 (882,446) 462,956 Interest accrued 5,269 (35,837) 7,209 Deferred fuel 213,627 (33,874) 156,181 Other working capital accounts 41,008'.
- 16,809 (286,232)
Provision for estimated losses and reserves (18,041) 196,619 10,533 Changes in other regulatory assets 48,626 22,671 71,132 Other (164,035)
- 121,592 111,026 Net cash flow provided by operating activities 2,929,319 2,005,820 2,181,703 INVESTING ACTIVITIES Construction/capital expenditures - - (1,410,610) (1,568,943) (1,530,301)
Allowance for equity funds used during construction 39,582 42,710 31,658 Nuclear fuel purchases . (238,170) - ' (224,308> (250,309) Proceeds from sale/leaseback of nuclear fuel 109,988 150,135 183,664 Proceeds from sale of assets and businesses 75,430 25,987 215,088 Investment in nonutility properties -- (6,420) (71,438) (216,956) Decrease in other investments - 383,498 172,187 38,964 Changes in other temporary investments 50,000 . (50,000)., 150,000 Decommissioning trust contributions and realized change in trust assets (89,807) (91,518) (84,914) Other regulatory investments (53,566) (156,446) (39,390) Other ., - (11,496) 114,033 Net cash flow used in investing activities (1,140,075) (1,783,130) (1,388,463)
- . - t' - - C;.:
See Notes to Consolidated Financial Statements.
,;W 44
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2004 2003 2002 (In Thousands) FINANCING ACTIVITIES Proceeds from the issuance of: Long-term debt 1,059,824 - 2,221,164 1,197,330 Common stock and treasury stock 170,237 217,521 130,061 Retirement of long-term debt (1,478,894) (2,409,917) (1,341,274) Repurchase of common stock (1,017,996) (8,135) (118,499) Redemption of preferred stock (3,450) (3,450) (1,858) Changes in credit line borrowings - net 49,846 (499,975) 244,333 Dividends paid: Common stock (427,901) (362,814). (298,991) Preferred stock (23,525) (23,524) (23,712) Net cash flow used in financing activities (1,671,859) (869,130) (212,610) Effect of exchange rates on cash and cash equivalents (1,882) 3,345 3,125 Net increase (decrease) in cash and cash equivalents 115,503 (643,095) 583,755 Cash and cash equivalents at beginning of period 692,233 1,335,328 751,573 Cash and cash equivalents at end of period $807,736 $692,233 $1,335,328 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized S477,768 $552,017 $633,931 Income taxes $28,241 $188,709 $57,856 Noncash investing and financing activities: Debt assumed by the Damhead Creek purchaser $488,432 Decommissioning trust funds acquired in nuclear power plant acquisitions $310,000 Long-term debt refunded with proceeds from long-term debt issued in prior period ($47,000) See Notes to Consolidated Financial Statements. a , : s 45
ENTERGY CORPORATION AND SUBSIDIARIES
- CONSOLIDATED BALANCE SHEETS, ,
ASSETS December 31, 2004 2003 (In Thousands) CURRENT ASSETS Cash and cash equivalents: Cash $79,136 $115,112 Temporary cash investments- at cost, which approximates market. 728,600 576,813 Special deposits 308 Total cash and cash equivalents 807,736 692,233 Other temporary investments 50,000 Notes receivable 3,092 1,730 Accounts receivable: Customer -- 435,191 398,091 Allowance for doubtful accounts (23,758) (25,976) Other 342,289 246,824 Accrued unbilled revenues 460,039 384,860 Total receivables 1,213,761 1,003,799 Deferred fuel costs 85,911 245,973 Accumulated deferred income taxes 76,899 Fuel inventory - at average cost. 127,251 110,482 Materials and supplies - at average cost 569,407 548,921 Deferred nuclear refueling outage costs 107,782 138,836 Prepayments and other 116,279 127,270 TOTAL 3,108,118 2,919,244 OTHER PROPERTY AND INVESTMENTS ji';, ,' ; !, ' Investment in affiliates - at equity 231,779 1,053,328 . Decommissioning trust funds 2,453,406 2,278,533 Non-utility property - at cost (less accumulated depreciation) 219,717 262,384 -.. ,; Other 90,992 152,681. TOTAL 2,995,894 3,746,926 PROPERTY, PLANT AND EQUIPMENT Electric 29,053,340 28,035,899 Property under capital lease 738,554 751,815 Natural gas 262,787 236,622 Construction work in progress 1,197,551 1,380,982 Nuclear fuel under capital lease 262,469 278,683 Nuclear fuel 320,813 234,421 TOTAL PROPERTY, PLANT AND EQUIPMENT 31,835,514 30,918,422 Less - accumulated depreciation and amortization 13,139,883 12,619,625 PROPERTY, PLANT AND EQUIPMENT - NET 18,695,631 18,298,797 DEFERRED DEBITS AND OTHER ASSETS Regulatory assets: SFAS 109 regulatory asset - net 746,413 830,539 Other regulatory assets 1,429,261 1,398,323 Long-term receivables 39,417 20,886 Goodwill 377,172 377,172 Other 918,871 935,501 TOTAL 3,511,134 3,562,421 TOTAL ASSETS S28,310,777 $28,527,388 See Notes to Consolidated Financial Statements. 46
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS LIABILITIES AND SHAREHOLDERS' EQUITY December 31, 2004 2003 (In Thousands) CURRENT LIABILITIES Currently maturing long-term debt $492,564 $524,372 Notes payable 193 351 Accounts payable 896,528 796,572 Customer deposits 222,320 199,620 Taxes accrued 224,011 224,926 Accumulated deferred income taxes 22,963 Nuclear refueling outage costs 8,238 Interest accrued 144,478 139,603 Obligations under capital leases 133,847 159,978 Other 218,442 145,453 TOTAL 2,332,383 2,222,076 NON-CURRENT LIABILITIES Accumulated deferred income taxes and taxes accrued 5,067,381 4,779,513 Accumulated deferred investment tax credits 399,228 420,248 Obligations under capital leases 146,060 153,898 Other regulatory liabilities 329,767 291,239 Decommissioning and retirement cost liabilities 2,066,277 2,215,490 Transition to competition 79,101 79,098 Regulatory reserves 103,061 69,528 Accumulated provisions 549,914 506,960 Long-term debt 7,016,831 7,322,940 Preferred stock with sinking fund 17,400 20,852 Other ,541331 1,407,551 TOTAL 17,316,351 17,267,317 Commitments and Contingencies Preferred stock without sinking fund 365,356 334,337 SHAREHOLDERS' EQUITY Common stock, $.01 par value, authorized 500,000,000 shares; issued 248,174,087 shares in 2004 and in 2003 2,482 2,482 Paid-in capital 4,835,375 4,767,615 Retained earnings 4,984,302 4,502,508 Accumulated other comprehensive loss (93,453) (7,795) Less - treasury stock, at cost (31,345,028 shares in 2004 and 19,276,445 shares in 2003) 1,432,019 561,152 TOTAL 8,296,687 8,703,658 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY S28,310,777 S28,527,388 See Notes to Consolidated Financial Statements. 47
; ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS, COMPREHENSIVE INCOME, AND PAID-IN CAPITAL For the Years Ended December 31, 2004 2003 2002 (In Thousands)
RETAINED EARNINGS Retained Earnings - Beginning of period $4,502,508 $3,938,693 $3,638,448 Add: Earnings applicable to common stock 909,524 $909,524 926,943 $926,943 599,360 $599,360 Deduct: Dividends declared on common stock 427,740 362,941 299,031 Capital stock and other expenses (10) 187 84 Total 427,730 363,128 299,115 Retained Earnings - End of period $4,984,302 $4,502,508 - $3,938,693 ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Net of taxes): Balance at beginning of period: Accumulated derivative instrument fair value changes (325,811) $17,313 ($17,973) Other accumulated comprehensive income (loss) items 18,016 (39,673) (70,821) Total (7,795) (22,360) (88,794) Net derivative instrument fair value changes arising during the period (I115,600) (I115,600) (43,124) (43,124). 35,286 35,286 Foreign currency translation 1,882 1,882 4,169 4,169 65,948 (15,487) Minimum pension liability 2,762 2,762 1,153 1,153 (10,489) (10,489) Net unrealized investment gains (losses) . 25,298 25,298 52,367 52,367- ' (24,311) (24,311) Balance at end of period-Accumulated derivative instrument fair value changes (141,41 1) (25,81 1) 17,313 Other accumulated comprehensive income (loss) items 47,958 18,016 $ . .1 *- (39,673) Total ($93,453) ($7,795) ($22,360) Comprehensive Income $823,866 x $941,508 $584,359 PAID-IN CAPITAL Paid-in Capital - Beginning of period S4,767,615 $4,666,753 $4,662,704 Add: Common stock issuances related to stock plans - 100,862 4,049
$4,7I ,6.
Paid-in Capital - End of period $4,835,375 S4,767,615 S4,666,753 See Notes to Consolidated Financial Statements. 48
ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES The accompanying consolidated financial statements include the accounts of Entergy Corporation and its direct and indirect subsidiaries. As required by generally accepted accounting principles, all significant intercompany transactions have been eliminated in the consolidated financial statements. The domestic utility companies and System Energy maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications, with no effect on net income or shareholders' equity. Use of Estimates in the Preparation of Financial Statements The preparation of Entergy Corporation's consolidated financial statements, in conformity with generally accepted accounting principles, requires management to make estimates and assumptions, that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used. Revenues and Fuel Costs The domestic utility companies generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, including the City of New Orleans, Mississippi, and Texas. Entergy Gulf States distributes gas to retail customers in and around Baton Rouge, Louisiana and Entergy New Orleans distributes gas to retail customers in the City of New Orleans. Entergy's Non-Utility Nuclear and Energy Commodity Services segments derive almost all of their revenue from sales of electric power generated by plants owned by them. Entergy recognizes revenue from electric power and gas sales when it delivers power or gas to its customers. To the extent that deliveries have occurred but a bill has not been issued, the domestic utility companies accrue an estimate of the revenues for energy delivered since the latest billings. Entergy calculates the estimate based upon several factors including billings through the last billing cycle in a month' actual generation in the month, historical line loss factors, and prices in effect in the domestic utility companies' various jurisdictions. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are so recorded and reversed. The domestic utility companies' rate schedules include either, fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Because the fuel adjustment clause mechanism allows monthly adjustments to recover fuel costs, Entergy Louisiana, Entergy New Orleans, and the Louisiana portion of Entergy Gulf States include a component of fuel cost recovery in their unbilled revenue calculations. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. Entergy Mississippi's fuel factor includes an energy cost rider that is adjusted quarterly. As discussed in Note 2 to the consolidated financial statements, the MPSC approved Entergy Mississippi's deferral of the refund of over-recoveries for the third quarter of 2004 that would have been refunded in the first quarter of 2005. The deferred amount plus carrying charges will be refunded in the second and third quarters of 2005. In the case of Entergy Arkansas and the Texas portion of Entergy Gulf States, their fuel' under-recoveries are treated as regulatory investments in the cash flow statements because those companies are allowed by their regulatory jurisdictions to recover the fuel cost regulatory asset over longer than a twelve-month period, and the companies earn a carrying charge on the under-recovered balances. 49
Entergy Corporation Notes to Consolidated Financial Statements System Energy's operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy's common equity funds allocable to its net investment in Grand Gulf, plus System Energy's effective interest cost for its debt allocable to its investment in Grand Gulf. Property. Plant, and Equipment Property, plant, and equipment is stated at original cost. For the domestic utility companies and System Energy, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the domestic utility companies' and System Energy's plant is subject to mortgage liens. Electric plant includes the portions of Grand Gulf and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions. Net property, plant, and equipment by business segment and functional category, as of December 31, 2004 and 2003, is shown below: Energy U.S. Non-Utility Commodity. Parent and 2004 Entergy Utility Nuclear Services-_ Other (In Millions) Production Nuclear $7,308 $5,987 $1,321 Other 1,533 1,228 305 Transmission 2,182 2,182 Distribution 4,672 4,672 Other 1,123 1,115 8 Construction work in progress 1,198 924 244 2 28 Nuclear fuel (leased and owned) 583 297 286. Asset retirement obligation ; - 97 97 6 Pr perty, plant, and equipment - net $18,696 $16,502 $1,851 $307 $36 I . Energy U.S. Non-Utility Commodity Parent and 2003 Entergy Utility Nuclear Services Other (In Millions) Production Nuclear $7,056 $6,112 $944 Other 1,816.
- 1,359 457 Transmission , 2,067 2,067 Distribution 4,231 4,231 Other i,079 1,069 10 Construction work in progress 1,381 954 398 29 Nuclear fuel (leased and owned) 513 298 215 Asset retirement obligation 156
$ .6, 2155 7 $
Property, plant, and equipment - net $18,299 .$16,245 - $1,557 $458 $39 50
Entergy Corporation Notes to Consolidated Financial Statements Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property. Depreciation rates on average depreciable property approximated 2.8% in 2004 and 2003, and 2.9% in 2002. Included in these rates are the depreciation rates on average depreciable utility property of 2.7% in 2004 and 2.8% in 2003 and 2002 and the depreciation rates on average depreciable non-utility property of 3.8% in 2004, 3.3% in 2003, and 4.0% in 2002. Non-utility property - at cost (less accumulated depreciation) is reported net of accumulated depreciation of
$152.8 million and $145.2 million as of December 31, 2004 and 2003, respectively.
Jointly-Owned Generating Stations Certain Entergy subsidiaries jointly own electric generating facilities with third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2004, the subsidiaries' investment and accumulated depreciation in each of these generating stations were as follows: Total Megawatt Accumulated Generating Stations Fuel-Type Capability (1) Ownership Investment Depreciation (In Millions) U.S. Utility: Grand Gulf Unit 1 Nuclear 1,270 90.00% (2) $3,702 $1,780 Independence Units I and 2 Coal 1,630 47.90% $462 $249 White Bluff Units 1 and 2 Coal 1,635 57.00% $428 $264 Roy S. Nelson Unit 6 Coal 550 60.90% $403 $241 Big Cajun 2 Unit 3 Coal 575 42.00% $233 $128 Energy Commodity Services: Harrison County Gas 550 61.00% $209 $7 Warren Gas 300 75.00% $24 $9 (1) "Total Megawatt Capability" is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. (2) Includes an 11.5% leasehold interest held by System Energy. System Energy's Grand Gulf lease obligations are discussed in Note 9 to the consolidated financial statements. Nuclear Refueling Outage Costs Entergy records nuclear refueling outage costs in accordance with regulatory treatment and the matching principle. These refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line. Except for the River Bend plant, the costs are deferred during the outage and amortized over the period to the next outage. In accordance with the regulatory treatment of the River Bend plant, River Bend's costs are accrued in advance and included in the cost of service used to establish retail rates. Entergy Gulf States relieves the accrued liability when it incurs costs during the next River Bend outage. Allowance for Funds Used During Construction (AFUDC) AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction in the U.S. Utility segment. Although AFUDC increases both the plant balance and earnings, it is realized in cash through depreciation provisions included in rates. 51
Entergy Corporation Notes to Consolidated Financial Statements Income Taxes Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return. Income taxes are allocated to the subsidiaries in proportion to their contribution to consolidated taxable income. SEC regulations require that no Entergy subsidiary pay more taxes than it would have paid if a separate income tax return had been filed. In accordance with SFAS 109, "Accounting for Income Taxes," deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities, and for certain credits available for carryforward. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted. Investment tax credits are deferred and amortized based upon the average useful life of the related property, in accordance with ratemaking treatment. Earnings per Share The following table presents Entergy's basic and diluted earnings per share (EPS) calculation included on the consolidated income statement: For the Years Ended December 31, 2004 2003 2002 (In Millions, Except Per Share Data)
$Ishare $/share $/share Income before cumulative effect of accounting change $909.5 $789.9 $599.4 Average number of common shares outstanding - basic 226.9 $4.01 226.8 $3.48 223.0 $2.69 Average dilutive effect of:
- Stock Options (1) 4.3 (0.075) 4.1 (0.062) 3.9 (0.046)
Equity Awards - - 0.2 (0.004) 0.4 (0.005) Average number of common shares outstanding - diluted 231.2 $3.93 231.1 $3.42 227.3 $2.64 Earnings applicable to common stock $909.5 $926.9 $599.4 Average number of common shares outstanding 7 basic 226.9 $4.01 226.8 $4.09 223.0 ' i.
$2.69 Average dilutive, effect of: I. I -. I I' .: ~i Stock Options (1) 4.3 (0.075) . ~4.1 (0.073). 3.9 (0.046),
Equity Awards .0.2 (0.004) 0,4 ' (0.005) Average number of common shares outstanding - diluted 231.2 $3.93 231.1 $4.01 227.3 $2.64 (1) Options to purchase approximately 3,319 common stock shares in 2004, 15,231 common stock shares in 2003, and 109,897 common stock shares in 2002 at various prices were outstanding at the end of those years that were not included in the computation of diluted earnings per share because the exercise prices were greater than the common share average market price at the end of each of the years presented. 52
Entergy Corporation Notes to Consolidated Financial Statements Stock-based Compensation Plans Entergy grants stock options to key. employees of the Entergy subsidiaries, which is described more fully in Note 7 to the consolidated financial statements. Prior to 2003, Entergy applied the recognition and measurement principles of APB Opinion 25, "Accounting for Stock Issued to Employees," and related Interpretations in accounting for those plans. No stock-based employee compensation expense is reflected in 2002 net income as all options granted under the plans have an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1,2003, Entergy prospectively adopted the fair value based method of accounting for stock options prescribed by SFAS 123, "Accounting for Stock-Based Compensation." Awards under Entergy's plans vest over three years. Therefore, the cost related to stock-based employee compensation included in the determination of net incotne for 2004 and 2003 is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS 123. The following table illustrates ;the effectr on net income and earnings per share if Entergy would have historically applied the fair value based method of accounting to stock-based employee compensation. For the Years Ended December 31, 2004 2003 2002 (InThousands, Except Per Share Data) Earnings applicable to common stock $909,524 $926,943 $599,360 Add back: Stock-based compensation expense included
!' in earnings applicable to common stock, net of related -
tax effects 5jl41 2,818 Deduct: Total stock-based employee compensation expense determined under fair value method for all awards, net of related tax effects 16,668 24,518 28,110 Pro forma earnings applicable to common stock $897,997 $905,243 $571,250 Earnings per average common share: - - Basic $4.01 . $4.09 $2.69 Basic -pro forma - $3.96 $3;99 $2.56 Diluted $3.93 $4.01 $2.64 Diluted - pro forma $3.88 '$3.92 $2.51 Application of SFAS 71 The domestic utility companies and System Energy currently account for the effects of regulation pursuant to SFAS 71, "Accounting for the Effects of Certain Types of Regulation." This statement applies to the financial statements of a rate-regulated enterprise that meets three criteria. The enterprise must have rates that (i)"are approved by a body empowered to set rates that bind customers (its regulator); (ii) are cost-based; and (iii) can be charged to and collected from customers. These criteria 'may also be applied to separable portions of a utility's business, such 'as the generation or transmission functions, or to specific classes of customers'. If an 'enterprise meets these criteria, it' capitalizes' costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. 'A significant majority of Entergy's regulatory assets, net of related regulatory and deferred tax liabilities, earn a retu'n on investment during' their recovery peri6ds. SFAS 71 requires that rate-regulated enterprises assess the probability of recovering their regulatory assets at each balance sheet date. When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity's balance sheet. SFAS 101, "Accounting for the Discontinuation of Application of FASB Statement No. 71," specifies how an enterprise that ceases to meet the criteria for application of SFAS 71 for all or part of its operations should report that event in its financial statements. In general, SFAS 101 requires that the enterprise report the discontinuation of 53
Entergy Corporation Notes to Consolidated Financial Statements the application of SFAS 71 by eliminating from its balance sheet all regulatory assets and liabilities related to the applicable segment. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs and therefore no longer qualifies for SFAS 71 accounting, it is possible that an impairment may exist that could require further write-offs of plant assets. EITF 974: "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101" specifies that SFAS 71 should be discontinued at a date no later than when the effects of a transition to competition plan for all or a portion of the entity subject to such plan are reasonably determinable. Additionally, EITF 974 promulgates that regulatory assets to be recovered through cash flows derived from another portion of the entity that continues to apply SFAS 71 should not be written off; rather, they should be considered regulatory assets of the segment that will continue to apply SFAS 71. See Note 2 to the consolidated financial statements for discussion of transition to competition activity in the retail regulatory jurisdictions served by the domestic utility companies. Only Texas has a currently enacted retail open access law, but Entergy believes that significant issues remain to be addressed by regulators, and the enacted law does not provide sufficient detail to reasonably determine the impact on Entergy Gulf States' regulated operations. Cash and Cash Equivalents Entergy considers all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at date of purchase to be cash equivalents. Investments with original maturities of more than three months are classified as other temporary investments on the balance sheet. Investments Entergy applies the provisions of SFAS 115, "Accounting for Investments for Certain Debt and Equity Securities," in accounting for investments in decommissioning trust funds. As a result, Entergy records the decommissioning trust funds at their fair value on the consolidated balance sheet. Because of the ability of the domestic utility companies and System Energy to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the domestic utility companies and System Energy have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the nonregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. Decommissioning trust funds for Pilgrim, Indian Point 2, and Vermont Yankee do not receive regulatory treatment. Accordingly, unrealized gains and losses recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders' equity because these assets are classified as available for sale. See Note 15 to the consolidated financial statements for details on the decommissioning trust funds. Equity Method Investees Entergy owns investments that are accounted for under the equity method of accounting because Entergy's ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of earnings or losses of the investee based on the change during the period in the estimated liquidation value of the investment, assuming that the investee's assets were to be liquidated at book value. The equity earnings for Entergy-Koch, LP recorded by Entergy are dictated by the terms of the partnership agreement in accordance with the hypothetical liquidation at book value (HLBV) method. In accordance with the HLBV method, earnings are allocated to members based on what each partner would receive from their capital account if, hypothetically, liquidation were to occur at the balance sheet date and amounts distributed were based on recorded book values. Entergy discontinues the recognition of losses on equity investments when its share of losses equals or exceeds its carrying amount of investee plus any advances made or commitments to provide additional financial support.. See Note 12 to the consolidated financial statements for additional information regarding Entergy's equity method investments. I 54
Entergy Corporation Notes to Consolidated Financial Statements Derivative Financial Instruments and Commodity Derivatives
- SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," requires that all derivatives be recognized in the balance sheet, either as assets or liabilities, at fair value, unless they meet the normal purchase, normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.
Contracts for commodities that will be delivered in quantities expected to be used or sold in.the ordinary course of business, including certain purchases and sales of power and fuel, are not classified as derivatives. These contracts are exempted under the normal purchase,; normal sales criteria of SFAS 133. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories-as the commodities are received or delivered.' ' ' For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective ad strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the 'cash flows of! the item being hedged.' Gains or -losses accumulated in 'other comprehensive income are reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The ineffective portions of all hedges are recognized in current-period earnings. Impairment of Long-Lived Assets . . " Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination'of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend'on the future operating costs associated with the assets, the efficiency and availability of'the assets'and generating units,- and the future market and price for energy over the remaining life of the assets. See Note 11 to the consolidated financial statements for a: discussion of asset impairments recognized by Entergy in 2002 and 2004. River ' -' ' :U The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the 'AFUDC actually, recorded by 'Entergy Gulf States on a net-of-tax. basis during the construction of River Bend and what the AFUDC would have been on apre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized over the estimated remaining economic life of River Bend. ."' . - Transition to Competition Liabilities In conjunction with electric utility. industry. restructuring activity in Texas, regulatory mechanisms were established to mitigate potential. stranded costs. 'Texas- restructuring legislation: allowed depreciation on transmission and distribution assets to be directed toward.generation assets. The liability recorded as a result of this mechanism is classified as "transition-to competition" deferred credits on the balance sheet,
, .t i . . - ; . , ,
- - ., I. .V Reacquired Debt The premiums and costs associated with reacquired debt of the domestic utility companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States) are being amortized over the life of the related new issuances, in accordance with ratemaking treatment.
'55
Entergy Corporation Notes to Consolidated Financial Statements Foreign Currency Translation All assets and liabilities of Entergy's foreign subsidiaries are translated into U.S. dollars at the exchange rate in effect at the end of the, period. Revenues and expenses are translated at average exchange rates prevailing during the, period. The resulting translation adjustments are reflected in a separate component of shareholders' equity. Current exchange rates are used for U.S. dollar disclosures of future obligations denominated in foreign currencies. New Accounting Pronouncements During 2004, Entergy adopted the provisions of FSP 106-2, "Accounting and Disclosure Requirements Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003," which is discussed further in Note 10 to the consolidated financial statements. Entergy also adopted FSP 109-1, "Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004" and FSP 109-2, "Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision Within the American Jobs. Creation Act of 2004" which are further discussed in Note 3 to the consolidated financial statements. SFAS 123R, "Share-Based Payment" was issued in December of 2004 and is effective for Entergy at the beginning of the third quarter in 2005; SFAS 123R requires all employers to account for share-based payments at fair value and also provides guidance on determining the assumptions to estimate fair value. SFAS 123R also provides guidance on how to account for differences in the amounts of deferred taxes initially recorded when the options are recorded as expense and the amount of expense deducted on a company's tax return when the options are actually exercised. Entergy began voluntarily expensing its stock options effective JanuaryA.1, 2003 in accordance with SFAS 148, "Stock-Based Compensation - Transition and Disclosure." Entergy is in the process of evaluating the reporting and disclosure issues resulting from the adoption of SFAS 123R but does not expect the effect of the adoption of this standard to be material to Entergy's financial position or results of operations. SFAS 151, "Inventory Costs - an amendment of ARB No. 43, Chapter 4" and SFAS 153, "Exchanges of Nonrmonetary Assets", were also issued during the fourth, quarter of 2004 and are effective for Entergy in 2006 and 2005, respectively. Entergy does not expect the impact of the adoption of these standards to be material. During 2003, Entergy adopted the provisions of the following accounting standards: SFAS 143, "Accounting for Asset Retirement Obligations," which is discussed further in Note 8 to the consolidated financial statements; FIN 46, Consolidation of Variable Interest Entities," which is discussed further in Note 5 to the consolidated financial statements; and SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." 'tSFAS 150, which became effective July 1, 2003,. requires mandatorily redeemable financial instruments to be classified and treated as liabilities in. the presentation of financial'position and results of operations. The only effect of implementing SFAS 1.50 for Entergy is the inclusion of long-term debt and preferred stock with sinking fund under the liabilities caption in Entergy's balance sheet. Entergy's results of operations and cash flows were not affected by SFAS 150. During 2003, Entergy also adopted the provisions of the following accounting standards: EITF 02-3, !'Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities"; SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" and related interpretations by the Derivatives Implementation Group, and FIN 45, "Guarantor's Accounting and Disclosure, Requirements for; Guarantees Including Indirect Guarantees of Indebtedness of Others". The adoption of these standards did not have a material effect on Entergy's financial statements. 56
Entergy Corporation Notes to Consolidated Financial Statements NOTE 2: RATE AND REGULATORY MATTERS I E r rty ta e t i Electric Industry Restructuring and the Continued Application of WFAS 71 Although Arkansas and Texas enacted retail open access laws, the retail open access law in Arkansas has now been repealed. Retail open access in Entergy Gulf States' service territory in Texas has been delayed. Entergy believes that significant issues remain to be addressed by regulators, and the enacted law in Texas does not provide sufficient detail to allow Entergy Gulf States to reasonably determine the impact on Entergy Gulf States' regulated operations.'- Entergy therefore continues to apply regulatory accounting principles to the retail operations of all of the domestic utility companies. Following is a summary of the status of retail open access in the domestic utility companies' retail service territories.
., % of Entergy's 2004 Revenues Derived from Retail Electric Utility Operations Jurisdiction Status of Retail Open Access in the Jurisdiction Arkansas Retail open access was repealed in February 2003. 11.6%
Texas In July 2004, the PUCT effectively rejected Entergy Gulf States' proposal to 11.8% implement retail open access in its service territory. In February 2005, bills were submitted in the Texas Legislature that would specify that retail open
, I -- access will not commence in Entergy Gulf States' territory until the PUCT t ; I.,
certifies a power region. Louisiana The LPSC has deferred pursuing retail open access, pending developments at 34.1% the federal level and in other states. In response to a study submitted to the LPSC that was funded by a group of large industrial customers, the LPSC recently has soliditedcornments regarding a limited retail access program. It is uncertain what action, if any, the LPSC might take in response to the information it received. Mississippi The MPSC has recommended not pursuing open access at this time. 10.9% New Orleans The Council has taken no action on Entergy New Orleans' proposal filed in 4.5% 1997. Texas As ordered by the PUCT, in January 2003 Entergy Gulf States filed its proposal for an interim solution (retail open access without a FERC-approved RTO), which among other elements, included:
- the recommendation that retail open access in Entergy Gulf States' Texas service territory, including corporate unbundling, occur by January 1, 2004, or else be delayed until at least January 1, 2007. If retail open access is delayed past January 1, 2004, Entergy Gulf States requested authorization to separate into two bundled utilities, one subject to the retail jurisdiction of the PUCT and one subject to the retail jurisdiction of the LPSC.
- the recommendation that Entergy's transmission organization, possibly with the oversight of another entity, will continue to serve as the transmission authority for purposes of retail open access in Entergy Gulf States' service territory.
- the recommendation that the decision points be identified that would require prior to January 1, 2004, the PUCT's determination, based upon objective criteria, whether to proceed with further efforts toward retail open access in Entergy Gulf States' Texas service territory.
57
Entergy Corporation Notes to Cdnsolidated Financial Statements After considering the proposal, in an April 2003. order the PUCT set forth a sequence of proceedings and activities designed to initiate an interim solution. These proceedings and activities included initiating a proceeding to certify an independent organization to administer, market protocols and ensure nondiscriminatory access to transmission and distribution systems. In July 2004 the, PUCT denied Entergy's application to certify Entergy's transmission organization as an independent organization under Texas law.; In its order,-the. PUCT also ordered: the cessation of efforts to develop an interim solution for retail open access in Entergy Gulf States' Texas service territory, termination of the pilot project in that' territory, and a delay in retail open access in that territory until either a FERC-approved RTO is in place or some other independent trainsmission entity is certified under Texas law. Several parties have appealed the termination of the pilot program aspect of the order, claiming the issue was not properly a part of the proceeding. In, February 2005, bills were submitted in the Texas Legislature that would clarify that Entergy Gulf States is no-longer subject to a rate freeze and specify that retail open access will not commence in Entergy Gulf States' Texas service territory until the PUCT certifies a power region.
, _v.e!
Louisiana In November 2001, the LPSC decided not to move forward with retail open access for any customers at this time. The LPSC instead directed its staff to hold collaborative group meetings concerning open access from time to time, and to have the LPSC staff monitor developments in neighboring states and to report to the LPSC regarding the progress of retail access developments in. those states. In September 2004, in response to a study funded by certain industrial customers that evaluated a'limited industrial-4Only retail choice program, the LPSC asked the LPSC staff to solicit comments and obtain information from utilities, customers, and other interested parties concerning the potential costs and benefits of a limited choice program, the impact of such a program on other customers, as well as issues such as, stranded costs and transmission service, Comments from interested'parties were filed with the LPSC on January 14, 2005, The LPSC has. not established a procedural framework for consideration of the comments. .At this time, it is not certain what further action, if any, the. LPSC might take in response to the information it received, 58
Entergy Corporation Notes to Consolidated Financial Statements Regulatorv Assets Other Regulatory Assets The domestic utility companies and System Energy are subject to the provisions of SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. In addition to the regulatory assets that are specifically disclosed on the face of the balance sheets, the table below provides detail of "Other regulatory assets" that are included on the balance sheets as of December 31, 2004 and 2003: 2004 2003 (In Millions) Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 8) $380.1 $464.9 Deferred fuel - non-current - recovered through rate riders when rates are redetermined annually 21.9 28.2 Depreciation re-direct - recovery begins at start of retail open access (Note 1) 79.1 79.1 DOE Decommissioning and Decontamination Fees - recovered through fuel rates until December 2006 (Note 8) 25.3 32.9 Low-level radwaste - recovery timing dependent upon pending lawsuit 19.4 19.4 Pension costs (Note 10) 207.3 134.0 Postretirement benefits -recovered through 2013 (Note 10) 19.1 21.5 Provision for storm damages - recovered through cost of service 124.5 123.3 Removal costs - recovered through depreciation rates (Note 8) 53.2 45.6 Resource planning - recovery timing will be determined by the LPSC in a base rate proceeding (Note 2) 25.4 5.8 River Bend AFUDC - recovered through August 2025 (Note 1) 37.5 39.4 Sale-leaseback deferral - recovered through June 2014 (Note 9) 127.3 131.7 Spindletop gas storage facility - recovered through December 2032 42.3 38.0 Unamortized loss on reaquired debt - recovered over term of debt 169.9 164.4 Other - various 97.0 70.1 Total $1,429.3 $1,398.3 Deferred fuel costs The domestic utility companies are allowed to recover certain fuel and purchased power costs through fuel mechanisms included in electric rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is recorded as "Deferred fuel costs" on the domestic utility companies' financial statements. The table below shows the amount of deferred fuel costs as of December 31, 2004 and 2003 that Entergy expects to recover or (refund) through the fuel mechanisms of the domestic utility companies, subject to subsequent regulatory review. 2004 2003 (In Millions) Entergy Arkansas $7.4 $10.6 Entergy Gulf States $90.1 $118.4 Entergy Louisiana $8.7 $30.6 Entergy Mississippi ($22.8) $89.i Entergy New Orleans $2.6 ($2.7) Entergy Arkansas Entergy Arkansas' rate schedules include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an annual energy cost rate. The energy cost 59
Entergy Corporation Notes to Consolidated Financial Statements rate includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. In March 2004, Entergy Arkansas filed with the APSC its energy cost recovery rider for the period April 2004 through March 2005.. The filed energy cost rate, which accounts for 12 percent of a typical residential customer's bill using 1,000 kWh per month, increased 16 percent due primarily to the elimination of a credit contained in the prior year's rate to refund previously over-recovered fuel costs. Also included in the current year's energy cost calculation isz a. decrease in rates- of $3.9 million as a'Tesult of the operation of a revised energy allocation method between the retail and wholesale sectors resulting from, the APSC's approval of a life-of resources power purchase agreement with Entergy New Orleans. EntergyvGulf States (Texas) In the Texas jurisdiction, Entergy Gulf States' rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, not recovered in base rates. Under the current niethodology, semi-annual revisions of the fixed fuel factor may be made in March and September based on the market price of natural gas. Entergy Gulf States will likely continue to use this methodology until the start of retail open access, which has been delayed. The amounts collected under Entergy' Gulf States' fixed fuel factor and any interim surcharge implemented until the date retail open access commences. are subject to fuel reconciliation proceedings before the PUCT. In the Texas jurisdiction, Entergy Gulf States' deferred electric fuel costs are $78.6 million as of December 31, 2004, which include the following: Amount (In Millions) Under-recovered fuel costs for the period 9/03 - 7/04 to be recovered through an interim fuel surcharge over a six-month period beginning in January 2005 $27.8' Items to be addressed as part of unbundling $29.0 ' - ' Imputed capacity charges ' $9.3 ' Other $12.5 The PUCT has ordered that the imputed capacity charges be excluded from fuel rates and therefore recovered through base rates. Entergy Gulf States filed a retail electric rate case and fuel proceeding with the PUCT in August 2004. As discussed below, the PUCT dismissed the rate case and fuel reconciliation proceeding in October 2004 indicating thatE'Entergy Gulf States is still subject to a rate freeze based on the current PUCT-approved settlement agreement 'stipulating that a rat'e freeze would remain in effect'until retail open access commenced 'in Entergy Gulf States' service territory, unless the rate freeze is lifted by the PUCT prior thereto. Without a Texas base rate proceeding,' it is pos'sible that Entergy dulf States will not be allowed to recover imputed capacity charges in Texas retail rates in the future. Entergy Gulf States believes the PUCT has misinterpreted the settlement and has appealed the PUCT order to the Travis County District Court and also intends to'pursue other available remedies as discussed above in "Electric Industry Restructuring and the Continued Application of SFAS 71." The dismissal of the rate case does not preclude Entergy Gulf- States from seeking the reconciliation of fuel and purchased power costs of $288 million incurred from September 2003 through March 2004 when, at the appropriate time, similar costs are reconciled in the future. In January 2001, Entergy Gulf States filed with the PUCT a'fuel reconciliation case covering the period from March 1999 through August 2000. Entergy Gulf States was reconciling approximately $583 million of fuel and purchased power costs. As part of this filing, Entergy Gulf States requested authority to collect $28 million, plus interest, of under-recovered fuel and purchased power costs. In August 2002, the PUCT reduced Entergy Gulf States' request to approximately $6.3 million, including interest through July 31, 2002. Approximately $4.7 million of the total reduction to the requested surcharge relates to nuclear fuel costs that the PUCT deferred ruling on at that time. In October 2002, Entergy Gulf States appealed the PUCT's final order in Texas District Court. In its appeal, Entergy Gulf States is challenging the PUCT's disallowance' of approximately $4.2 million related to imputed capacity costs and its disaliowance related to costs for energy delivered from the 30% non-regulated share of River 60
Entergy Corporation Notes to Consolidated Financial Statements Bend. The casewas argued before the Travis County Texas District Court in August 2003 and the Travis County District Court judge affirmed the PUCT's order. In October 2003, Entergy Gulf States appealed this decision to the Court of Appeals. Oral argument before the appellate court occurred in September 2004 and the matter is still pending. In September 2003, Entergy Gulf States filed an application with the PUCT to implement an $87.3 million interim fuel surcharge, including interest, to collect under-recovered fuel and purchased power expenses incurred from September 2002 through August 2003. Hearings were held in October 2003 and the PUCT issued an order in December 2003 allowing for the recovery of $87 million. The surcharge was collected over a twelve-month period that began in January 2004. In March 2004, Entergy Gulf States filed with the PUCT a fuel reconciliation case covering the period September 2000 through August 2003. Entergy Gulf States is reconciling $1.43 billion of fuel and purchased power costs on a Texas retail basis. This amount includes $8.6 million of under-recovered costs that Entergy Gulf States is asking to 'reconcile and roll into its fuel over/under-recovery balance to be addressed in the next appropriate fuel proceeding. This case involves imputed capacity and River Bend payment issues similar to those decided adversely in the January 2001 proceeding, discussed above, which is now on appeal. On January 31, 2005, the ALJs issued a Proposal for Decision that recommends disallowing $10.7 million (excluding interest) related to these two issues. A final PUCT decision is expected in the first quarter of 2005. In September 2004, Entergy Gulf States filed an application with the PUCT to implement a $27.8 million interim fuel surcharge,-including interest, to collect under-recovered fuel and purchased power expenses incurred from September 2003 through July 2004. Entergy Gulf States proposed to collect the surcharge over a six-month period beginning January 2005. In December 2004, the PUCT approved the surcharge consistent with Entergy Gulf States' tequest. Amounts collected though the interim fuel surcharge, which will be implemented over the six-month period commencing January 2005, are subject to final reconciliation in a future fuel reconciliation proceeding. Entergy Gulf States (Louisiana) and Entergy Louisiana In Louisiana, Entergy Gulf.States and Entergy Louisiana recover electric fuel and purchased power costs for the upcoming month based upon the level of such costs from the prior month. In Louisiana, Entergy Gulf States' purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations of actual fuel costs incurred with fuel cost revenues billed to customers. In August 2000, the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Louisiana pursuant to a November 1997 LPSC general order. The time period that is the subject of the audit is January 1, 2000 through December 31, 2001. In September 2003, the LPSC staff issued its audit report and recommended a disallowance with regard to one item. The issue relates to the alleged failure to uprate Waterford 3 in a timely manner, a claim that also has been raised in the summer 2001, 2002, and 2003 purchased power proceedings. The LPSC staff has quantified the possible disallowance as between $7.6 and $14 million. Entergy Louisiana notified the LPSC that it will contest the recommendation. The procedural schedule in the case has been suspended. A status conference for the purpose of establishing a new procedural schedule will be set when the current hearings in the Power Purchase Agreement proceedings at the FERC are concluded. The FERC hearings in that matter concluded in November 2004. If the LPSC approves the proposed settlement discussed below under "Retail Rate Proceedings", the issue of a proposed imprudence disallowance relating to the uprate will be resolved and will no longer be at issue in this proceeding. In January 2003, the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States and its affiliates pursuant to a November 1997 LPSC general order. The audit will include a review of the reasonableness of charges flowed by Entergy Gulf States through its fuel adjustment clause in Louisiana for the period January 1, 1995 through December 31, 2002. Discovery is underway, but a detailed 61
Entergy Corporation Notes to Consolidated Financial Statements procedural schedule extending beyond the discovery stage has not yet been established, and the LPSC staff has not yet issued its audit report. ; . i; i.lCA i ,'. -J'd)('.' a .-'&1yo '.j. ci t , ' Ist mA Entergy Mississippi .* Entergy Mississippi's rate schedules include an energy cost, recovery rider which is adjusted quarterly to reflect accumulated over- or under-recoveries from the second prior quarter. In May 2003, Entergy Mississippi filed and the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Under the MPSC's order, Entergy Mississippi deferred until 2004. the collection of fuel under-recoveries for the first and second quarters of 2003 that would have been collected in the third and fourth quarters of 2003, respectively. The deferred amount of $77.6 million plus carrying charges was collected through the energy cost recovery rider over a twelve-month period that began in January 2004. . 2 I,.J i r,,j 4 Jr '-4 -A -! In January 2005, the MPSC approved a change in Entergy Mississippi's energy ,cost .recoyery rider. Entergy Mississippi's fuel over-recoveries for the third quarter of 2004 of $21.3 million will be deferred from the first quarter 2005 energy cost recovery rider adjustment calculation. The deferred amount of $21.3 million plus carrying charges will be refunded through the energy cost recovery rider in the second and third quarters of 2005. Entergy New Orleans , i i ' t 3 :i:;'n. -' i Entergy New .Orleans' electric rate schedules ,include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costsadjusted by a surcharge or credit for deferred fel expense arising from monthly reconciliations, including carrying charges. Entergy New Orleans' gas.,rate schedul~es include estimates for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations, including carrying charges. In June and November 2004, the City Council passed resolutions implementing a package of measures developed by Entergy New Orleans and the Council Advisors to protect customers from potential gas price spikes during the 2004 - 2005 winter heating season. These measures incluxde maintaining Entergy New Orleans' financial hedging plan for its purchase of wholesale gas, and deferral of collection of up to $6.2 million of gas costs associated with a cap on the purchased gas adjustment in November and December 2004 and in the event that the average residential customer's gas bill were to exceed a threshold level. The. deferrals resulting from these caps will receive accelerated recovery over a seven-month period beginning in April 2005. ii + S .':1. ' i l '..) ii ;! ir t In November 2004, the City Council directed Entergy New Orleans to confer with the Council Advisors regarding possible modification of the current gas cost collection mechanism in order to address concerns regarding its fluctuations particularly during the winter heating season. Retail Rate Proceedings i -1l i:i.. . '.i "'n' O C; O .{ ¢ .'..AI 7t'<:'J to S-5;5ijtlu
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? JiS; Sill I Filings with the APSC (Entergy Arkansas) wl-;- 'q I; i.;, CCII; hut~;t. h.r. a.
No significant retail rate proceedings are pending in Arkansas at this time. i * . . . <: m'unt' Filings with the PUCT and Texas Cities (Entergy Gulf States) lt . f .,ui'ie
,i, flC:n-s9 [ 1, .C &,
Retail Rates 0 . ,I.i. .t', fIC; .)b1,..
,i:'i 72 di 3ti? ilfit g Entergy Gulf States is operating in Texas under the terms of a December 2001 settlement agreement approved by the PUCT. The settlement provided for base rates that have remained in effect during the delay in the implementation of retail open access in Entergy Gulf States' Texas service territory. In View of the PUCT order in July 2004 to further delay retail open acdess in the Texas service territory, Entergy Gulf States filed a retail electric rate case and fuel reconciliation proceeding with the PUCT in August 2004 seeking the following: ,
- approval of a base rate increase of $42.6 million annually for the Texas retail jurisdiction; 62
Entergy Corporation Notes to Consolidated Financial Statements
- approval to implement a $14.1 million per year rider to recov0r'over a 15-year period, $110.9 million of incurred costs related to its efforts to transition to a competitive retail mairket in accordance with the Texas restructuring law;
- approval to implement a proposed $11.3 million franchise fee rider to recover payments to municipalities charging such fees; and i .i . .
- a requested return on equity of 11.5%.
In addition, Entergy Gulf States' fuel reconciliati_"on{1 f1 fmiade i'n6conjuncti6n'with the base f Ste cas'e sought to reconcile approximately $288 million in fuel and purchased 'pr6wer costs incurred during the period September 2003 through March 2004. In October 2004, the PUCT is'ueiid a written order in which it dismissed the rate cas'6tand fuel reconciliation prf&ceding indicating that Ent4Frg G& 9fS'ftes is still subject to a rate freeze based on a PUCT-approved agreement in 2001 stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless the rate freeze is lifted by the PUCT prior thereto. Ei'fergy Gulf States believes' the PUCT has misinterpreted the gettleniiii¶'and has appealed the PUCT order to the Travis County District Court and intends to'piistie'"6ther available ikedR'., ii In Februaty'2005, bills wer esubhmitted'in the Texas' LegisI tethat Would 6c1rify t a naee S is no longer subject to'a rate freeze and specify that' retail open 6e8& -will not commence in Entergy Gulf States' Texas'service territory until the PUCTXcertifies a'poWie regioh. ~i t'" i Recovery of River Bend Costs In March 1998, the PUCT disallowed recovery of $1.4 billion of company-wide abeyed River Bend plant costs, which have been held in abeyance since 1988. Entergy Gulf States appealed the PUCT's decisionon this matter to the Travis County District Court in Texas. In April 2002, the Travis County District Court issued an order affirming the PUCT's' order on reaid dis'allowing r ei 'bf abeyed plant costs. " Entergy Gulf States the appealed this ruling to the Third' District Court 'of Appeals. tn MJuy 2003, 'the Third District Court of Appeals unanimously affirmed the judgineint of the Travis County'District'C6o'rt. After considering the progress 'of the prbie'-ding-in light of the decision of the Cou'rt of Appeals, Etde'rgy Gulf States' accfued for the loss that would be associated with a final, non-appealable'decision disallowing the abyed plat' c6sts. The net carrying value of the abeyed plant costs was $107.7 million at the time of the Court f Aj'5p5als decision. Accrual of the $107.7 million loss was' recdrded in the secofid quarter of 2003 as inisceflan'ib{ o6ther income (deductions) and reduced 'net income by $65.6miillion after-ta*' `n nSept-ember 2004, the Texas S'pi e'Court denied Entergy Gulf States' petition for review, and Enfergy Gulf States filed a motkio foi'r-~ehdeting9" In February 2005, the Texas Supreme Court denied the motion for rehearing, 'and the proceeding is nO'wfii1. 'a-l., Filings with the LPSC Proposed Settlement In September 2004, the LPSC consolidated various dockets that were the subject of settlement discussions between thee L4PSC staff and EnfergyGulf States and Entergy Louisiana. The LPSC directed its staff to continue the settlement discussions addubmit'any' ~proposcd settlement th Ito d fo isInanuary Entergy Gulf States and Entery tLouisiana- filed testimony with'the nPSC ifi'support of a propose ietflemnent 'that rent lyincludes a'n 6r 6grun'd $7'6 million to ntergr Guy-lf't ie',16oisiana customers,-4 ith no' imme iate ch-angeim;current base rates an toreund $14 illon to Entergy L' smersIf
" "" LPSC approves the proposed setlement, Entergy Gulf States will be regulated under. a three-year formula rate plan that, among other provisions, establishes rgy ulf States to recover increment capacity cost's without filing a traditiof ba'se rate proceeding. The ftern-eint' resolves all issues in, and wilfl result in the dismrisiial' f, Entergy Gulf Les' fourth, iftsth,'ei d eighth 'annual rvniiews, ntergy GulfSt nin post-merger earnings review and revenue requirement analysis a fuel 'review for Entergy"Gulf States, cets established io' oisider issues concerning power purchases for b56th Entergy Gulf States anid Entergy Louis'iana for the summers of"20'f, 2002', 2O00, and 2(104, and a docket concerning retail'issues'aising under tha-Entergy System Agreement. The settlement does not include the ystem Agreeme&nt case pedinig at FERC. The 63
Entergy Corporation Notes to Consolidated Financial Statements LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005. Annual Earnings Reviews (Entergy Gulf States) In May 2002, Entergy Gulf States filed its ninth and last required post-merger analysis with the LPSC. The filing included an earnings review filing for the 2001 test year that resulted in a rate decrease of $11.5 million, which was implemented effective June 2002. In its latest testimony, in December 2003, the LPSC staff recommended a rate refund of $30.6 million and a prospective rate reduction of approximately $50 million. Hearings concluded in May 2004. Should the LPSC approve the proposed settlement discussed above, the ninth post-merger analysis would be resolved. In December 2002, the LPSC approved a settlement between Entergy Gulf States and the LPSC staff pursuant to which Entergy Gulf States agreed to make a base rate refund of $16.3 million, including interest, and to implement a $22.1 million prospective base rate reduction effective January 2003. The settlement discharged any potential liability for claims that relate to Entergy Gulf States' fourth, fifth, sixth seventh, and eighth post-merger earnings reviews, with the exception of certain issues related to the calculation of the River Bend Deregulated Asset Plan percentage. Entergy Gulf States made the refund in February 2003. Should the LPSC approve the proposed settlement discussed above, the outstanding issue in these proceedings would be resolved. Retail Rates (Entergy Louisiana) In January 2004, Entergy Louisiana made a rate filing with the LPSC requesting a,base rate increase of approximately $167 million. In that filing, Entergy Louisiana noted that approximately $73 million of the base rate increase was attributable to the acquisition of a generating station and certain power purchase agreements that, based on current natural gas prices, would produce fuel and purchased power savings for customers that substantially mitigate the impact of the requested base rate increase. The filing also requested an allowed ROE of 11.4%. Entergy Louisiana's previously authorized ROE mid-point currently in effect is 10.5%0 Hearings concluded in December 2004. Based on the evidence submitted at the hearing, the LPSC staff is recommending approximately a $7 million base rate increase. The LPSC staff proposed the implementation of a formula rate plan that includes a provision for the recovery of incremental capacity costs, including those related to the proposed Perryville acquisition, without filing a traditional base rate proceeding. A decision by the LPSC is expected in mid-to late-March 2005 on these issues. Filings with the MPSC (Entergy Mississippi) Formula Rate Plan Filings Entergy Mississippi is operating under a December 2002 order issued by the MPSC. The order endorsed a new power management rider schedule designed to more efficiently colle& capacity portions of purchased poWer costs. Also, the order provides for improvements in the return on equity formula and more robust performance measures for Entergy Mississippi's formula rate plan. Under the provisions of Entergy Mississippi's formula rate plan, a bandwidth is placed around the benchmark ROE, and if Entergy Mississippi earns outside of the bandwidth (as well as outside of a range-of-no-change at each edge of the bandwidth), then Entergy Mississippi's rates will be adjust&d, though on a prospective basis only. Under Mississippi law and Entergy Mississippi's formula rate plan, h6wever, if Entergy Mississippi's earned ROE is above the top of the range-of-no-change at the top of the formula rate plan bandwidth, then 8ntergy Mississippi's "Allowed ROE" for the 'next twelve-month period is the point halfway between such earned ROE and the top of the bandwidth; and Entergy Mississippi's retail rates are set at that halfway-point ROE level. In the situation where Entergy Mississippi's earned ROE is not above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the top of the range-of-no-change at the top of the bandwidth. 64
Entergy Corporation Notes to Consolidated Financial Statements Entergy Mississippi made its annual formula rate plan filing with the MPSC in March 2004 based on a 2003 test year. In April 2004, the MPSC approved a joint stipulation entered into between the Mississippi Public Utilities Staff and Entergy Mississippi that provides for no change in rates based on a performance adjusted return on common equity mid-point of 10.77%, establishing an allowed regulatory earnings range of 9.3% to 12.2%. Filings with the Council (Entergy New Orleans) Rate Proceedings In May 2003, the City Council approved a resolution allowing for a total increase of $30.2 million in electric and gas base rates effective June 1, 2003. In April 2004, Entergy New Orleans made filings with the City Council as required by the earnings review process prescribed by the Gas and Electric Formula Rate Plans approved by the City Council in 2003. In August 2004, the City Council approved an unopposed settlement among Entergy New Orleans, the Council Advisors, and the intervenors in connection with the Gas and Electric Formula Rate Plans. In accordance with the resolution approving the settlement agreement, Entergy New Orleans' gas and electric base rates remain unchanged from the levels set in May 2003. The resolution ordered Entergy New Orleans to defer $3.9 million relating to voluntary severance plan costs allocated to its electric operations and $1.0 million allocated to its gas operations, which amounts were accrued on its books in 2003, and to record on its books regulatory assets in those amounts to be amortized over five years effective January 2004. Entergy New Orleans also was ordered to defer $6.0 million of fossil plant maintenance expense incurred in 2003 and to record on its books a regulatory asset in that amount to be amortized over a five-year period effective January 2003. Fuel. Adjustment Clause Litigation In April 1999, ,a group of ratepayers filed a complaint against Entergy New Orleans, Entergy Corporation, Entergy Services, and Entergy Power in state court in Orleans Parish purportedly on behalf of all Entergy New Orleans ratepayers. The plaintiffs seek treble damages for alleged injuries arising from the defendants' alleged violations of Louisiana's antitrust laws in connection with certain costs passed on to ratepayers in Entergy New Orleans' fuel adjustment filings with the City Council. In particular, plaintiffs allege that Entergy New Orleans improperly included certain costs in the calculation of fuel charges and that Entergy New Orleans imprudently purchased high-cost fuel from other Entergy affiliates. Plaintiffs allege that Entergy New Orleans and the other defendant Entergy companies conspired to make these purchases to the detriment of Entergy New Orleans' ratepayers and to the benefit of Entergy's shareholders, in violation of Louisiana's antitrust laws. Plaintiffs also seek to recover interest and attorneys' fees. Entergy filed exceptions to the plaintiffs' allegations, asserting, among other things, that jurisdiction over these issues rests with the City Council and FERC. In March 2004, the plaintiffs supplemented and amended their petition. If necessary, at the appropriate time, Entergy will also raise its defenses to the antitrust claims. The suit in state court has been stayed by stipulation of the parties pending a decision by the City Council in the proceeding discussed in the next paragraph. Plaintiffs also filed this complaint with the City Council in order to initiate a review by the City Council of the plaintiffs' allegations and to force restitution to ratepayers of all costs they allege were improperly and imprudently included in the fuel adjustment filings. Testimony was filed on behalf of the plaintiffs in this proceeding asserting, among other things, that Entergy New Orleans and other defendants have engaged in fuel procurement and power purchasing practices and included costs in Entergy New Orleans' fuel adjustment that could have resulted in Entergy New Orleans customers being overcharged by more than $100 million over a period of years. Hearings were held in February and March 2002. In February 2004, the City Council approved a resolution that resulted in a refund to customers of $11.3 million, including interest, during the months of June through September 2004. The resolution concludes, among other things, that the record does not support an allegation that Entergy New Orleans' actions or inactions, either alone or in concert with Entergy or any of its affiliates, constituted a misrepresentation or a suppression of the truth made in order to obtain an unjust advantage of Entergy New Orleans, or to cause loss, inconvenience, or harm to its ratepayers. Management believes that it has adequately provided for the liability associated with this proceeding. The plaintiffs have appealed the City Council resolution to the state court in Orleans Parish. Oral argument on the plaintiffs' appeal was conducted in February 2005. 65
Entergy Corporation Notes to Consolidated Financial Statements NOTE 3. INCOME TAXES Income tax expenses for 2004, 2003, and 2002 consist of the following: 2004 2003 2002 (In Thousands) Current: ($731,129 Federal (a)(b) $54,380 ) $510,109 Foreign (2,231) 8,284 (3,295) State (a)(b) 38,301 23,396 43,788 Total (a)(b) 90,450 (699,449) 550,602 Deferred -- net 296,445 1,307,092 (233,532) Investment tax credit adjustments -- net (20,987) (27,644) (23,132) Recorded income tax expense $365,908 $579,999 $293,938 (a) The actual cash taxes paid were $28,241 in 2004, $188,709 in 2003, and $57,856 in 2002. Entergy Louisiana's mark-to-market tax accounting election significantly reduced taxes paid in 2002. In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts. The most significant of these is the contract to purchase power from the Vidalia project (the contract is discussed in Note 8 to the consolidated financial statements). The new tax accounting method has provided a cumulative cash flow benefit of approximately $790 million through 2004, which is expected to reverse in the years 2005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. Approximately half of the consolidated cash flow benefit of the election occurred in 2001 'and the remainder occurred in 2002. (b) In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the' IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $2.95 billion deduction on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. On a consolidated basis, a $74 million cash tax benefit was realized in 2004. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. 66
Entergy Corporation Notes to Consolidated Financial Statements
. ,, .II I . I . I !
II_. Total income taxes differ from the amounts computed by applying the statutory income tax rate to income before taxes. The reasons for the differences for the years 2004, 2003, and 2002 are: 2004 2003 2002 (In Thousands) , - - Computed at statutory rate (35%) $454,635 $535,663 -, $320,954 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 36,185 54,024 44,835 Regulatory differences-utility plant items 41,240 52,638 29,774 Amortization of investment tax credits (20,596) (24,364) (22,294) EAM capital loss (86,426) Flow-through/permanent differences (42,902) (30,221) (38,197) US tax on foreign income 2,014 7,888 (28,416) Other -- net (18,242) (15,629) (12,718) Total income taxes $365,908 $579,999 $293,938. Effective Income Tax Rate 28.2% 37.9% ; 32.1%. The EAM capital loss is a tax benefit, resulting from the sale of preferred stock and less than 1% of the common stock of Entergy Asset Management, an Entergy subsidiary. In December 2004, an Entergy subsidiary sold the stock to a third party for $29.75 million. The sale resulted in a capital loss for tax purposes of $370 million, producing a federal and state net tax benefit of $97 million that.Entergy recorded in the fourth quarter of 2004. Entergy has established a contingency provision in its financial statements that management believes will sufficiently cover the risk associated with this issue.
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Entergy Corporation Notes to Consolidated Financial Statements Significant components of net deferred and noncurrent accrued tax liabilities as of December 31, 2004 and 2003 are as follows: - 2004 2003 (In Thousands) Deferred and Noncurrent Accrued Tax Liabilities: Net regulatory liabilities ($978,815) ($1,072,898) Plant-related basis differences (4,699,803) (3,574,593) Power purchase agreements (972,348) -(945,495) Nuclear decommissioning (545,109) (519,028) Other (346,993) (379,875) Total (7,543,068) (6,491,889) I 1. Deferred Tax Assets: Accumulated deferred investment tax credit 133,979 141,723 Capital losses 134,688 92,423 Net operating loss carryforwards 1,201,006 129,122 Sale and leaseback 227,155 223,134 Unbilled/deferred revenues 28,741 18,983 Pension-related items 247,662 204,083 Reserve for regulatory adjustments 131,112 138,933 Customer deposits 107,652 108,591 Nuclear decommissioning 158,796 272,551 Other 225,659 399,080 Valuation allowance (43,864) (39,210) Total 2,552,586 1,689,413j Net deferred and noncurrent accrued tax liability A ($4,990,482) ($4,802,476) At December 31, 2004, Entergy had $342.4 million in net realized federal capital los 'carryforw'ards that will expire as follows: $103.8 million in 2007, $10.6 million in 2008, and $228.0 million in 2009. At December 31, 2004, Entergy had federal net operating loss carryforwards of $2.9 billion. If the federal net operating loss carryforwards are not utilized, they will expire in the years 2023 through 2024. At December 31, 2004, Entergy had state net operating loss carryforwards of $3.5 billion, primarily resulting from Entergy Louisiana's mark-to-market tax election and the change in method of accounting for tax purposes related to cost of goods sold, as discussed above. If the state net operating loss carryforwards are not utilized, they will expire in the years 2008 through 2019. The 2004 and 2003 valuation allowances are provided against UK capital loss and UK net operating loss carryforwards, and certain state net operating loss carryforwards. The UK losses can be utilized against future UK taxable income. For UK tax purposes, these carryforwards do not expire. On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was enacted. The Act promotes domestic production and investing activities by providing a number of tax incentives including a temporary incentive to repatriate accumulated foreign earnings, subject to certain limitations, by providing an 85% dividends received deduction for certain repatriated earnings and also providing a tax deduction of up to 9% of qualifying 68
Entergy Corporation Notes to Consolidated Financial Statements production activities. In 2004, Entergy repatriated $64 million of accumulated foreign earnings, which resulted in approximately $16.1 million of tax benefit. At December 31, 2004, Entergy has approximately $7.4 million of undistributed earnings from subsidiary companies outside the United States that are being considered for repatriation. If these earnings are repatriated in accordance with the Act, the repatriation would result in approximately $1.5 million of income tax expense. In accordance with FSP 109-1, which was issued by the FASB to address the accounting for the impacts of the Act, the allowable production tax credit will be treated as a special deduction in the period in which it is deducted rather than treated as a tax rate change during 2004 which isthe period in which the Act was signed into law. The adoption of FSP 109-1 and FSP 109-2, also issued by the FASB to address the accounting for the repatriation provisions of the Act, did not have a material effect on Entergy's financial statements. NOTE 4. LINES OF CREDIT AND SHORT-TERM BORROWINGS Entergy Corporation has in place two separate revolving credit facilities, a 5-year credit facility and a 3-year credit facility. The 5-year credit facility, which expires in December 2009, has a borrowing capacity of $500 million, none of which was outstanding at December 31, 2004. The 3-year credit facility, which expires in May 2007, has a borrowing capacity of $965 million, of which $50 million was outstanding at December 31, 2004. Entergy also has the ability to issue letters of credit against the total borrowing capacity of both credit facilities, and $50 million had been issued against the 3-year facility at December 31, 2004. The commitment fee for these facilities is currently 0.13% of the line amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior debt ratings of the domestic utility companies. Entergy Corporation's facilities require it to maintain a consolidated debt ratio of 65% or less of its total capitalization, and maintain an interest coverage ratio of 2 to 1. If Entergy fails to meet these limits, or if Entergy or the domestic utility companies default on other indebtedness or are in bankruptcy or insolvency proceedings, an acceleration of the facility's maturity date may occur. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans each have 364-day credit facilities available as follows: Amount of Amount Drawn as Company Expiration Date Facility of Dec. 31, 2004 Entergy Arkansas April 2005 $85 million Entergy Louisiana April 2005 $15 million(a) - Entergy Mississippi May 2005 $25 million Entergy New Orleans April 2005 $14 million(a) - (a) The combined amount borrowed by Entergy Louisiana and Entergy New Orleans under these facilities at any one time cannot exceed $15 million. The 364-day credit facilities have variable interest rates and the average commitment fee is 0.13%. The Entergy Arkansas facility requires it to maintain total shareholder's equity of at least 25% of its total assets. The short-term borrowings of Entergy's subsidiaries are limited to amounts authorized by the SEC. The current limits authorized are effective through November 30, 2007. In addition to borrowing from commercial banks, Entergy's subsidiaries are authorized under the SEC order to borrow from Entergy's money pool. The money pool is an inter-company borrowing arrangement designed to reduce Entergy's subsidiaries' dependence on external short-term borrowings. Borrowings from the money pool and external borrowings combined may not exceed the SEC authorized limits. As of December 31, 2004, Entergy's subsidiaries' aggregate authorized limit was
$1.6 billion and the aggregate outstanding borrowing from the money pool was $151.6 million. There were no borrowings outstanding from external sources. Under the SEC order and without further SEC authorization, the domestic utility companies and System Energy cannot issue new short-term indebtedness unless (a) Entergy and the 69
Entergy Corporation Notes to Consolidated Financial Statements borrower each maintain common equity of at least 30% of its capital and, (b) with the exception of money pool borrowings, the debt security to be issued (if rated) arnd all outstanding securities of the issuer and Entergy Corporation that are rated must be rated investment grade. There is further discussion of commitments for long-term financing arrangements in Note 5 to the consolidated financial statements. The short-term securities issuances of Entergy Corporation also are limited to amounts authorized by the SEC. Under its current SEC order and without further SEC authorization, Entergy Corporation cannot incur additiorial indebtedness or issue other securities unless (a) it and each of its public utility subsidiaries maintain a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of Entergy Corporation that are rated are rated investment grade.
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Entergy Corporation Notes to Consolidated Financial Statements NOTE 5. LONG - TERM DEBT Long-term debt as of December 31, 2004 and 2003 consisted of: 2004 2003 (In Thousands) Mortgage Bonds: 8.25% Series due April 2004 - Entergy Gulf States $292,000 6.2% Series due May 2004 - Entergy Mississippi 75,000 6.125% Series due July 2005 - Entergy Arkansas 100,000 100,000 8.125% Series due July 2005 - Entergy New Orleans 30,000 30,000
'6.77% Series due August 2005 - Entergy Gulf States 98,000 98,000 Libor + 0.90% Series due June 2007 - Entergy Gulf States 275,000 4.875% Series due October 2007 - System Energy 70,000 70,000 5.2% Series due December 2007 - Entergy Gulf States 200,000 6.5% Series due March 2008 - Entergy Louisiana 115,000 4.35% Series due April 2008 - Entergy Mississippi 100,000 100,000 6.45% Series due April 2008 - Entergy Mississippi 80,000 3.6% Series due June 2008 - Entergy Gulf States 325,000 325,000 3.875% Series due August 2008 - Entergy New Orleans 30,000 30,000 Libor + 0.40% Series due December 2009 - Entergy Gulf States 225,000 4.65% Series due May 2011 - Entergy Mississippi 80,000 4.875% Series due November 2011 - Entergy Gulf States 200,000 6.0% Series due December 2012 - Entergy Gulf States 140,000 140,000 5.15% Series due February 2013 - Entergy Mississippi 100,000 100,000 5.25% Series due August 2013 - Entergy New Orleans 70,000 70,000 5.09% Series due November 2014 - Entergy Louisiana 115,000 '5.6% Series due December 2014 - Entergy Gulf States 50,000 5.25% Series due August 2015 - Entergy Gulf States 200,000 200,000 6.75% Series due October 2017 - Entergy New Orleans 25,000 25,000 5.4% Series due May 2018 - Entergy Arkansas 150,000 150,000 4.95% Series due June 2018 - Entergy Mississippi 95,000 95,000 5.0% Series due July 2018 - Entergy Arkansas 115,000 115,000 5.5% Series due April 2019 - Entergy Louisiana 100,000 8.0% Series due March 2023 - Entergy New Orleans 45,000 7.7% Series due July 2023 - Entergy Mississippi 60,000 7.55% Series due September 2023 - Entergy New Orleans 30,000 7.0% Series due October 2023 - Entergy Arkansas 175,000 175,000 5.6% Series due September 2024 - Entergy New Orleans 35,000 5.65% Series due September 2029 - Entergy New Orleans 40,000 6.7% Series due April 2032 - Entergy Arkansas 100,000 100,000 7.6% Series due April 2032 - Entergy Louisiana 150,000 150,000 6.0% Series due November 2032 - Entergy Arkansas 100,000 100,000 6.0% Series due November 2032 - Entergy Mississippi 75,000 75,000 7.25% Series due December 2032 - Entergy Mississippi 100,000 100,000 5.9% Series due June 2033 - Entergy Arkansas 100,000 100,000 6.20% Series due July 2033 - Entergy Gulf States 240,000 240,000 6.25% Series due April 2034 - Entergy Mississippi 100,000 6.4% Series due October 2034 - Entergy Louisiana 70,000 6.38% Series due November 2034 - Entergy Arkansas 60,000 Total mortgage bonds $3,763,000 $3,860,000 71
Entergy Corporation Notes to Consolidated Financial Statements 2004 2003 (In Thousands) Governmental Bonds (a): 5.45% Series due 2010, Calcasieu Parish - Louisiana $22,095 $22,095 6.75% Series due 2012, Calcasieu Parish - Louisiana 48,285 48,285 6.7% Series due 2013, Pointe Coupee Parish - Louisiana 17,450 17,450 5.7% Series due 2014, Iberville Parish - Louisiana 21,600 21,600 7.7% Series due 2014, West Feliciana Parish - Louisiana 94,000 94,000 5.8% Series due 2015, West Feliciana Parish - Louisiana 28,400 28,400 7.0% Series due 2015, West Feliciana Parish - Louisiana 39,000 39,000 7.5% Series due 2015, West Feliciana Parish - Louisiana 41,600 41,600 9.0% Series due 2015, West Feliciana Parish - Louisiana 45,000 45,000 5.8% Series due 2016, West Feliciana Parish - Louisiana 20,000 20,000 6.3% Series due 2016, Pope County - Arkansas (h) 19,500 19,500 5.6% Series due 2017, Jefferson County - Arkansas 45,500 45,500 6.3% Series due 2018, Jefferson County - Arkansas (h) 9,200 9,200 6.3% Series due 2020,, Pope County - Arkansas 120,000 120,000 6.25% Series due 2021, Independence County - Arkansas (h) 45,000 45,000 7.5% Series due 2021, St. Charles Parish - Louisiana (h) 50,000 50,000 5.875% Series due 2022, Mississippi Business Finance Corp. 216,000 216,000 5.9% Series due 2022, Mississippi Business Finance Corp. 102,975 102,975 7.0% Series due 2022, Warren County - Mississippi 8,095 7.0% Series due 2022, Washington County - Mississippi 7,935 7.0% Series due 2022, St. Charles Parish - Louisiana (h) 24,000 24,00 7.05% Series due 2022, St. Charles Parish - Louisiana (h) 20,000, 20,000 Auction Rate due 2022, Independence County - Mississippi (h) 30,000, K30,000 4.6% Series due 2022, Mississippi Business Finance Corp.; 16,030., 5.95% Series due 2023, St. Charles Parish - Louisiana (h) 25,000 25,000 6.2% Series due 2023, St. Charles Parish - Louisiana (h) 33,000 -33,000 6.875% Series due 2024, St. Charles Parish - Louisiana (h) 20,400, 20,400 6.375% Series due 2025, St. Charles Parish - Louisiana 16,770 16,770 7.3% Series due 2025, Claiborne County - Mississippi ,,- 7,625 6.2% Series due 2026, Claiborne County - Mississippi 90,000 I, ,90,900pO 5.05% Series due 2028, Pope County - Arkansas (b) 47,000, - 47,000 5.65% Series due 2028, West Feliciana Parish - Louisiana (c) 62,000 6.6% Series due 2028, West Feliciana Parish - Louisiana 40,000 . 40,000 5.35% Series due 2029, St. Charles Parish - Louisiana (i) Auction Rate due 2030, St. Charles Parish - Louisiana (h) 60,000 60,000 4.9% Series due 2030, St. Charles Parish - Louisiana (d) (e) 55,000 1 55,000 Total governmental bonds 1,462,805 1,532,430 Other Long-Term Debt: Note Payable to NYPA, non-interest bearing, 4.8%,implicit rate $445,605 $514,708 3 year Bank Credit Facility (Entergy Corporation and Subsidiaries, Note 4) i .50,000 Bank term loan, Entergy Corporation, avg rate 2.98%, due 2005 60,000 60,000 Bank term loan, Entergy Corporation, avg rate 3.08%j due 2008, 35,000 35,000 6.17% Notes due March 2008, Entergy Corporation ,72,000 72,000 6.23% Notes due March 2008, Entergy Corporation 15,000 15,000 6.13% Notes due September 2008, Entergy Corporation 150,000 150,000 72
Entergy Corporation Notes to Consolidated Financial Statements 2004 2003 (In Thousands) Other Long-Term Debt (continued): 7.75% Notes due December 2009, Entergy Corporation 267,000 267,000 6.58% Notes due May 2010, Entergy Corporation 75,000 75,000 6.9% Notes due November 2010, Entergy Corporation 140,000 140,000 7.06% Notes due March 2011, Entergy Corporation 86,000 86,000 Long-term DOE Obligation (f) 156,332 154,409 Waterford 3 Lease Obligation 7.45% (Entergy Corporation and Subsidiaries, Note 9) 247,725 262,534 Grand Gulf Lease Obligation 5.01% (Entergy Corporation and Subsidiaries, Note 9) 397,119 403,468 Unamortized Premium and Discount - Net (10,277) (11,853) 8.5% Junior Subordinated Deferrable Interest Debentures Due 2045 - Entergy Arkansas 61,856 8.75% Junior Subordinated Deferrable Interest Debentures Due 2046 - Entergy Gulf States 87,629 87,629 9.0% Junior Subordinated Deferrable Interest Debentures Due 2045 - Entergy Louisiana 72,165 Other 9,457 9,966 Total Long-Term Debt 7,509,395 7,847,312 Less Amount Due Within One Year t . 492,564 -524,372 Long-Term Debt Excluding Amount Due Within One Year $7,016,831 $7,322,940 Fair Value of Long-Term Debt (g) $6,614,211 , $7,123,706 (a) Consists of pollution control revenue bonds and environmental revenue bonds. (b) The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on September 1, 2005 and can then be remarketed. (c) The bonds had a mandatory tender date of September 1, 2004. Entergy Gulf States purchased the bonds from the holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time. (d) On June 1, 2002, Entergy Louisiana remarketed $55 million St. Charles Parish Pollution Control Revenue Refunding Bonds due 2030, resetting the interest rate to 4.9% through May 2005. (e) The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on June 1, 2005 and can then be remarketed. ' (f) Pursuant to the Nuclear Waste Policy Act of 1982, Entergy's nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes' the one-time fee, plus accrued interest, in long-term debt. (g) The fair value excludes lease obligations and long-term DOE obligations, and includes debt due within one year. It is determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. (h) The bonds are secured by a series of collateral first mortgage bonds. (i) The bonds in the principal amount of $110.95 million had a mandatory tender date of October 1, 2003. Entergy Louisiana purchased the bonds from the' holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time. 73
Entergy Corporation Notes to Consolidated Financial Statements The annual long-term debt maturities (excluding lease obligations) for debt outstanding as of December 31, 2004, for the next five years are as follows: (In Thousands) 2005 $467,298 2006 $75,896 2007 $199,539 2008 $747,246 2009 $512,584 In November 2000,- Entergy's Non-Utility Nuclear business purchased the FitzPatrick and Indian Point 3 power plants in a seller-financed transaction. Entergy issued notes to NYPA with seven annual installments of approximately $108 million commencing one year from the date of the closing, and eight annual installments of $20 million commencing eight years from the date of the closing. These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%. In accordance with the purchase agreement with NYPA; the purchase of Indian Point 2 in 2001 resulted in Entergy's Non-Utility Nuclear business becoming liable to NYPA for an additional $10 million per year for 10 years, beginning in September 2003.- This -liability was recorded upon the purchase of Indian Point 2 in September 2001, and is included in the note payable to NYPA balance above. In July 2003, a payment of $102 million was made prior to maturity on the note payable to NYPA. Under a provision in a letter of credit supporting these notes, if certain of the domestic utility companies or System Energy were to default on other indebtedness, Entergy could be required to post collateral to support the letter of credit. Covenants in the Entergy Corporation notes require it to maintain a consolidated debt ratio of 65% or less of its total capitalization. If Entergy's debt ratio exceeds this limit, or if Entergy or certain of the domestic utility companies default on other indebtedness or are in bankruptcy or insolvency proceedings, an acceleration of the notes' maturity dates may occur. The long-term securities issuances of Entergy. Corporation, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and System Energy also are limited to amounts authorized by the SEC,., Under its current SEC order, and without further authorization, Entergy Corporation cannot incur additional indebtedness or issue other securities unless (a) it and each of its public utility subsidiaries maintain a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of Entergy Corporation that are rated,, are rated investment grade by at least one nationally recognized statistical rating agency. Under their current SEC orders, and without further authorization, Entergy Gulf States, Entergy Louisiana, and Entergy Mississippi cannot incur additional indebtedness or issue other securities unless (a) the issuer and Entergy Corporation maintains a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all outstanding securities of the, issuer (other than preferred stock of Entergy Gulf States), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. Junior Subordinated Deferrable Interest Debentures and Implementation of FIN 46 Entergy implemented FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" effective December 31, 2003. FIN 46 requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among their investors. Variable interest entities (VIEs), generally, are entities that do not have sufficient equity to permit the entity to finance its operations without additional financial support from its equity interest holders and/or the group of equity interest holders are collectively not able to exercise control over the entity, The primary beneficiary is the party that absorbs a majority of the entity's expected losses, receives a majority of its expected residual returns, or both as a result of holding the variable interest. A company may have an interest in a VIE through ownership or other contractual rights or obligations. Entergy Louisiana Capital I, Entergy Arkansas Capital I, and Entergy Gulf States Capital I (Trusts) were established as financing subsidiaries of Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States, 74
Entergy Corporation Notes to Consolidated Financial Statements respectively, (the parent company or companies, collectively) for the purposes of issuing common and preferred securities. The Trusts issued Cumulative Quarterly Income Preferred Securities (Preferred Securities) to the public and issued common securities to their parent companies. Proceeds from such issues were used to purchase junior subordinated deferrable interest debentures (Debentures) from the parent company. The Debentures held by each Trust are its only assets. Each Trust uses interest payments received on the Debentures owned by it to make cash distributions on the Preferred Securities and common securities. The parent companies fully and unconditionally guaranteed payment of distributions on the Preferred Securities issued by the respective Trusts. Prior to the application of FIN 46, each parent company consolidated its interest in its Trust. Because each parent company's share of expected losses of its Trust is limited to its investment in its Trust, the parent companies are not considered the primary beneficiaries and therefore de-consolidated their interest in the Trusts upon application of FIN 46 with no significant impacts to the financial statements. The parent companies' investment in the Trusts and the-Debentures issued by each parent company are included in Other Property and Investments and Long-Term Debt, respectively. Capital Funds Agreement Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:
- maintain System Energy's equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);
- permit the continued commercial operation of Grand Gulf 1;
- pay in full all System Energy indebtedness for borrowed money when due; and
- enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy's rights in the agreement as security for the specific debt.
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Entergy Corporation Notes to Consolidated Financial Statements NOTE 6. PREFERRED STOCK The number of shares authorized and outstanding and dollar value of preferred stock and minority interest for Entergy Corporation subsidiaries as of December 31, 2004 and 2003 are presented below. Only the Entergy Gulf States series "with sinking fund" contain mandatory redemption requirements. All other series of the U.S. Utility are redeemable at Entergy's option. ; Shares Shares Authorized Outstanding 2004 2003' 2004 - `:2003 2004 2003 Enterov Corporation (Dollars in Thousands) U.S. Utility: Preferred Stock without sinking fund: Entergy Arkansas, 4.32%-7.88% Series 1,613,500 1,613,500 1,613,500 1,613,500 $116,350 $116,350 Entergy Gulf States, 4.20%-7.56% Series 473,268 473,268 473,268 473,268 47,327 47,327 Entergy Louisiana, 4.16%-8.00% Series 2,115,000 2,115,000 2,115,000 2,115,000 100,500 100,500 Entergy Mississippi, 4.36%-8.36% Series 503,807 503,807 503,807 503,807 50,381 50,381 Entergy New Orleans, 4.36%-5.56% Series 197,798 197,798 197,798 197,798 19,780 19,780 Total U. S. Utility Preferred Stock without sinking fund 4,903,373 4,903,373 4,903,373 4,903,373 334,337 334,337 Energy Commodity Services: Preferred Stock without sinking fund: Entergy Asset Management, 11.50% rate I 1,000,000 - 297,376 - 29,738 Other - 1,281 Total Preferred Stock without sinking fund 5,903,373 4,903,373 5,200,749 4,903,373 $365,356 $334,337 U.S. Utility: Preferred Stock with sinking fund: Entergy Gulf States, Adjustable Rate 7.0% (a) 174,000 208,520 174,000 208,520 $17,400 $20,852 Total Preferred Stock with sinking fund 174,000 208,520 174,000 208,520 $17,400 $20,852 Fair Value of Preferred Stock with sinking fund (b) $15,286 $15,354 (a) Represents weighted-average annualized rate for 2004 and 2003. (b) Fair values were determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. There is additional disclosure of fair value of financial instruments in Note 14 to the consolidated financial statements. All outstanding preferred stock is cumulative. Entergy Gulf States' preferred stock with sinking fund retirements were 34,500 shares in 2004 and 2003, and 18,579 shares in 2002. Entergy Gulf States has annual sinking fund requirements of $3.45 million through 2009 for its preferred stock outstanding. In 2004, Entergy realized a pre-tax gain of $0.9 million upon the sale to a third party of preferred shares, and less than 1% of the common shares, of Entergy Asset Management, an Entergy subsidiary. See Note 3 to the consolidated financial statements for a discussion of the tax benefit realized on the sale. Entergy Asset Management's stockholders' agreement provides that at any time during the 180-day period prior to December 31, 2007 or each subsequent December 31 thereafter, either Entergy Asset Management or the preferred shareholders may request that the preferred dividend rate be reset. If Entergy Asset Management and the preferred shareholders 76
Entergy Corporation Notes to Consolidated Financial Statements are unable to agree on a dividend reset rate, a preferred shareholder can request that its shares be sold to a third party. If Entergy Asset Management is unable to sell the preferred shares within 75 days, the preferred shareholder has the right to take control of the Entergy Asset Management board of directors for the purpose of liquidating the assets of Entergy Asset Management in order to repay the preferred shares and any accrued dividends. NOTE 7. COMMON EQUITY Common Stock Treasury Stock Treasury stock activity for Entergy for 2004 and 2003 is as follows: 2004 2003 Treasury Shares Cost Treasury Shares Cost (InThousands) (InThousands) Beginning Balance, January I 19,276,445 $561,152 25,752,410 $747,331 Repurchases 16,631,800 1,017,996 155,000 8,135 Issuances: Employee 'Stock-Based Compensation Plans (4,555,897) (146,877) (6,622,095) (194,057) Directors' Plan (7,320) (252) (8,870) (257) Ending Balance, December 31 31,345,028 $1,432,019 19,276,445 $561,152 Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors' Plan), the Equity Ownership Plan of Entergy Corporation and Subsidiaries (Equity Ownership Plan), the Equity Awards Plan of Entergy Corporation and Subsidiaries, and certain other stock benefit plans. The Directors' Plan awards to non-employee directors a portion of their compensation in the form of a fixed number of shares of Entergy Corporation common stock. Equity Compensation Plan Information Entergy grants stock options, equity awards, and incentive awards to key employees of the Entergy subsidiaries under the Equity Ownership Plan which is a shareholder-approved stock-based compensation plan. Stock options are granted at exercise prices not less than market'value on the date of grant. The majority of options granted in 2004, 2003, and 2002 will become exercisable in equal amounts on each of the first three anniversaries of the date of grant. Unless they are forfeited previously under the terms of the grant, options expire ten years after the date of the grant if they are not exercised. Entergy grants most of the equity awards and incentive awards earned under its stock benefit plans in the form of performance units, which are equal to the cash value of shares of Entergy Corporation common stock at the time of payment. In addition to the potential for equivalent share appreciation or depreciation, performance units will earn the cash equivalent of the dividends paid during the performance period applicable to each plan. The costs of equity and incentive awards, given either as company stock or performance units, are charged to income over the period of the grant or restricted period, as appropriate. In 2004, 2003, and 2002, $47 million, $45 million, and $28 million, respectively, was charged to compensation expense. Entergy was assisted by external valuation firms to determine the fair value of the stock option grants made in 2004 and 2003. The fair value applied to these grants was an average of two firms' option valuations, which included, adjustments for factors such as lack of marketability, stock retention requirements, and regulatory restrictions on exercisability. In 2002, the fair value of each option grant was estimated on the date of grant using 77
Entergy Corporation Notes to Consolidated Financial Statements the Black-Scholes option-pricing model, without any such adjustments. The stock option weighted-average assumptions used in determining the fair values were as follows: 2004 2003 2002 Stock price volatility 23.1% 26.3% 27.2% Expected term in years 6.3 6.2 5.0 Risk-free interest rate 3.2% 3.3% 4.2% Dividend yield 3.3% 3.3% 3.2% Dividend payment $1.80 $1.40 $1.32 Stock option transactions are summarized as follows: 2004 2003 2002 Average Average Average Number Exercise Number Exercise Number Exercise of Options Price of Options Price of Options Price Beginning-of-year balance 15,429,383 $38.64 19,943,114 $35.85 17,316,816 $31.06 Options granted 1,898,098 $58.63 2,936,236 $44.98 , 8,168,025 $41.72 Options exercised (4,541,053) $38.07 (6,927,000) $33.12 (4,877,688) $28.62 Options forfeited/expired (476,351) $39.94 (522,967) $40.98 (664,039) , $36.36 End-of-year balance 12,310,077 $41.88 15,429,383 $38.64 19,943,114 $35.85 7,1 8 $2 3 $3 4 . 8 2 ' . Options exercisable at year-end 7,162,884 $37.25 6,153,043; $34.82 - 4,837,51 1 $31.39 1 . , Weighted-average fair value of options at time of grant $7.76 $6.86 $9.22 The following table summarizes information about stock options outstanding as of December 31, 2004: Options Outstanding Options Exercisable "' Weighted-Avg. . .i. Remaining Weighted- Number 'Weighted-Range of As of Contractual Avg. Exercise Exercisable' Avg. Exercise i Exercise Prices 12/31/2004 Life-Yrs. Price- at 12/31/2604 ' Price
$23 - $33.99 1,674,430 5.0 $26.28 1,674,430 $26.28 .
, .; . I f , -
$34 - $44.99 8,547,519 7.1 $41.09 5,195,493 $39.95
$45 - $55.99 230,445 5.6 $49.61 222,378"' $49.68 7, 8 . 9. 67 I
$56 - $67.99 1,857,683 9.1 $58.64 ,, 70,583,. $59.67
$ 1.
$23 - $67.99 12,310,077 7.1 $41.88 I 7,162,884 '$37.25 78
Entergy Corporation Notes to Consolidated Financial Statements Retained Earnings and Dividend Restrictions Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation's subsidiaries restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2004, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to Entergy Corporation. In 2004, Entergy Corporation received dividend payments totaling $825 million from subsidiaries. Investments in affiliates that are not controlled by Entergy Corporation, but over which it has-significant influence, are accounted for using the equity method. Entergy's retained earnings for 2003 included $472 million of undistributed earnings of equity method investees. Due to the receipt of dividends from Entergy-Koch, 1LP after the sale of its energy trading and pipeline businesses in 2004, there were no undistributed earnings in Ertergy's retained earnings at December 31, 2004. Equity method investments are discussed in Note 12 to the consolidated financial statements. NOTE 8. ;,COMMITMENTS AND CONTINGENCIES Entergy is involved in a number of legal, tax, and regulatory proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of its business. While management is'unable to predict the outcome of such proceedings, management does not believe that the ultimate resolution of these matters will have a material adverse effect on Entergy's results of operations, cash flows, or financial condition. Vidalia Purchased Power Agreement Entergy Louisiana has an agreement extending through the year 2031 to purchase energy generated by a hydroelectric facility known as the Vidalia project. Entergy Louisiana made payments under the contract of approximately $147.7 million in 2004, $112.6 million in 2003, and $104.2 million in 2002. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $125.3 million in 2005, and a total of $3.5 billion for the years 2006 through 2031. Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause. In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $11 million each year for up to ten years, beginning in October 2002. The provisions of the settlement also provide that the LPSC shall not recognize or use Entergy Louisiana's use of the cash benefits from the tax treatment in setting any of Entergy Louisiana's rates. Therefore, to the extent' Entergy Louisiana's use of the proceeds would ordinarily have reduced its rate base, no change in rate base shall be reflected for ratemaking purposes. Nuclear Insurance ' ; Third Party Liability Insurance' The Price-Anderson Act provides insurance for the public in the event of a nuclear power plantfaccident. The costs of this insurance are borne by the nuclear power industry. Originally passed by Congress in 1957 and most recently amended in 1988, the Price-Anderson Act requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident. This protection must consist of two levels:
- 1. The primary level is private insurance underwritten by American Nuclear Insurers and provides liability insurance coverage of $300 million. If this amount is not sufficient to cover claims arising from the accident, the second level, Secondary Financial Protection, applies. An industry-wide aggregate limitation of $300 million exists for domestically-sponsored terrorist acts. There is-no limitation for foreign-sponsored terrorist acts. ,
79
Entergy Cbrporation Notes to Consolidated Financial Statements
- 2. Within the Secondary Financial Protection level, each nuclear plant must pay a retrospective premium,
- equal'to its proportionate share of the loss in excess of the jrimary level, up to a maximum of $100.6 million per reactor per incident. This consists of a $95.8 million maximum retrospective'premium plus a five percent surcharge thatfmay'be applied, if needed, at a rate that is presently set at $10 million per year per nuclear power reactor. 'There are nd domestically- or foreign-sponsored terrorism limitations.
Currently, 104 nuclear reactors are participating in the SecoindarylFinancial Protection program - 103' operating reactors and one closed reactor that still 'stores used nuclear fuel on site. 'The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactors provides over $10 billion in insurance coverage to'compensate the public in the event of a nuclear power reactor accident.
- Entergy owns and operates ten of the nuclear power reactors, and owns the shutdown Indian Point 1 reactor (10% 'of Grand Gulf is owned by a non-affiliated company which would share on a pro-rata basis in any retrospective premium assessment under the Pride-Anderson Act).
An additional but temporary contingent liability exists for all nuclear power reactor owners because of a previous Nuclear Worker Tort (long-term bodily injury caused by exposure to nuclear radiation while employed at a nuclear power plant) insurance program that was in place from 1988 to 1998. The maximum premium assessment exposure to each reactor is $3 million and will only be applied if such claims exceed the program's accumulated reserve funds. This contingent premium assessment feature will expire with the Nuclear Worker Tort program's expiration, which is scheduled for 2008. Property Insurance Entergy's nuclear owner/licensee subsidiaries are members of certain mutual insurance companies that provide property damage coverage,including decontamination and premature decommissioning expense, to the members' nuclear generating plants. These 'programs are underwritten by Nuclear Electric Insurance Limited (NEIL). As of December 31; 2004, Entergy was insured against such losses per the following structures U.S. Utility Plants (ANO I and 2 Grand Gulf. River Bend, and Waterford 3) Primnary L'ayer (per plant) - $500 million per occirrence
- Exc~ess Layer (per plant) $100 million per'occurrence
- Blanket Layer (shared among all plants) - $1.0 billion per occurrence
- Total limit - $1.6,billion per occurrence ,
- Deductibles' ;- ' - ,
* $5.0 million per occurrence - Turbine/generator damage .
* $5.0 million per occurrence - Other than turbine/generator damage Note: ANO I and 2 share in the Primary Layer with one policy in common.
Non-Utility Nuclear Plants (Indian Point 2 and 3, FitzPatrick. Pilgrim. and Vermont Yankee!
- Primary Layer (per plant) - $500 million per occurrence
*; Blanket Layer (shared among all plants) - $615 million per occurrence
- Total limit - $1.115 billion per occurrence
- Deductibles:
* $1.0 million'per occurrence - Turbine/generator damage
* $2.5 million per occurrence - Other than turbine/generator damage Note: Indian Point 2 and 3 share in the Primary Layer with one policy in common.
In iddition, the Non-Utility' Nuclear plants'are also covered under NEIL's Accidental Outage Coverage program. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a 80
Entergy Corporation Notes to Consolidated Financial Statements covered NEIL property damage loss, subject to a deductible. The following summarizes this coverage as of December 31, 2004: Indian Point 2 and 3
* $4.5 million weekly indemnity
* $490 million maximum indemnity
- Deductible: 12 week waiting period, FitzPatrick and Pilgrim (each plant has an individual policy with the noted parameters)
* $4.0 million weekly indemnity * ,
' $490 million maximum indemnity
- Deductible: 12 week waiting period Vermont Yankee
* $3.5 million weekly indemnity
* $435 million maximum indemnity
- Deductible: 12 week waiting period Entergy's U.S. Utility nuclear plants have significantly less or no accidental outage coverage. Under the property damage and accidental outage insurance programs, Entergy nuclear plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. As of December 31, 2004, the maximum amounts of such possible assessments per occurrence were $50.8 million for the U.S. Utility plants and $68.9 million for the Non-Utility Nuclear plants.
Entergy maintains property insurance for its nuclear units in excess of the NRC's minimum requirement of $1.06 billion per site for nuclear power plant licensees. NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. -Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors. In the event that one or more acts of domestically-sponsored terrorism causes property damage under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such' nuclear insurance policies shall be an aggregate of $3.2i billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses. There is no aggregate limit involving one or more acts of foreign-sponsored terrorism. Nuclear Decommissionine and Other Retirement Costs SFAS 143, "Accounting for Asset Retirement Obligations," which was implemented effective January 1, 2003, requires the recording of liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets.' For Entergy, these asset retirement obligations consist of its liability for deconimissioning its nuclear power plants. These liabilities are recorded at their fair values (which is the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives of the assets. The net effect of implementing SFAS 143 for the rate-regulated business of the domestic utility companies and System Energy was recorded as a regulatory asset, with no resulting impact on Entergy's net income. Entergy recorded these regulatory assets because existing rate mechanisms in each jurisdiction are based on the principle that Entergy will recover all ultimate costs 'of decommissioning from customers. 81
Entergy Corporation Notes to Consolidated Financial Statements Upon implementation of SFAS 143 in 2003, assets and liabilities increased $1.1 billion for the U.S. Utility segment as a result of recording the asset retirement obligations at their fair values of $1.1 billion as determined under SFAS 143, increasing utility plant by $287 million, reducing accumulated depreciation by $361 million, and recording the related regulatory assets of $422 million. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking decreased earnings by $21 million net-of-tax as a result of a one-time cumulative effect of accounting change. In accordance with ratemaking treatment and as required by SFAS 71, the depreciation provisions for the domestic utility companies and System Energy include a component for removal costs that are not asset retirement obligations under SFAS 143. In accordance with regulatory accounting principles, Entergy has recorded a regulatory asset for certain of its domestic utility companies and System Energy of $86.9 million as of December 31, 2004 and $72.4 million as of December 31, 2003 to reflect an estimate of incurred but uncollected removal costs previously recorded as a component of accumulated depreciation. The decommissioning and retirement cost liability for certain of the domestic utility companies and System Energy includes a regulatory liability of $34.6 million as of December 31, 2004 and $26.8 million as of December 31, 2003 representing an estimate of collected but not yet incurred removal costs. For the Non-Utility Nuclear business, the implementation of SFAS 143 resulted in a decrease in liabilities of $595. million due to reductions in decommissioning liabilities, a decrease in assets of $340 million, including a decrease in electric plant in service of $315 million, and an increase in earnings in 2003 of $155 million net-of-tax as a result of a one-time cumulative effect of accounting change. The cumulative decommissioning liabilities and expenses recorded in 2004 by Entergy were as follows.
-Change in Liabilities as of Cash Flow Liabilities as of December 31, 2003 Accretion Estimate Spending December'31, 2004 (In Millions)
U.S. Utility $1,504.1 $98.0 ,($274.1) -; . $1,328.0 Non-Utility Nuclear .$710.4, ,;; $57.6,;. ($20.3) ($9.4) , $738.3 In addition, an insignificant amount of removal costs associated with non-nuclear power plants are also included in the decommissioning line item on thebalance sheet., Entergy1 periodically. reviews and updates estimated decommissioning costs. The actual decommissioning costs- may vary from the estimatep because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment During 2004, Entergy updated decommissioning cost studies for ANO 1 and 2 and River Bend. In the first quarter of 2004, Entergy Arkansas recorded 'a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for ANO 1 and 2 as a result of revised decommissioning costs and changes in assumptions regarding the timing of when th1e decommissionirg of the plants will begin. The revised estimate resulted in a $107.7nmi1ion' reduction in its- decommissioninj liability; along with a $19.5 million reduction in utility plant and an $88.2 million reduction in the related regulatory, asset. In,the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected an expected life extension for the plant. The revised estimate resulted in a $166.41million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $49.6 million reduction in non-utility property, a $40.1 million reduction in the related regulatory asset, and a regulatory liabilityof $17.7 million. For the portio of RAver Bend not subject to cost-based rateznaking, thp revised estimate resulted in the elimination of the a, cost that had been recorded at the time of adoption of SFAS 143 with, the remainder recorded as miscellaneous other income of $27.7 million. l P. . l In the third quarter of 2004, Entergy's Non-Utility Nuclear business recorded a reduction of $20.3 niilli, in decommissioning liability to 'reflect changes Jin assumptions regarding the timing of when decommissioning of a plant will begin. Entergy considered the assumptions as part of recent studies evaluating the economic effect olthe plant in its region. The revised estimate resulted in miscellaneous other income of $20.3 million, reflecting ithe g2
Entergy Corporation Notes to Consolidated Financial Statements excess of the reduction in the liability over the amount of undepreciated asset retirement cost recorded at the time of adoption of SFAS 143. If Entergy had applied SFAS 143 during prior periods, the following impacts would have resulted: Year Ended December 31, 2002 Earnings applicable to common stock - as reported $599,360 Pro forma effect of SFAS 143 $14,119 Earnings applicable to common stock - pro forma $613,479 Basic earnings per average common share - as reported $2.69 Pro forma effect of SFAS 143 $0.06 Basic earnings per average common share - pro forma $2.75 Diluted earnings per average common share - as reported $2.64 Pro forma effect of SFAS 143 $0.06 Diluted earnings per average common share - pro forma $2.70 For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liability. NYPA and Entergy executed decommissioning agreements, which specify their decommissioning obligations. NYPA has the right to require Entergy to assume the decommissioning liability provided that it assigns the corresponding decommissioning trust, up to a specified level, to Entergy. If the decommissioning liability is retained by NYPA, Entergy will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. Entergy believes that the amounts available to it under either scenario are sufficient to cover the future decommissioning costs without any additional contributions to the trusts. Entergy maintains decommissioning trust funds that are committed to meeting the costs of decommissioning the nuclear power plants. The fair values of the decommissioning trust funds and asset retirement obligation-related regulatory assets of Entergy as of December 31, 2004 are as follows: Decommissioning Regulatory Trust Asset (In Millions) U.S. Utility $1,052.0 $380.1 Non-Utility Nuclear $1,401.6 The Energy Policy Act of 1992 contains a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning (D&D) of the DOE's past uranium enrichment operations. Annual assessments in 2004 were $4.4 million for Entergy Arkansas, $1.1 million for Entergy Gulf States, $1.6 million for Entergy Louisiana, and $1.8 million for System Energy. The Energy Policy Act calls for cessation of annual D&D assessments not later than October 24, 2007. At December 31, 2004, two years of assessments were remaining. D&D fees are included in other current liabilities and other non-current liabilities and, as of December 31, 2004, recorded liabilities were $8.8 million for Entergy Arkansas, $1.9 million for Entergy Gulf States, $3.3 million for Entergy Louisiana, and $3.3 million for System Energy. Regulatory assets in the financial statements offset these liabilities, with the exception of Entergy Gulf States' 30% non-regulated portion. These assessments are recovered through rates in the same manner as fuel costs. 83
Entergy Corporation Notes to Consolidated Financial Statements Income Taxes Entergy is currently under audit by the IRS with respect to tax returns for tax periods subsequent to 1995 and through 2001, and is subject to audit by the IRS and other taxing authorities for subsequent tax periods. The amount and timing of any tax assessments resulting from these audits are uncertain, and could have a material effect on Entergy's financial position and results of operations. Entergy believes that the contingency provisions established in its financial statements will sufficiently cover the risk associated with tax matters. Certain material audit matters as to which management believes there is a reasonable possibility of a future tax assessment are discussed below. See Note 3 to the consolidated financial statements for additional discussion of income taxes. Foreign Tax Credits In July 1997, the UK government enacted the Windfall Tax, which was a one-time tax imposed on formerly government-owned companies in regulated industries. The Windfall Tax applied to companies that the government had previously privatized in the telecommunication, airport operation, gas, water, electricity, and railway industries. London Electricity, the UK public limited company purchased and subsequently sold by Entergy, was subject to the UK Windfall Tax. Entergy fulfilled its obligation with respect to the tax in 1997 and 1998. In subsequent tax years, Entergy reported a foreign tax credit for the UK Windfall Tax that London Electricity paid. Entergy has claimed a net tax benefit of $152 million related to this foreign tax credit. During 2004, the IRS proposed to disallow this foreign tax credit. Entergy disagreed with the position of the IRS and protested the disallowance of the credit to the Office of IRS Appeals. Entergy expects to receive a Notice of Deficiency in 2005 for this item, and plans to vigorously contest this matter. The. amount at issue including tax and interest as of December 31, 2004 is $195 million. Entergy believes that the contingency provision established in its financial statements will sufficiently cover the risk associated with this dispute.
, . .' 1 I :
Depreciable Property Lives - During the years 1997 through 2004, Entergy subsidiaries, Entergy Services, Entergy Arkansas; Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy Resources reflected changes in tax depreciation methods with respect to certain types of depreciable property. (e.g. street; lighting, billing meters, and various generation plant equipment). The cumulative effect of these changes results in additional depreciation deductions generating a cash flow benefit of approximately $152 milliof as of December 31, 2004. The related IRS interest exposure if the deduction is ultimately disallowed is $44 million at December 31, 2004. This benefit reverses over time and will also fluctuate with each year's addition to those types of assets. Due to the temporary nature of the tax benefit, the potential interest charge represents the total net earnings exposure of Entergy. For the years under audit, 1996-2001, the IRS challenged Entergy's classification of these assets and proposed adjustments to the depreciation deductions taken. Entergy disagrees with the position of the IRS and has protested the disallowance of these deductions to the Office of IRS Appeals. Entergy expects to receive a Notice of Deficiency in 2005 for this item, and plans to vigorously contest this matter. Entergy believes that the contingency provision established in its financial statements sufficiently covers the risk associated with this item. Mark to Narket of Certain Power Contracts In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts. The most significant of these is, the, contract to purchase power from the Vidalia hydroelectric project. The new tax accounting method. has provided a cumulative cash flow benefit; of approximately $790 million as of December 31, 2004. The related IRS interest exposure is $93! million at December 31, 2004. This benefit is expected to reverse in the years 200$ through 2031. The election, did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. Due to the temporary nature of the tax benefit, the potential interest charge represents Entergy's net earnings exposure. Entergy Louisiana's 2001 tax return is currently under examination by the IRS, though no 84
Entergy Corporation Notes to Consolidated Financial Statements adjustments have yet been proposed with respect to the mark to market election. Entergy believes that the contingency provision established in its financial statements will sufficiently cover the, risk associated with this issue. CashPoint Bankruptcy In 2003 the domestic utility companies entered an agreement with CashPoint Network Services (CashPoint) under which CashPoint was to manage a network of payment agents through which Entergy's utility customers could pay their bills. The payment agent system allows customers to pay their bills at varidus commercial or governmental locations, rather than sending payments by mail. Approximately one-third of Entergy's utility customers use payment agents. On April 19, 2004, CashPoint failed to pay funds due to the domestic utility companies that had been collected through payment agents. The domestic utility companies then obtained a temporary restraining order from the Civil District Court for the Parish of Orleans, State of Louisiana, enjoining CashPoint from distributing funds belonging to Entergy, except by paying those funds to Entergy. On April 22, 2004, a petition for involuntary Chapter 7 bankruptcy was filed against CashPoint by other creditors in the United States Bankruptcy Court for the Southern District of New York. In response to these events, the domestic utility companies expanded an existing contract with another company to manage all of their payment agents. The domestic utility companies filed proofs of claim in the CashPoint bankruptcy proceeding in September 2004. Although Entergy cannot precisely determine at this time the amount that CashPoint owes to the domestic utility companies that may not be repaid, it has accrued an estimate of loss based on current information. If no cash is repaid to the domestic utility companies, an event Entergy does not believe is likely, the current estimate of maximum exposure to loss is approximately $25 million. Employment Litigation Entergy Corporation and certain subsidiaries are defendants in numerous lawsuits filed by former employees asserting that they were wrongfully terminated and/or discriminated against on the basis of age, race, sex, and/or other protected characteristics. Entergy Corporation and these subsidiaries are vigorously defending these suits and deny any liability to the plaintiffs. Nevertheless, no assurance can be given as to the outcome of these cases. NOTE 9. LEASES General As of December 31, 2004, Entergy had capital leases and non-cancelable operating leases for equipment, buildings, vehicles; and fuel storage facilities (excluding nuclear fuel leases and the Grand Gulf and Waterford 3 sale and leaseback transactions) with minimum lease payments as follows: , Operating Capital Year Leases Leases (In Thousands) 2005 $99,246- $9,660 2006 85,769 5,724 2007 68,557 3,438 2008 55,155 1,754 2009 45,240 237 Years thereafter 210,474 2,606 Minimum lease payments 564,441 23,419 Less: Amount representing interest - 3,388 Present value of net minimum lease payments $564,441 $20,031 85
Entergy Corporation Notes to Consolidated Financial Statements Total rental expenses for all leases (excluding nuclear fuel leases and the Grand Gulf and Waterford 3 sale and leaseback transactions) amounted to $81.3 million in 2004, $84.3 million in 2003, and $92.2 million in 2002. Nuclear Fuel Leases As of December 31, 2004, arrangements to lease nuclear fuel existed in an aggregate amount up to $150 million for Entergy Arkansas, $105 million for Entergy Gulf States, $80 million for Entergy Louisiana, and $110 million for System Energy. As of December 31, 2004, the unrecovered cost base of nuclear fuel leases amounted to approximately $93.9 million for Entergy Arkansas, $71.2 million for Entergy Gulf States, $31.7 million for Entergy Louisiana, and $65.6 million for System Energy. The lessors finance the acquisition and ownership of nuclear fuel through loans made under revolving credit agreements, the issuance of commercial paper, and the issuance of intermediate-term notes. The credit agreements for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy each have a termination date of October 30, 2006. The termination dates may be extended from time to time with the consent of the lenders. The intermediate-term notes issued pursuant to these fuel lease arrangements have varying maturities through February 15, 2009. It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. However, if such additional financing cannot be arranged, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations in accordance with the fuel lease. Lease payments are based on nuclear fuel use. The total nuclear fuel lease payments (principal and interest) as well as the separate interest component charged to operations by the domestic utility companies and System Energy were $146.6 million (including interest of $12.8 million) in 2004, $142.0 million (including interest of $11.8 million) in 2003, and $137.8 million (including interest of $11.3 million) in 2002. Sale and Leaseback Transactions Waterford 3 Lease Obligations In 1989, Entergy Louisiana sold and leased back 9.3% of its 'interest in Waterford 3 for the aggregate sum of $353.6 million. The lease has an approximate term of 28 years. The lessors financed the sale-leaseback through the issuance of Waterford 3 Secured Lease Obligation Bonds. The lease payments made by Entergy Louisiana are sufficient to service the debt. In 1994, Entergy Louisiana did not exercise its option to repurchase the 9.3% interest in Waterford 3. As a result, Entergy Louisiana issued $208.2 million of non-interest bearing first mortgage bonds as collateral for the equity portion of certain amounts payable under the lease. In 1997, the lessors refinanced the outstanding bonds used to finance the purchase of Waterford 3 at lower interest rates, which reduced the annual lease payments. Upon the occurrence of certain events, Entergy Louisiana may be obligated to assume the outstanding bonds used to finance the purchase of the unit and to pay an amount' sufficient to withdraw from the lease transaction. Such events include lease events of default, events of loss, deemed loss events, or certain adverse "Financial Events." "Financial Events" include, among other things, failure by Entergy Louisiana, following the expiration of any applicable grace or cure period, to maintain (i) total equity capital (including preferred stock) at least equal to 30% of adjusted capitalization, or (ii) a fixed charge coverage ratio of at least 1.50 computed on a rolling 12 month basis. As of December 31, 2004, Entergy Louisiana's total equity capital (including preferred stock) was 51.33% of adjusted capitalization and its fixed charge coverage ratio for 2004 was 3.76. 86
Entergy Corporation Notes to Consolidated Financial Statements As of December 31, 2004 Entergy Louisiana had future minimum lease payments (reflecting an overall implicit rate of 7.45%) in connection with the Waterford 3 sale and leaseback transactions, which are recorded as long-term debt, as follows: (In Thousands) 2005 $14,554 2006 18,261 2007 18,754 2008- 22,606 2009 32,452 Years thereafter 334,062 Total 440,689 Less: Amount representing interest 192,964 Present value of net minimum lease payments $247,725 Grand Gulf Lease Obligations In December 1988, System Energy sold 11.5% of its undivided ownership interest in Grand Gulf for the aggregate sum of $500 million. Subsequently, System Energy leased back its interest in the unit for a term of 26-1/2 years. System Energy has the option of terminating the lease and repurchasing the 11.5% interest in the unit at certain intervals during the lease. Furthermore, at the end of the lease term, System Energy has the option of renewing the lease or repurchasing the 11.5% interest in Grand Gulf. In May' 2004 System Energy caused the Grand Gulf lessors to refinance the outstanding bonds that they had issued to finance the purchase of their undivided interest in Grand Gulf. The refinancing is at a lower interest rate, and System Energy's lease payments have been reduced to reflect the lower interest costs.. System Energy is required to report the sale-leaseback as a financing transaction in its financial statements. For financial reporting purposes, System Energy expenses the interest portion of the lease obligation and the plant depreciation. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes. Consistent with a recommendation contained in a FERC audit report, System Energy recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and is recording this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance at the end of the lease term. The amount of this net regulatory asset was $75.4 million and $83.2 million as of December 31, 2004 and 2003, respectively. As of December 31, 2004 System Energy had future minimum lease payments (reflecting an implicit rate of 5.01%), which are recorded as long-term debt as follows: (In Thousands) 2005 $45,423 2006 46,019 2007 46,552 2008 ' 47,128 2009 47,760 Years thereafter 302,402 Total 535,284 Less: Amount representing interest 138,165 Present value of net minimum lease payments $397,119 87
Entergy Corporation Notes to Consolidated Financial Statements NOTE 10. RETIREMENT, OTHER POSTRETIREMENTi-- BENEFITS,,.- AND DEFINED CONTRIBUTION PLANS - LL . CJti&,. f Qwrit dIWUr* 9, _ffl ,i: t3 . J J ,'Aifumr
-4(
Pension Plans Entergy has seven pension plans covering substantially all of its employees: "Entergy Corporation Retirement Plan for Non-Bargaining Employees," "Entergy Corporation Retirement Plan for Bargaining Employees," "Entergy Corpoiation Retirement Plan II for Non-Bargaining Employees," "Entergy Corporation Retirement Plan II for Bargaining Employees," "Entergy Corporation Retirement Plan III," "Entergy Corporation Retirement Plan IV for Non-Bargaining Employees," and "Entergy Corporation Retirement Plan IV for Bargaining Employees." Except for the Entergy Corporation Retirement Plan III, the pension plans ate noncontributory and provide pension benefits that are based on employees' credited service and compensation during the final years before retirement. The Enterg& Corporation Retirement Plan III includes a mandatory employee contribution of 3% of earnings during the first 10 years of plan participation, and allows'voluntary contributions from 1% to 10% of earnings for a limited group of employees. Entergy Corporation- and its subsidiaries fund pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. As of December 31, 2004 and 2003, Entergy recognized an additional rminimium pension liability for the excess of the accumulated benefit, obligation Qyer the fair market value of plan assets. In accordance with SFAS ,87, an offsetting intangible asset, up to the amount,of any unrecognized prior service cost, was also recorded, with.the remaining offset to the liability recorded as ,a.regulatory asset reflective. of the recovery mnechanism.for pension cosits in Entergy's jurisdictions or to other comprehensive income for Entergy's ,npn-regulated business. Entergy's domestic utility companies' and System Energy's pension costs are recovered from customers as a component of cost of service in each of its jurisdictions. Entergy uses a December 3 l me~asurement diate for its pension plans. ;
... ht: :.J; ,,.fJli. at wil t' i r*'i.}ii *.I_'.Xt .3b~tiV fLou ~ To~ ' " r94'jtt '9j1 J. 72[UI QO ~f?32. 1 '
Components of Net Pension Cost s i3;vL jip5,-i Y c.Sii 4frie', - c 't R t x Z.sisS Total 2004, 2003, and 2002 pension costs of Entergy Corporation and its subsidiaries, including amounts c v s unii ,z c cqc ! i-r 'lI-capitalized, included the following components: ** . t _ ....;Jt j92.G ;- vJs<'-J"
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I.v2 it200 ie'jf~eq , 2003i, ,0 2 reLft *............................... t Ai i14>fisisli])t J.... I jisr,
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- i ;er'v'ice cost - benefit's 4e'adrA'ed Dll $76'94" ' 70,337 3 $56,947d 'Ji2D iIt .&1it; dInj the period "1, xh 1LC\ -u Interest cost on projected 148,092 134,403 128,387 benefit obligation ___- LL (5, d ;460)
I(1 t' 'A pected return on assets `584 l c- ,46) (I, 9.
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.............. i 94. t....,*... X ....
b D ......................... Amortization of transition asset (763) (763) (763) Amortization of prior service cost 5,143 5,886 5,993 Recognized net loss 21,687 6,399 5,504 Curtailment loss - 14,864 stat Special termination benefits - 32,006 Net pension costs $97,521 $107,672 $37,866 I)
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~ ri~f::,t.lW,l '9 ~~~~~iA ,ft .Zj 88
Entergy Corporation Notes to Consolidated Financial Statements Pension Obligations, Plan Assets, Funded Status, Amounts Not Yet Recognized and Recognized in the Balance Sheet as of December 31, 2004 and 2003: fis';.X:-j~. c 'JY 01KW f j7.f~if ; t 4'itt w'SO,
*)f rtl7l at's ovS9i ; nt Ssci.-il2ZX{i~t ;q i 'A:.W-i' AlA ij~f~sAn :j21 N '.i WWThsaWl fl~sI if aUr>J11/2i sc'litm
- 3Idr1t!E December 31, t n ill) 5A j '*1'
- 1. -. P 2004 -- 2003Y - .Y;i (In Thousands)
WrIti jj ,L,, I Wl:fC-t lA anfltQ fTtm ~ff~ ~t~~t'lhl~U 1f~i(j2 iJG2f smr Changein Projected Benefit Obligation,(PBO) , mc- ivfttYi14 avtcT:JJDQ Ircninrxccrob Balance atbeginningofyear. , ; ,;. . j y$ 2,349,565 $1,992,207 ,. fflit:3 Servicecost.A, Iflt 9cnThw-. b J i&1f-it \l<iOttsYŽ . 76,946 't
- 70,337 Interest cost . . ruJA;) C ;; n -;(;<c 148,092 ; 134,403 ft c- f Amendments ! 13 W $2 3M79 `107 if 227 Actuarial loss 171,146 205,949 Benefits paid ' (I 1` 2 3 4 )'flh (i ( 9 4 5 1 4fIIj2iflSU; Em ployee ckontibuttions, 1,212 1,5*
Curtailment loss f951 0-Special termination benefits - 32,006 Balance afend of yearti. $2,633,436 $2,349,565 6Jb"fLf i i L At fril Change in Plan Assets Fair value of assets at beginning of year -$1744975 $$1,451,802 Actual return-'on plana'etst' 170,964 . 355,043 Employer contributiohs'f 1S -S&-72,825 ^ic7 1734,645 Employee contributiofi§ - & Jt )l . 2; 1,212 f 1,059 Benefits paid i ..J I Yi!p,). t ?o fIT i fo ao (117,234) (97,574) Fair value of assets afend of year" t oo1 ,)tH"$ 1,872,742 $1,744,975 Funded status .. , .\ - ($760,694) hill ($604,590) Amounts not yefircognized in the balance sheet Unrecognized transition asset (662) (1,426) Unrecognized prior service cost 29,053 30,467 Unrecognized net loss 542,391 410,321 Accrued pension cost recognized in the balance sheet ($189,912) ($165,228) Amounts recognized in the balance sheet Accrued pension cost ($189,912) ($165,228) Additional minimum pension liability (244,280) (180,212) Intangible asset 26,167 30,832 Accumulated other comprehensive income 10,781 15,359 Regulatory asset 207,332 134,021 Net amount recognized ($189,912) ($165,228) 89
Entergy Corporation Notes to Consolidated Financial Statements Other Postretirement Benefits Entergy also currently provides health care and life insurance benefits for retired employees. Substantially all domestic employees may become eligible for these benefits if they reach retirement age while still working for Entergy. Entergy uses a December 31 measurement date for its postretirement benefit plans. Effective January 1, 1993, Entergy adopted SFAS 106, which required a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. At January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $241.4 million for Entergy (other than Entergy Gulf States) and $128 million for Entergy Gulf States. Such obligations are being amortized over a 20-year period that began in 1993. For the most part, the domestic utilities and System Energy recover SFAS 106 costs from customers and are required to fund postretirement benefits collected in rates to an external trust. Components of Net Postretirement Benefit Cost Total 2004, 2003, and 2002 other postretirement benefit costs of Entergy Corporation and its subsidiaries, including amounts capitalized and deferred, included the following components: 2004 2003 2002 (In Thousands) Service cost - benefits earned during the period $30,947 $37,799 $29,199 Interest cost on APBO 53,801 52,746. 44,819 Expected return on assets (18,825) (15,810) (14,066) Amortization of transition obligation 9,429 15,193 17,874. Amortization of prior service cost (5,222) , (925) 992. Recognized net (gain)/loss 15,546 12,369 1,874 Curtailment loss - 57,958 Special termination benefits 5,444 - Net other postretirement benefit cost $85,676 $164,774 $80,692 90
Entergy Corporation Notes to Consolidated Financial Statements Other Postretirement Benefit Obligations. Plan Assets. Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet as of December 31,2004 and 2003: December 31, 2004 2003
,. 1s (In Thousands)
Change in APBO Balance at beginning of year $941,,03 ,$799,506 Service cost 30,947 37,799 Interest cost 53,801 52,746 Actuarial loss 73,890- 115,966 Benefits paid (66,456) (48,379) Plan Amendments (a) (60,231) (84,722) Plan participant contributions 9,312 7,074 Curtailments. 56,369 Special termination benefits - 5,444 Balance at end of year $983,066 $941,803 Change in Plan Assets Fair value of assets at beginning of year $227,446 $182,692 Actual return on plan assets 15,550 "22,794 Employer contributions 63,399 63,265 Plan participant contributions 9,312 7,074 Benefits paid (66,455) (48,379) Fair value of assets at end of year $249,252 ' $227,446 Funded status ($733,814) - ($714,357) Amounts inot yet recognized in the balance sheet i d I Unrecognized transition obligation 5,594 :: ; ,44,815 Unrecognized prior service cost ; (39,560)- (20,746) Unrecognized net loss ... i 391,940 ' 336,005 Accrued other postretirement benefit cost recognized in the balance'sheet ' ($375,840) ' ($354,283) (a) Reflects plan design changes, includinga change in the participation assumption for the majority of non-bargaining employees effective August 1, 2003 and certain bargaining employees and additional non-bargaining employees effective January 1, 2004. 91
Entergy Corporation Notes to Consolidated Financial Statements Pension and Other Postretirement Plans' Assets Entergy's pension and postretirement plans weighted-average asset allocations by asset category at December 31, 2004 and 2003 are as follows: Pension Postrefirement 2004 2003 2004 2003 Domestic Equity Securities 46% 56% 38% 37% International Equity Securities 21% 14% 14% 0% Fixed-Income Securities 31% 28% 47% 60% Other 2% 2% 1% 3% Entergy's trust asset investment strategy is to invest the assets in a manner whereby long-term earnings on the assets (plus cash contributions) provide adequate funding for retiree benefit payments. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense. In the optimization study, Entergy formulates assumptions (or hires a consultant to provide such analysis) about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes. The future market assumptions used in the optimization study are determined by examining historical market characteristics of the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period. The optimization analysis utilized in Entergy's latest study produced the following approved asset class target allocations. Pension Postretirement Domestic Equity Securities 45% 37% International Equity Securities 20% 14% Fixed-Income Securities 31% 49% Other (Cash and GACs) 4% 0% These allocation percentages combined with each asset class' expected investment return produced an aggregate return expectation for the five years following the study of 7.6% for pension assets, 5.4% for taxable postretirement assets, and 7.2% for non-taxable postretirement assets. These returns are not inconsistent with Entergy's disclosed expected pre-tax return on assets of 8.50% over the life of the respective liabilities. Since precise allocation targets are inefficient to manage security investments, the following ranges were established to produce an acceptable economically efficient plan to manage to targets: Pension Postretirement Domestic Equity Securities 45% to 55% 32% to 42% International Equity Securities 15% to 25% 9% to 19% Fixed-Income Securities 25% to 35% 44% to 54% Other 0% to 10% 0% to 5% Accumulated Pension Benefit Oblieation The accumulated benefit obligation for Entergy's pension plans was $2.3 billion and $2.1 billion at December 31, 2004 and 2003, respectively. 92
Entergy Corporation Notes to Consolidated Financial Statements Estimated Future Benefit Payments Based upon the assumptions used to measure the company's pension and postretirement benefit obligation at December 31, 2004, and including pension and postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid over the next ten years will be as follows: Estimated Future Benefits Payments Pension Postretirement (In Thousands) Year(s) '-'i 2005 $115,203 $60,932 2006 $116,894 $59,761 2007 $119,092 $62,392 2008 $122,728 $64,381 2009 $127,877 $66,444 2010 -2014 $780,295 $360,191 Contributions Entergy expects to contribute $185.9 million (excluding about $1.2 million in employee contributions) to its pension plans and $63.3 million to other postretirement plans in 2005. Additional Information The change in the minimum pension liability included in other comprehensive income and regulatory assets was as follows for 2004 and 2003: 2004 2003 (In Thousands) Increase/(decrease) in the minimum pension liability included in: Other comprehensive income ($4,578) ($1,639) Regulatory assets $73,311 ($23,768) Actuarial Assumptions The assumed health care cost trend rate used in measuring the APBO of Entergy was 10% for 2005, graduallydecreasing each successive year until it reaches 4.5% in 2011 and beyond. The assumed health care cost trend rate used in measuring the Net Other Postretirement Benefit Cost of Entergy was 10% for 2004, gradually decreasing each successive year until it reaches 4.5% in 2010 and beyond. A one percentage point change in the assumed health care cost tread rate for 2004 would have the following effects: 1 Percentage Point Increase 1 Percentage Point Decrease Impact on the Impact on the sum of service sum of service Impact on the costs and Impact on the costs and 2004 APBO interest cost APBO interest cost Increase (Decrease) (In Thousands) Entergy Corporation $99,271 $11,587 ($89,801) ($10,061) 93
Entergy Corporation Notes to Consolidated Financial Statements The significant actuarial assumptions used in determining the pension PBO and the SFAS 106 APBO for 2004, 2003, and 2002 were as follows:
- 2004 2003 2002 Weighted-average discount rate:
Pension - . . 6,00% 6.25% 6.75% Other postretirement ;6.00% 6.71% 6.75% Weighted-average rate of increase in future compensation levels 3.25% 3.25% 3.25% Expected long-term rate of return on plan assets:- Taxable assets, 5.50% 5.50% _5.50% Non-taxable assets -8.50% 8.75% 8.75% The significant actuarial assumptions used in determining the net periodic, pension and other postretirement benefit costs for 2004, 2003, and 2002 were as follows: 2004 2003 2002 Weighted-average discount rate, Pension 6.25% 6.75% 7.50% Other postretirement 6.71% 6.75% 7.50% Weighted-average rate of increase i; in future compensation levels 3.25% i - 3.25% 4.60% Expected long-term rate of return on plan assets: Taxable assets 5.50% 5.50% 5.50% Non-taxable' assets 8.75% 8.75% 9.00% Entergys. remaining pension transition assets are being amortized over the greater of the remaining service period of active participants ot 15 years ending in 2005, and its SFAS 106 transition obligations are being amortized over 20 years ending in 2012. Voluntary Severance Program As part of an initiative to achieve productivity improvements with a goal of reducing costs, primarily in the Non-Utility Nuclear and U.S. Utility businesses,;in the second half of 2003 Entergy offered a voluntary severance prdgram- to; employees in various departments. - Approximately 1,100 employees, including 650 employees in nuclear operations from the Non-Utility Nuclear and U.S.' Utility businesses, accepted the offers. As a result of this program, in the fourth quarter 2003 Entergy recorded additional pension and postretirement costs (including amounts capitalized) of $110.3 million for special tepiination benefits and plan curtailment charges. These amounts are included in the net pension cost and net postretirement benefit cost for the year ended December 31, 2003.; Medicare Prescription Dru2. Improvement and Modernization Act of 2003 In December 2003, the President signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 into law. The Act introduces a prescription drug benefit cost under Medicare (Part D), starting in 2006, as well as federal subsidy to employers who provide a retiree prescription drug benefit that is at least actuarially equivalent to Medicare Part D. At December 2003, specific authoritative guidance on the accounting for the federal subsidy was pending. As allowed by Financial Accounting Standards Board Staff Position No. FAS 106-1, Entergy elected to record an 94,
Entergy Corporation Notes to Consolidated Financial Statements estimate of the effects of the Act in accounting for its postretirement benefit plans at December 31, 2003, under SFAS 106 and in providing disclosures required by SFAS No. 132 (revised 2003), Employers' Disclosures about Pensions and Other Postretirement Benefits. At December 31, 2003, based on actuarial analysis of prescription drug benefits, estimated future Medicare subsidies were expected to reduce the December 31, 2003 Accumulated Postretirement Benefit Obligation by $56 million. For the year ended December 31, 2003, the impact of the Act on net postretirement benefit cost was immaterial, as it reflected only one month's impact of the Act. In 2004, Entergy continued to record an estimate of the effects the Act in accounting for its postretirement benefit plans. In mid-2004, the Financial Accounting Standards Board issued Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which was effective for Entergy's June 30, 2004 interim reporting. In August 2004, the Centers for Medicare and Medicaid Services issued proposed regulations to implement the new Medicare law. A ruling from the Centers for Medicare and Medicaid Services was issued in late January 2005 with final guidance expected later this year. The actuarially estimated effect of future Medicare subsidies reduced the December 31, 2003 and 2004 Accumulated Postretirement Benefit Obligation by $128 million and $161 million, respectively, and reduced the 2004 other postretirement benefit cost by $23.3 million. Defined Contribution Plans Entergy sponsors the Savings Plan of Entergy Corporation and Subsidiaries (System Savings Plan). The System Savings Plan is a defined contribution plan covering eligible employees of Entergy and its subsidiaries. Through January 31, 2004, the System Savings Plan provided that the employing Entergy subsidiary:
- make matching contributions to the System Savings Plan in an amount equal to 75% of the participants' basic contributions, up to 6% of their eligible earnings, in shares of Entergy Corporation common stock if the employees direct their company-matching contribution to the purchase of Entergy Corporation's common stock; or
- make matching contributions in the amount of 50% of the participants' basic contributions, up to 6% of their eligible earnings, if the employees direct their company-matching contribution to other investment funds.
Effective February 1, 2004, the employing Entergy subsidiary began making matching contributions for non-bargaining employees to the System Savings Plan in an amount equal to 70% of the participants' basic contributions, up to 6% of their eligible earnings. The 70% match is allocated to investments as' directed by the employee. Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries II (established in 2001), the Savings Plan of Entergy Corporation and Subsidiaries III (established in 2002), and the Savings Plan of Entergy Corporation and Subsidiaries V (established in 2002). The plans are defined contribution plans that cover eligible employees, as defined by each plan, of Entergy and its subsidiaries. The employing Entergy subsidiary makes matching contributions equal to 50% of the participants' participating contributions for each of these plans. Effective September 30, 2004, employees participating in the Savings Plan of Entergy Corporation and Subsidiaries III (Savings Plan III) were transferred into the System Savings Plan and Savings Plan III was terminated. Entergy's subsidiaries' contributions to defined contribution plans collectively were $32.9 million in 2004,
$31.5 million in 2003, and $29.6 million in 2002. The majority of the contributions were to the System Savings Plan.
95
Entergy Corporation Notes to ConsolidatedFinancial Statements NOTE 11.V BUSINESS SEGMENT INFOR1VLATION Entergy's reportable segments as of December 31, 2004 are U.S. Utility, Non-Utility Nuclear, and Energy Commodity Services. U.S. Utility generates; transmits, distributes, and sells electric power in portions of Arkansas, Louisiana, Mississippi, and Texas, and provides natural gas utility service in portions of Louisiana. Non-Utility Nuclear owns and operates five nuclear power plants and is primarily focused on selling electric power produced by those plants to wholesale customers. Energy Commodity Services includes Entergy-Koch, LP and Entergy's non-nuclear wholesale assets business. Entergy-Koch engaged in two major businesses: energy commodity marketing and trading through Entergy-Koch Trading, and gas transportation and storage through Gulf South Pipeline. Entergy-Koch sold both of these businesses in the fourth quarter of 2004, and Entergy-Koch is no longer an operating entity. The non-nuclear wholesale assets business sells to wholesale customers the electric power produced by power plants that it owns while it focuses on improving performance and exploring sales or restructuring opportunities for its power plants. Such opportunities are evaluated consistent with Entergy's market-based point-of-view. Results from Entergy-Koch are reported as equity in earnings of unconsolidated equity affiliates in the financial statements. Entergy's operating segments areo strategic business units managed separately due to their different operating and regulatory environments. Entergy's chief operating decision maker is its Office of the Chief Executive, which consists of its highest-ranking. officers.
"All Other" includes the parent company, Entergy Corporation, other business activity, including the Competitive Retail Services business, which has higher revenues in 2004 as its number of customers has increased, and earnings on the proceeds of sales of previously-owned businesses.
Entergy's segment financial information is as follows: i Energy k Non-Utility Commodity 2004 U. S. Utility Nuclear* Services
- All Other* Eliminations Consolidated (In Thousands)
Operating revenues $8,142,808 $1,341,852 $216,450 $486,804 ($64,190) $10,123,724 Deprec:, amort. & decom. '$915,667 $106,408 $16,311 $6,736 $- $1,045,122 Interest income $40,831 $63,569 $17,875 $42,729 ($55,195) $109,809 Equity in loss of unconsolidated equity affiliates $- $- ($78,727) $- $- - ($78,727) Interest charges $383,032 $53,657 $15,560. $81,916 ($55,142) $479,023 Income taxes (credits) $406,864 $142,620 ($155,840) ($27,736) j $- $365,908 Net income $666,691 $245,029 $3,778 $17,606 ($55) $933,049 Total assets $22,937,237 $4,531,604 $2,223,961 $199,233 ($1,581,258) $28,310,777 Investment in affiliates -at equity $207 $- $512,571 $- ($280,999) $231,779 Cash paid for long-lived asset additions $1,152,167 $242,822 $2,022 $13,604 ($5) $1,410,610 96
Entergy Corporation Notes to Consolidated Financial Statements Energy Non-Utility Commodity 2003 U. S. Utility Nuclear* Services
- AU Other* Eliminations Consolidated (In Thousands)
Operating revenues $7,584,857 $1,274,983 $184,888 $188,228 ($38,036) $9,194,920 Deprec., amort. & decomm. $890,092 $87,825 $13,681 $5,005 $996,603 Interest income $43,035 $36,874 $18,128 $27,575 ($38,226) $87,386 Equity in earnings (loss) of unconsolidated equity affiliates ($3) $271,650 $- $271,647 Interest charges $419,1i1 $34,460 $15,193 $75,787 ($38,225) $506,326 Income taxes (credits) $341,044 $88,619 $105,903 ($45,492) $490,074 Cumulative effect of accounting change ($21,333) $154,512 ; $3,895 $- ,. $- $137,074 Net income (loss) $492,574 $300,799 $180,454 ($23,360) $ $950,467 Total assets $22,402,314 $4,171,777 $2,076,921 . $1,495,903 ($1,619,527) $28,527,388 Investment in affiliates - at equity $211 $1,081,462 $- ($28,345). $1,053,328 Cash paid for long-lived asset additions $1,233,208 $281,377 $44,284 $10,074 $- $1,568,943 Energy Non-Utility Commodity
' 2002 U. S. Utility Nuclear* Services
- All Other* Eliminations Consolidated (In Thousands)
Operating revenues $6,773,509 $1,200,238 $294,670 $40,729 ($4,1 11) $8,305,035 Deprec., amort. & decomm. $800,257 $88,733 $21,465 $5,143 $915,598 Interest income $23,231 $71,262 $26,140 $35,433 ($37,7 41) $118,325 Equity in earnings (loss) of unconsolidated equity affiliates ($2) $- $183,880 $- $183,878 Interest charges $465,703 $47,291 $61,632 $35,579 ($37,7 41) $572,464 Income taxes (credits) $313,752 $132,726 ($141,288) ($11,252) $- $293,938 Net income (loss) $606,963 $200,505 ($145,830) ($38,566) $- $623,072 Total assets $21,630,523 $4,482,308 $2,167,472 $1,327,354 ($2,103,2 91) $27,504,366 Investment in affiliates - at equity $214 $- $823,995 $- $- $824,209 Cash paid for long-lived asset additions $1,131,734 $169,756 $210,297 $18,514 $- $1,530,301 Businesses marked with
- are referred to as the "competitive businesses,!' with the exception of the parent company, Entergy Corporation, which is included in "All Other." Eliminations are primarily intersegment activity.
Substantially all of Entergy's recorded asset for goodwill is in its U.S. Utility segment. In the fourth quarter 2004, Entergy recorded a charge of approximately $55 million ($36 million net-of-tax) as a result of an impairment of the value of the Warren Power plant. Entergy concluded that the value of the plant, which is owned in the non-nuclear wholesale assets business, was impaired. Entergy reached this conclusion based on valuation studies prepared in connection with the sale of preferred stock in a subsidiary in the non-nuclear wholesale assets business. Energy Commodity Services' net loss for the year ended December 31, 2002 includes net charges of $428.5 million to operating expenses ($238.3 million net-of-tax). These charges reflect the effect of Entergy's decision to discontinue additional greenfield power plant development and the asset impairments resulting from the 97
Entergy Corporation Notes to Consolidated Financial Statements deteriorating economics of wholesale power markets in the United States and the United Kingdom. The net charges consist of the following:
- The power development business obtained contracts in October 1999 to acquire 36 turbines from General Electric. Entergy's rights and obligations under the contracts for 22 of the turbines were sold to an independent special-purpose entity in May 2001. $178.0 million of the charges, including an offsetting benefit of $28.5 million ($18.5 million net-of-tax) related to the sale of four turbines to a third party, is a provision for the net costs resulting from cancellation or sale of the turbines subject to purchase commitments with the special-purpose'-erntity. t
* $204.4 million 'of the charges resulf fromrthe write-offtof 1nter5y Pher Development Corpora'ion"s equity investment in the Damhead Creek project and the impairment of the values of the Warred Power power plant, the Crete project, and the RS"Cogen projectf This portiotf o the charges reflects' Sntergy's 'estimate' of the effects of reduced 4sark spre'ads in the United States and thie United Kingdom. These estimate's are based on various sourcik 6f inforrmibion, including distcounted cash'flow projections and current Mharket prices. ? Cxj ... , 6
* $39.1 million of the charges relate to the restructuring of the notnfuclear wholesale assets business, l including impairments tof ad&ninistrai'vVfix'ed ass t,'sestimated sublease losses, and employee-i6Iated costs
for approximately 135 affddted employees. These restrudturing costs, which are included in the "Provision for turbine commitments, asset impairments, and restructuring charges" in the accompanying consolidated, statement of income, were comprised of the following: ,, . Paid in
- Cash Remaining a through Accrual as ti;,.-.:.Sft '"tU. .- Restructuring December Non-Cash of December Costs 2004 Portion 31, 2004 (In Millions)
Fixed asset impairments $22.5 $- $22.5 $-
'Sublease' losses 't5 5.1 Severance and related costs 59- 5.. ., 5.1 Total i ' 3' ' $1 i $22.5 $5.1. ,,A a
&,4iil MI 4 J'-
'A i 1H.
* $32.7 million of the charges result from the write-off of capitalized project devf6pfmient'costs for projects that will not he completed. -f fA'. .
- The net charges include a'gain of $25.7 million ($15.9 -millionn&t-6f-iax) on the sale of projects utnideŽr' development in Spain in August 2002 and the after-tax gain of $3'1.4 million realized on the sale of'
- .:: t< &c~y..;.:Z -
Damhead Creek in December 2002.
, <. ... . ; .; . , .. m I- ;I
. A , i'"
Geographic Areas
!. fj< \ *,i}, t0t* ta C
- f. G: !~~-~Udjii Ir i; For the years ended December 31, 2004 and 2003, Entergy derived less than 1% of its revenue from outside the of the United States. For the year ended December 31, 2002 Entergy derived 3% of its revenue from outside of i',' rrr Poht43ni ' :, ssi 10 1 VasI'). .E United States, .1 .. CttiIti Ip
.. e - tI iit- Il .0) 2 1 .I1. t fontrat 2 ) fl < f J N W IL; iit f+J As of December 31, 2004 and 2003 Entergy had almost no long-lived assets located outside of the United
.uY. it ifiU-,I 1.10 11',,J V j. 'it . (I States. ; - \XzIsfl ii) a o'U';1 f00f AI t is ij1U&V (Un h'; .lrI qld a!.twV-' i'.sA £7f, 52U 'P. .2 . .1!4!. ti4'iif(slip di'- 10i Wtfllk. LFd 4_
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Entergy Corporation Entergy Corporation Notes to Consolidated Financial Statements NOTE 12. EQUITY METHOD INVESTMENTS r !. As of Decemnber 31, 2004, Entergy owns investments in the following companies that it accounts for under the equity method~ facco nting: , li fit . t;2 i ." :. _'-!
- if H1im'P9 I r i , F1 0. % ! ; m u 2 1 :}'
f';/; i Company .,., Ownership . ,,,
,, ,Description
- fii. ipric 1/2 mkjv..f ' i^ 'j,, .otsrj 0.d to Ri; 3 bi Enqtergy-Koch,LP r ii
,: j 50>. %partnership Engagd iin two major businesses: energy commodity
; )
Jinterest,,, , .marke~ting aind trading through Entergy-Koch Trading, and gas transportation and storage through Gulf South Pipeline. Entergy-Koch sold both of these businesses in the fourth
.. t Ji ,, ] 1 * . .~ni<,>i 3 :itjoi.. fP ;quarter of ?2994, and Entergy-Koch is no longer an
;i .r' GI 2 !Mi ,andI_'2JdC)(sifli- b K0;cit.1i'.v . ' '
RS Cogen LLC , - ,50% ,~ecnbjer *,, 1Co-generation project'that produces power and steam on an i 'Jii ' . interest industrial and merchant basis in the Lake Charles, Louisiana area,. ,t ,Ji_* ,).flQ rr f- ~li9i ,,o las 'j /'!Ite Top Deer, ,0 ,,,5O% memb~erL Wind-powered electric generation joint venture.
- .':'... H .jt 2-141)?,-, -,,"interest , ,, :> . - r .- [ .
Following is a reconciliation of Entergy's investments in equity affiliates: 2004 2003 2002 Ut;70 i pi (In Thousands) . Beginning of year $1,053,328 $824,209 $766,103 Additional investments 157,020 4,668 36,3712 Income (loss) from the investments (78,727) 271,647 183,878 Other income 6,232 45,583 21,462 Distributions received (888,260) (105,142)
. (73,902)
;Dispositionsand other adJustrneints ' '(iX4 ) K'T2,363 109,704)
- " ei.ItUW'L $231,'79' $fO03,328 ' "'
C , f ifH . i -(),I-
* . .l- It,2i ;S<'a a't; . -;A.iu.i : fIc. 9 V: fJJIj(.>7. ')jJ . .
,The following is aesu$m ary of combined financial inform4
'..-It~iJ J.' t.I ,H JO > a. ,Ifti(l( z;S ')J( .,- 29>ei 9l ion.reported 9 by Entergy's equity method investees: :.lt. fai$1 '-r; t() £ ;i3S 1f' .b'& & ri:.4d.w
.l Ii rn, 4ifit ntQ :ij V(j I tn I.:; 61r 81 w iff ' iillq b '" ~ orjl t ' !>, . - r OJrjq
*.l.' "',clW1' 1 4I -'h __.j7f._-,200____3 _ 2002io ;
(In Thousands) Operatingreventues ass $540,386 $,576,04 $551 Operating income ($111,535) $207,301 Balance Shaement Items $159 3,42>,>i^ ^ 8 Net income $739,858 (1) $172,595 $68,095 Balance Sheet Items Current assets $540,386 $2,576,630 .. ,;^~ T ... $;: ~... Noncurrent assets $418,038 $1,675,334 Current liabilitie5s), ( v l4;J5r,'. $180 $$1,757, 663ui 0 09 r Noncurrent liabilities ; $463,899 _
- [63 i t, i 5 .
1:66,540., (1) Includes gains recorded by Entergy-Koch on the sales of its energy trading and pipeline businesses.
.J V bS-: ,ii 8f1A J .-. 2 ..-
99
Entergy Corporation Notes to Consolidated Financial Statements Related-party transactions and guarantees !ITi'f, i21 a v >.i 'ii ' t, i X f,:.i . *@'.dy' During 2004, 2003, and 2002, Enteri y procured various~ sNvices from Entergy-Koch consisting primarily of pipeline transportation services for natural gas and risk management services for electricity and natural gas: The total cost of such services in 2004, 2003, and 2002 was approximately $9.5 million, $15.9 million, and $11.2 million, respectively. Ii id03,Energy Louisiana and Entergy fewM!leaiis entered purchase pow'er agreements with RS Cogen, and purchased a total of $26.0 million of capacity and energy from RS Cogen in 2003. In 2004, Entbfgy Louisiana and Entegy' N6W-Orleans purchased a total' of'$43:6 'million of capacity and enerig' 'from R'S' Cogen. Entergy s operatih ftraiisactio'is'twith its othff'ififity meth6d'fin-vestees were not material in 2004, 2003, or 20 2 iffl 1' tf'T elrli::'toAu, Prft o.,.l~r 'Eil.l;-,ly,-,o -v-
-Inthe purchase agr'1eft-&iis fo6r its efnrgy t rading' and the pipeline business sales, Entergy-Koch has agreed to indemnify the respective purchasers for 'cdertain potential losses relating to any breaches of the sellers' representations, warranties, and obligations under each of the purchase agreements. Entergy Corporation has guaranteed up to 50% 'of Efitegy-koch's 'indeinnification obligatio'n-ito the' purchasers. Entergy does e'xpect anYithiterial claihmd'un.dtrthese ii-Ai fiuionioblliati6fis, but to fh e extent that any are asserted and paid, the gain that Entergy expects to record in 2006 may be reduced.
During the fourth 4d~aff&'of 2004,'an' Eft'6?gys'ubidiaq ptr6iidks'd from a commercial bank holder $16.:3 million of RS Cogen subordinated indebtedness, due October 2017, bearing interest at LIBOR plus 4.50%. The debt was purchased at a discount of approximately $2.4 million that will be amortized over the remaining life of the debt. 'it, i 'tui(, 1 c3J'Xi.l-3lDVW P1flJ' _' ) f i~~ 7 2' L.', i NOTE 13. ACQUISITIONS AND DtSPOSITIONS
't.1I^(.fO ~ ~ ~ ,;.<:gzXfj¢dtl i '}a'xisy~
Asset AcqFuisitions .' .. .. J. Vermont Yankee In Jul'i2002, Entergy's Non-Uiiity Nuclear busifiess purchased the 510 TW Ver'Mont'Waiike nuclear power plant 1ocated in Vernon, Vermont, from Vermo'nt Xankee Nucleair F'owier C-oroio~n or $180 million. Entergy received teplant, nuclear fuel, inventories, and related real estate. The liability to' de&o6tihiission the plant, as well as related decommissioning trust funds of approximately $310 million, was also transferred to Entergy. Thie'acqui'sition included a-10-yeSf powe' purchae' agr&effieint (PPA) under 'which the f6ronier owners will buy the power produced by the plant, which is through the expiration of the current operating license for the plant. The PPA includes an adjustment clause which provides that the prices specified in the PPA will be adjusted downward annually, beginning in Dec'iiiber 2005, if power M'arket prices drop below the PPA prices.
! .`1)fi ,e rJits J 1. i I The acquisition was accounted for using the purchase method. The results of operations of Vermont Yankee subsequent to the purchase date have been included in Entergy's consolidated irsu'uof o per'aitions. The purchase price has been allocated to the hasets acquired and liabilities assumed based on their estimated fair values on the purchase 'dat"'> IJ>. ' . c.t 1-) ' .
Asset Dispositions Entergy-Koch Businesses ! ,Z 2'i J. tLs.) In the fourth quarter of 2M04, Entergy-Koch sold its energy trading and pipelin-ei bu-ses's`ssto third parties. The sales came after a review of st rfgic alternativie' for' enhancing the value of' ntergy'Ko'ch, LP. Entergy received $862 million of cash distributions in 2004 from Entergy-Koch after the business sales, and Entergy ultimately e ts' ciotalneash diibutin exceeing$1"billion, 'comprised ofthe after-tax 'ash from the distributions of the sales proceeds and the eventual liquidation of Entergy-Koch. Entergy currently expects the 100
Entergy Corporation Notes to Consolidated Financial Statements net cash distributions that it will receive will exceed its equity investment in Entergy-Koch, and expects to record a $60 million net-of-tax gain when it receives the remaining cash distributions, which it expects will occur in 2006. Other ,,;uc'sat- '0.iC'.tti In January 2004, Entergy sold its 50% interest in the Crete project, which is a 320MW power plant located in Illinois, and realized an insignificant gain on the sale. ifl jvit ut< <>ol3 lnsnEn'rrr f lu "Nr &sb<<'fl urIGt f~tL8 U
-- ,, In August 2002, Entergy s~old,,its interest in projects under developmept in Spain for a realized gain on the salqe of, $25.7 mrillion. In, December 2002, Entergy sold its 800 MW. Damhead Creek power plant in the UK resulting in an increase in, net income, of $31.4 million. The Damihead Creek buyer assumed all market and regulatory risks associated with the facility._ ,,15> , u +/-. Yi.:5W0- '..-'O'! A I; knii 10 M3/4L:9 UT'i' a)t Wai ':_' -. mtjitllsi:i ~asl-xlV1 tQull ,;fv'itJ.t-. -';.J :)fJ.ITt (MA!tbi nm.I <t0 .t 2.Z:%fm... { jl'Wj 43I. iOtIsfliXf
. <: .Sh'f Jl ytZ;8j8l,+i:~
5 tatJit~
.J S 1V, i; iVs xm:iit,Ž li- A *\:fjS '1f1 sl F I.54119i 'i iIX~iTwIh 7 !U4U'll.)1S--jb hti iV;i NOTE 14. , RISK MANAGEMENT AND FAIR VALUES is '1I . 1!;ui Vbvi;ji' i'1/2. C 4'),
Market and Commodity Risks In the normal course of business, Entergy is exposed to a number of market and commodity risks. Market risk is the potential loss that Entergy may incur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Entergy is subject to a number of commodity and market risks, including: { -
- . ^^ \<;:...&il.a vtU 0 J -'EIIt ia.wtt' .;rT t :-'ir' ti oaq~'iT'hJ i-ro0/:f j 'i . L~v \ 1 f;-l4 t1 . ; $1,itt'fi-- (d 0;is )~l1cv
-v tits'. 4 :m. - R 4j oi'Type of Risk
>f0 ff Primary Affected Segments 'Vi".bI '-I' i; .'.:& Power price risk iiC)
J - . _..... tis' ZAIt iu All reportable segments -, -'.'o ichuut Fuel price risk 1.. u... ! ' j -z' a All reportable segments .:-I - Foreign currency exchange rate risk All reportable segments Equity price and interest rate risk - investments _. U.S. Utility, Non-Utility Nuclear
..it iJi:i' J i ) f.. tV.1 'Ai P10) 'iR jay fi brl-I jJ . . 'j .S f ji '- "- . 550i4..'20ti s '2P(1uS Lh(14;j{
-. Entergy manages these risks through both contractual arrangements and derivatives. Contractual risk management tools include long-term power and fuel purchase agreements, capacity contracts, and tolling agreements. Entergy also uses a variety of commodity and financial derivatives, including natural gas and electricity futures, forwards, swaps, and options; foreign currency forwards; and interest rate swaps as a part of its overall risk management strategy. Except for the energy trading activities conducted through December 2004 by Entergy-Koch, Entergy enters into derivatives only to manage natural risks inherent in its physical or financial assets or liabilities.
Entergy's exposure to market risk is determined by a number of factors, including the size, term, composition, and diversification of positions held, as well as market volatility and liquidity. For instruments such as options, the time period during which the option may be exercised and the relationship between the current market price of the underlying instrument and the option's contractual strike or exercise price also affects the level of market risk. A significant factor influencing the overall level of market risk to which Entergy is exposed is its use of hedging techniques to mitigate such risk. Entergy manages market risk by actively monitoring compliance with stated risk management policies as well as monitoring the effectiveness of its hedging policies and strategies. Entergy's risk management policies limit the amount of total net exposure and rolling net exposure during the stated
'101
Entergy Corporation Notes to Consolidated Financial Statements periods. These policies, including related risk limits, are regularly assessed to ensure their appropriateness given Entergy's objectives. Hedging Derivatives Entergy classifies substantially all of the following types of derivative instruments held by its consolidated businesses as cash flow hedges:
'Instrument Business Segment Natural gas and electricity futures and forwards Non-Utility Nuclear, Energy Commodity Services, Competitive Retail Services Foreign currency forwards U.S. Utility, Non-Utility Nuclear Cash flow hedges with net unrealized losses of approximately $99 million at December 31, 2004 are scheduled to mature during 2005. Net losses totaling approximately $13 million were realized during 2004 on the maturity of cash flow hedges. Unrealized gains or losses result from hedging power output at the Non-Utility Nuclear power stations and foreign currency hedges related to Euro-denominated nuclear fuel acquisitions. The related gains or losses from hedging power are included in revenues when realized. The realized gains or losses from foreign currency transactions are included in the cost of capitalized fuel. The maximum length of time over which Entergy is currently hedging the variability in future cash flows for forecasted transactions at December 31, 2004 is approximately four years. The ineffective portion of the change in the value of Entergy's cash flow hedges during 2004 was insignificant.
Fair Values Financial Instruments The estimated fair value of Entergy's financial instruments is determined using bid prices reported by dealer markets and by nationally recognized investment banking firms. The estimated fair value of derivative financial instruments is based on market quotes. Considerable judgment is required in developing some of the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. In addition, gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not necessarily accrue to the benefit or detriment of stockholders. Entergy considers the carrying amounts of most of its financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. Additional information regarding financial instruments and their fair values is included in Notes 5 and 6 to the consolidated financial statements. 102
Entergy Corporation Notes to Consolidated Financial Statements
'DECOMMISSIONING TRUST FUNDS I NOTE 15.
Entergy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held at December 31, 2004 and 2003 are summarized as follows: Total Total
' Fair Unrealized Unrealized 2004 i Value Gains- Losses i (In Millions)
Equity $995 $166 $17 Debt Securities 1,457
- 33 6 Total $2,452 $199 $23 2003:
Equity $896 l $81 $11 Debt Securities 1,383 27 3 Total $2,279 , $108 $14 The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows at December 31, 2004: - 'l Equity Securities Debt Securities Gross Gross Fair , Unrealized Fair Unrealized Value Losses Value Losses (In Millions) Less than 12 months $29 $2 $334 $5 More than 12 months 115 15 37 I Total $144 $17 $371- $6 Entergy evaluates these unrealized gains and losses at the end of each'period to determine whether an other than temporary impairment has 'occurred. This' analysis considers the length of time that a security has been in a loss position, the current performance pf that security, and whether decommissioning costs are recovered in rates. Due to the regulatory treatment of decommissioning collections and trust fund earnings, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy record regulatory assets or liabilities for unrealized gains and losses on trust investments. For the unregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains or losses in other deferred credits. No significant impairments were recorded in 2004 and 2003 as a result of these evaluations. I A 103
Entergy Corporation Notes to Consolidated Financial Statements The fair value of debt securities, summarized by contractual maturities, at December 31, 2004 is as follows: Fair-Value-(In Millions) less than I year $134 I year- 5 years 592 5 years - 10 years 425 10 years - 15 years 158 15 years - 20 years 60 20 years+ 88 Total $1,457 During the year ended December 31, 2004, the proceeds from the dispositions of securities amounted to $37 million with gross gains of $0.7 million and gross losses of $0.7 million, which were reclassified out of other comprehensive income into earnings during the period. NOTE 16. QUARTERLY FINANCIAL DATA (UNAUDITED) Operating results for the four quarters of 2004 and 2003 were: Operating Operating Net Revenues Income Income (Loss) (In Thousands) 2004:
- First Quarter $2,251,549 $378,834 $213,016
- Second Quarter $2,485,097 $494,312 $271,011 Third Quarter $2,963,581 $571,472 $288,047 Fourth Quarter $2,423,497 $208,946 $160,975 2003:
First Quarter $2,037,723 $363,403 $400,923(a) SecondQuarter $2,353,909 $461,576 $211,517 Third Quarter $2,700,125 $619,005 $371,650 -; Fourth Quarter $2,103,163 $40,571 ($33,623) (a) Net income before the cumulative effect of accounting changes for the first quarter 2003 was
$258,001.
Earnings Per Average Common Share 2004 2003 Basic Diluted Basic Diluted First Quarter $0.90 $0.88 $1.77(b) $1.73(b) Second Quarter $1.16 $1.14 $0.91 $0.89 Third Quarter $1.24 $1.22 $1.60 $1.57 Fourth Quarter $0.71 $0.69 ($0.19) ($0.18) (b) Basic and diluted earnings per average common share before the cumulative effect of accounting changes for the first quarter of 2003 were $1.13 and $1.10, respectively. 104
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy ENTERGY'S BUSINESS (continued) U.S. Utility The U.S. Utility is Entergy's largest business segment, with five wholly-owned domestic retail electric utility subsidiaries: Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. These companies generate, transmit, distribute and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Gulf States and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Also included in the U.S. Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf 1. System Energy sells its power and capacity from Grand Gulf 1 at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. These utility subsidiaries are each regulated by state utility commissions, and in the case of Entergy New Orleans, the City Council. System Energy is regulated by FERC as all of its transactions are at the wholesale level. The U.S. Utility continues to operate as a monopoly as efforts toward deregulation have been delayed, abandoned, or not initiated in its service territories. The overall generation portfolio of the U.S. Utility, which relies heavily on natural gas and nuclear generation, is consistent with Entergy's strong support for the environment. The U.S. Utility is focused on providing highly reliable and cost effective electricity and gas service while working in an environment that provides the highest level of safety for its employees. Since 1998, the U.S. Utility has significantly improved key customer service, reliability, and safety metrics and continues to actively pursue additional improvements. Customers As of December 31, 2004, Entergy's domestic utility companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows: Electric Customers Gas Customers Area Served (In Thousands) (%) (In Thousands) %)M Entergy Arkansas Portions of Arkansas 667 25% Entergy Gulf States Portions of Texas and Louisiana 724 27% 91 39% Entergy Louisiana Portions of Louisiana 662 25% Entergy Mississippi Portions of Mississippi 420 16% Entergy New Orleans City of New Orleans* 189 7% 145 61% Total customers 2,662 100% 236 100%
- Excludes the Algiers area of the city, where Entergy Louisiana provides electric service.
Electric Energy Sales The electric energy sales of Entergy's domestic utility companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On July 15, Entergy reached a 2004 peak demand of 21,174 MW, compared to the 2003 peak of 20,162 MW recorded on August 19 of that year. Selected electric energy sales data is shown in the table below: 105
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Selected 2004 Electric Energy Sales Data. ; Entergy Entergy Entergy Entergy Entergy System Entergy Arkansas Gulf States Louisiana Mississippi New Orleans Energy (a) I ; I (In GWh) I.. I . . .I . 1 I -- Sales to retailI'e customers 19,735 - 35,275 28,183 -12,978 6,055 - 102,226 Sales foi resa lle: II e .. Affiliates 7,43 t 1,528 1,129 305 1,514 9,212 Others 4,911 3,172 122 393 25 - 8,623 Total 32,083 39,975 29,434 13,676 7,594 9,212 110,849 Average use per residential custo mer (kWh)- 12,485; 15,620 15,359 i4,475 12,618 14,384 (a) Includes the effect of intercompany eliminations. The following table illustrates the domestic utility companies' 2004 combined electric sales voiume as a percentage of total electric sales volume, and 2004 combined electrki revenues as a percentage of total 2004 eiectric revenue, each by customer class. Customer Class % of Sales Volume % of Revenue Residential ' 35.2 Commercial 23.9 25.3 Industrial (a) 36.3 28.6
- Wholesale - 7.8 8.3 Governmental: 2.3 '. 2.6 (a) Major industrial customers are in the chemical, petroleum refining, and paper industries.
See "Selected Financial Data" for each of the domestic utility companies for the detail of their sales by customer class for 2002, 2003, and 2004. Selected 2004 Natural Gas Sales Data - q r Efntergy New Orleans and ,Entergy Gulf States provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Gulf States sold 14,803,852 and 6,868,935 Mcf, respectively, of natural gas to retail customers in 2004. In 2004, 98% of Entergy Gulf States' operating revenue was derived from the electric utility business, and only 2% from the natural gas distribution business. For Entergy New Orleans, 80% of operating revenue was derived from the electric utility business and 20% from the natural gas distribution business in 2004. Following is data concerning Entergy New Orleans' 2004 retail operating revenue sources.
- . .. . i .,, i:
- Electric Operating j
Natural Gas Ente New Orleans -- Revenue -Revenue i. Residential 40%'i 50% Commercial 37% 22% Industrial 8% 13% Governmental/Municipal 15% 15% 106
Part I Item 1 Entergy Corporation, Domestic utility companies, and System Energy Retail Rate Regulation General (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans) The retail regulatory philosophy has shifted in some jurisdictions from traditional, cost-of-service regulation to include performance-based rate elements. Performance-based rate plans are designed to encourage efficiencies and productivity while permitting utilities and their customers to share in the benefits. Entergy Mississippi, Entergy Louisiana, and Entergy New Orleans have implemented performance-based formula rate plans, but Entergy Louisiana's performance-based formula rate plan expired in 2001. As explained below, performance-based formula rate plans currently are under consideration for Entergy Louisiana and for the Louisiana jurisdiction of Entergy Gulf States. Following is a summary of the status of retail open access in the domestic utility companies' retail service territories.
% of Entergy's 2004 Revenues Derived from Retail Electric Utility Operations Jurisdiction . .
Status of Retail Open Access in the Jurisdiction Arkansas Retail open access was repealed in February 2003. 11.6% Texas In July 2004, the PUCT effectively rejected Entergy Gulf States' proposal to 11.8% implement retail open access in its service territory. In February 2005, bills were submitted in the Texas Legislature that specify that retail open access will not commence in Entergy Gulf States' territory until the PUCT certifies a power region. Louisiana The LPSC has deferred pursuing retail open access, pending developments at 34.1% the federal level and in other states. In response to a study submitted to the LPSC that was funded by a group of large industrial customers, the LPSC recently has solicited comments regarding a limited retail access program. It is uncertain what action, if any, the LPSC might take in response to the infonnation it received. Mississippi The MPSC has recommended not pursuing open access at this time. 10.9% New Orleans The Council has taken no action on Entergy New Orleans' proposal filed in 4.5% 1997. Retail Rate Proceedings Each domestic utility operating subsidiary participates in retail rate proceedings on a consistent basis. The status of material retail rate proceedings is described below and in Note 2 to the domestic utility companies and System Energy financial statements. Authorized Company ROE Pending Proceedings/Events Entergy Arkansas ...... 11. 0 % No base rate cases are pending. Transition cost recovery rider approved to collect $8.5 million effective October 2004 with recovery expected over subsequent 16 months. It is likely that a rate filing will be made in 2005 in connection with the ANO I steam generator and reactor vessel head replacement. 107
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Entergy Gulf States- 10.95% Base rates are currently set at rates approved by the PUCT in June 1999. Texas ......... Entergy Gulf States filed a retail electric rate case with the PUCT in August 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case indicating that Entergy Gulf States is still subject to a rate freeze based on an agreementsapproved by PUCT, order in 2001, stipulating that a rate freeze would., remain in:effect until retail open access commenced in Entergy Gulf States' service territory, unless lifted by the PUCT prior thereto. Entergy Gulf States has appealed this decision and intends to pursue other available remedies, including legislation that would clarify that it is no longer operating under a rate freeze,: In February 2005, bills were filed in the Texas legislature that would clarify that Entergy.Gulf States is no longer operating under a rate freeze and specify. that retail open access will not commence in Entergy Gulf States' territory until the PUCT certifies a power region. Entergy Gulf States- 11.1% In December 2003, the LPSC staff recommended a $30.6 million rate refund Louisiana ....:.. and a prospective rate reduction of approximately $50 million as a result of the ninth post-merger earnings analysis (2002). Hearings concluded in May 2004. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement that would resolve, among other dockets, Entergy Gulf States' ninth post-merger review, and dockets established to consider issues concerning the comnpaniesl power purchases* for the summers of 2001, 2002, 2003, and 2004. The -proposed settlement currently includes an offer to refund $76 million to Entergy Gulf States' Louisiana customers through a credit on bills rendered in March 2005, with no immediate change in the current base rates. The settlement also proposes a formula rate plan with an ROE mid-point of.10.65%. The LPSC has solicited comments on the proposed settlement from the, parties to the various proceedings at issue in the settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.
, ** . . 1 _.
Entergy Louisiana..... 9.7%- In January 2004, Entergy Louisiana filed with the LPSC an application for a 11.3%(1) $167 million base rate increase and an ROE of 11.4%. The currently authorized ROE midpoint is 10.5%. Hearings in thisn matter concluded in December 2004. Based on the evidence submitted at the hearing, the LPSC staff is recommending approximately a $7 million base rate increase. The LPSC staff proposed the implementation of a formula rate plan that includes a provision for the recovery of incremental capacity costs, including those related to the proposed Perryville acquisition. A decision by the LPSC-iS expected in mid- to late-March 2005 on these issues.. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement with the LPSC that would resolve, among other dockets, dockets established to consider issues concerning the companies' power purchases for the- summers of 2001, 2002,
-2003, and 2004. The proposed settlement currently includes an offer to refund
$14 million to Entergy Louisiana's customers. The LPSC has solicited comments. on thei proposed -settlement from the parties to the various
- proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005.
108
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Entergy Mississippi... 9.3%- An annual formula rate plan is in place. Entergy Mississippi made its annual 12.2%(2) formula rate plan filing in March 2004 based on a 2003 test year. There was no change in rates based on an adjusted ROE midpoint of 10.77%. Entergy New Orleans 10.25%- The midpoint ROE of the electric and gas plans is 11.25%, with a target equity 12.25%(3) component of the capital structure of 42%. Entergy New Orleans made a formula rate plan filing in April 2004. The City Council ordered that electric and gas rates remain unchanged from levels set in 2003. Entergy New Orleans will file its formula rate plan for the year ended December 31, 2004 by May 1, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in effect based on the December 31, 2004 test year shall continue. System Energy ...........- 10.94% ROE approved by July 2001 FERC order. No cases pending before FERC. (1) Entergy Louisiana's formula rate plan expired with the 2001 test year. Under the expired formula, if Entergy Louisiana earned outside of the bandwidth range, rates would be adjusted on a prospective basis. If earnings were above the bandwidth range, rates would be reduced by 60 percent of the amount necessary to bring earnings down to the top of the bandwidth, and if earnings were below the bandwidth range, rates would be increased by 60 percent of the corresponding shortfall. (2) ~Under Mississippi law and Entergy Mississippi's formula rate plan, if Entergy Mississippi's earned ROE is above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's rates are reduced by 50 percent of the difference between the earned ROE and the top of the bandwidth. In such circumstance, Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the point halfway between such earned ROE and the top of the bandwidth.- Entergy Mississippi's retail rates are set at that halfway-point ,ROE level. (Before the comparison is made of the earned ROE to the bandwidth, the bandwidth can be adjusted for performance measures by as much as 1%. Rates are adjusted pursuant to Entergy Mississippi's formula rate plan on a prospective basis only.) In the situation where Entergy Mississippi's earned ROE is not above the top of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the top of the range-of-no-change at the top of the bandwidth. If earnings are below the bandwidth range, rates are increased by 50 percent of the difference between the earned ROE and the bottom of the bandwidth. Under the provisions of Entergy Mississippi's formula rate plan, each annual formula rate plan filing incorporates a revised calculation of the benchmark ROE. (3) If Entergy New Orleans earns outside the bandwidth range, rates will be adjusted on a prospective basis. Under the gas formula rate plan, if earnings are above the bandwidth range, rates are reduced by 100 percent of the overage, and if below, increased by 100 percent of the shortfall.. In addition, if the ROE falls between 11.5% and 12.25%, rates are reduced by 60 percent of the difference (between 11.5% and 12.25%), and if the ROE falls between 10.25% and 11%, rates are increased by 40 percent of the difference (between 10.25% and 11%). Under the electric formula rate plan, rates are adjusted accordingly by 100 percent of the amount of any overage or shortfall. Entergy New Orleans may earn up to 13.25% under the electric formula rate plan provided that the increase is caused by its share of energy cost savings under the generation performance-based recovery plan discussed below. Entergy Arkansas Fuel Recovery Entergy Arkansas' rate schedules include .an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve month period commencing on April I of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying 109
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy charges, of the energy cost for the prior calendar year. Entergy Arkansas' 2004 filing is discussed in Note 2 to the domestic utility companies and System Energy financial statements. Entergy Gulf States Louisiana Jurisdiction - Formula Rate Plan In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement with the LPSC. Included in the settlement is a proposal of a three-year formula rate plan for Entergy Gulf States' Louisiana operations that included a provision for the recovery of incremental capacity costs. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005. Fuel Recovery Entergy Gulf States' Texas rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, not recovered' in base rates. Under the current methodology, semi-annual revisions of the fixed fuel factor may be made in March and September based on the market price of natural gas. Entergy Gulf States will likely continue to use this methodology until retail open access begins in Texas. To the extent actual costs vary from the fixed fuel factor, refunds or surcharges are required or permitted. The amounts collected under the fixed fuel factor through the start of retail open access are subject to fuel reconciliation proceedings before the PUCT. At the start of retail open access for Entergy Gulf States in Texas, which is currently delayed, fuel and purchased power cost recovery will be subject to the fuel component of the price-to-beat rates approved by the PUCT. The PUCT fuel cost reviews that were resolved during the past year or are currently pending are discussed in Note 2 to the domestic utility companies and System Energy financial statements. Entergy Gulf States' Louisiana electric rates include a fuel adjustment designed to recover the cost of fuel and purchased power costs. The fuel adjustment'contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers. Entergy Gulf States' Louisiana gas rates include a purchased gas adjustment based on estimated gas costs for the billing month adjusted by a surcharge or credit'for deferred fuel expense arising fronm the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers. ' Entergy Louisiana Formula Rate Plan The LPSC staff has proposed the implementation of a formula rate plan for Entergy Louisiana that includes a provision for the recovery of incremental capacity costs. A decision from the LPSC is expected in mid- to late-March 2005 Fuel Recovery Entergy Louisiana's rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers. In September 2002, Entergy Louisiana settled a proceeding that concerned a contract entered into by Entergy Louisiana to purchase, through 2031, energy generated by a hydroelectric facility known as the Vidalia project. In the settlement, the LPSC approved Entergy Louisiana's proposed treatment of the regulatory impact of a tax accounting election related to that project. In general, the settlement permits Entergy Louisiana to keep a portion of the tax benefit in exchange for bearing the risk associated with sustaining the tax treatment. The LPSC settlement divided the term of the Vidalia contract into two segments: 2002-2012 and 2013-2031. During the first 110
Part I Item 1 Entergy Corporation, Domestic utility companies, and System Energy eight years of the 2002-2012 segment, Entergy Louisiana agreed to credit rates by flowing through its fuel adjustment calculation $11 million each year, beginning monthly in October 2002. Entergy Louisiana must credit rates -in this way and by this- amount even if Entergy Louisiana is unable to sustain the tax deduction. Entergy Louisiana also must' credit rates by $11 million each year for an additional two years unless either the tax accounting method elected is retroactively' repealed or the Internal Revenue Service denies the entire deduction related to the tax accounting method. Entergy Louisiana agreed to credit ratepayers additional amounts unless the tax accounting election is not sustained, if it is challenged. During the years 2013-203 1, Entergy Louisiana and its ratepayers would share* the remaining benefits of this tax accounting election.- Note '8 to the domestic utility companies and System Energy financial statements contains further discussion of the obligations related to 'the Vidalia project. Entergy Louisiana has reduced its indebtedness and preferred stock with a portion of the cash generated by the tax election. In accordance with the terins of the September 2002 settlement, Entergy Louitiana'requested SEC approval to return up to $350 million of common equity capital to Entergy Corporation in order to maintain Entergy Louisiana's current capital structure. In December 2002, Entergy Louisiana repurchased $120 million of common stock from Entergy Corporation and paid a dividend of $122.6 million pursuant to the SEC approval. The provisions of the settlement provide that the LPSC shall not recognize or use Entergy Louisiana's use of this cash in setting any of Entergy Louisiana's rates. Therefore, to the extent Entergy Louisiana's use of the proceeds would ordinarily' have reduced its rate base, no change in rate base shall be reflected for ratemaking purposes., The SEC approval for additional return of equity capital is now expired. lEntergy Mississippi Performance-Based Formula Rate Plan Entergy Mississippi files a performnance-based formula rate plan every 12 months that compares the annual earned rate of return to, and adjusts it against, a benchmark rate of return. ' The benchmark is calculated under a separate formula within the formula rate plan. The formula rate plan'allows for periodic small adjustments in rates, up to an amount that would produce a change in 'Entergy Mississippi's overall revenue of almost 2%, based on a comparison of actual earned returns to benchmark returns and upon certain performance factors. Entergy Mississippi filed a formula rate plan in March 2004 for the 2003 test year, and filings are due to continue annually thereafter., The March 2004 formula rate plan filing is discussed in Note 2 to the domestic utility companies and System Energy financial statements. Fuel Recovery I Entergy Mississippi's rate schedules include energy cost recovery riders to recobver fuel and purchased energy costs. The rider utilizes projected energy costs filed quarterly by Entergy Mississippi to develop an energy cost rate. The energy cost rate is redetermined each calendar quarter and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy cost as of the second quarter preceding the redetermination. In January 2005, theMPSC approved a change in Entergy;Mississippi's energy cost recovery rider. Entergy Mississippi's fuel over-tecoveries: for the third quarter of 2004 will be deferred from the first quarter 2005 energy cost recovery rider adjustment calculation. The deferred amount of $21.3 million plus carrying charges will be refunded through the energy cost recovery rider in the second and third quarters of 2005 at a rate of 45% and 55%, respectively. Entergy New Orleans Formula Rate Plans In May 2003, the City Council approved the implementation of formnula rate plans for electric and gas service that will be evaluated annually until 2005. Entergy New Orleans made a filing with the City Council in April 2004 based upon a 2003 test year, which after review, resulted in a City Council resolution approving no change in gas and electric rates. Entergy New Orleans will make a filing in accordance with the formula rate III
Part I Item I EAtergy Corporation, Domestic utility companies, and System Energy plans by May 1, 2005 based on a 2004 test year. Under the formula rate plans, the midpoint ROE of both plans is 11.25%, with.a target equity component of Entergy New Orleans' capital structure of 42%. Any change in rates would be prospective, with, the first billing cycle effective after September 1, 2005. Entergy New Orleans' can earn between 10.25% and 12.25% under the electric plan, and betw een 11% and 11.5% under the gas plan, with earnings within those ranges not resulting in a change in rates. Entergy New Orleans' formula rate plan, filings are discussed in Note 2 to the domestic utility companies and System.Energy financial statements.
-a .. uiti.,,i~s OJ '/-l9?isiti . Iu ..U - t. ( tV!' wit-, Q.fvfiLi .AYt, i-~ijiri al by) I>, - -'.; ' } "' it}<>; zjn'.
2 x,t;Ji{iJOtf, XLAt
.iii-pu In May 2003, the City Council approved implementation of a generation performance-based rate calculation in the electric fuel adjustment clause under which Entergy New Orleans receives 10% of calculated, fuel and purchased power cost savings in excess of $20 million, based on a defined benchmark, subject to a 13.25%
return on equity limitation for electric operations as provided for in the electric formula rate plan. Entergy New Qrleans bears 1.0% of any "negative" fuel and purchased power cost savings. In October 2004, Entergy New Orleans' annual evaluation report was submitted for the period June 2003 through May 2004.. Additional savings associated with the first year generation performance-based rate calculation were $71 million of which Entergy New Orleans' share was $5.1 million. i t'b .,. JU.i 't it. ICI t i.> ftl2SuU :U ' I it-I; 3lJ .'sj T.A :-. oPi Usnxitayw )ai orb oJ wms;o g {),\ < rro:!r.i'.oft, ] 1 . uj~i'ttvrt, btc I'> : "r n. I;I vtmmlt:- uitt. ty.ie i.;;) Fuel Recovery :} i. .n.i :- we J 0, o; : : ";H ictj;jI CttV,/tiitifli~tC22 tr to StIO':f,
- Entergy New Orleans' electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges. The adjustment also includes the difference between non-ftel Grand Gulf costs paid by Entergy New Orleans and the estimate of such costs, which are included in base rates, as provided in Entergy New Orleans' Grand Gulf rate settlements. Entergy New Orleans' gas rate schedules include an adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges. In June and.November 2004,. the City Council passed resolutions implementing a package of measures developed by Entergy New Orleans and the Council Advisors to protect customers from potential gas price spikes during the 2004 - 2005 winter heating season. These measures include: maintaining Entergy New.Orleans' financial hedging plan for its.purchase of wholesale gas, and deferral of collection of up to $6.2 million of gas.costs associated with a cap on the purchased gas adjustment in November and December 2004 in the, event that the average residential customer's gas bill were to exceed a threshold level.'
The deferrals resulting from, these caps will receive accelerated recovery over a seven-month period beginning in April 2005. o... it.;woo'k "o u . In November 2004, the City Council directed Entergy New Orleans to confer with the Council Advisors regarding possible modification of the current gas cost collection mechanism in order to address concerns regarding its fluctuations particularly during the winter heating season. .J'woxxt tuln'.? ' 181 :'i 'i2.i 1 Franchises,, -, l ijpj '.'v, iv l iitts. wilt i:, .'Et !:fittqA¶Wt f t t >, 'T1O 38 e .T }hs I*§ iief}sin.itlniloi flub 5tad? '1il 2W 1S 5 't.i:12flii ii' .O3<38 @ i ". is 'i~K) 7-'3t' i9951Th i ,.. . '?'iso- 2P8 Gfl'fi !YYTelf -i At-, Entergy Arkansas holds exclusive franchises to provide electric service in approximately 307 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property.. h Arkansas, franchises are considered to be contracts and, therefore, are.terminable uponbreachofthetenrms ofthefranchise.,, ,,. 4,,. ., ,Iio4fl1ftJ i..2' Dl- l , 0n' !.-. "i! 'Ltjr DC A 10 iJ o : Ul;u.to a tr~1tmifD t:- t tl ' , .,m ., ' If r,?:Ii' t K Xt v' i a In Louisiana, Entergy Gulf States holds non-exclusive franchises, permits, or certificates of convenience and necessity to provide electric service in approximately 55 incorporated municipalities and the unincorporated areas of approximately 19 parishes, and to provide gas service in the City of Baton Rouge and the unincorporated areas of two parishes. In Texas, Entergy Gulf States holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 24 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 65 incorporated municipalities. Entergy Gulf States typically is granted 50-year franchises in Texas. Most of Entergy Gulf States' Louisiana franchises have a term of 60 years., Entergy Gulf StakIestcuent elect c franchises will expire during 2007 - 2045 in Texas and during 2015-2046 in Louisiana., .. j £ K I :;fit -1'fi alO ; .2%. fc It r-i? '., 112
Part I Item 1 Entergy Corporation, Domestic utility companies, and System Energy Entergy Louisiana holds non-exclusive franchises to- proVide electric service in approximately 116 these incorporated Louisiana municipalities. Most of these franchises have 25-year terms, although six of municipalities have granted 60-year franchises. Entergy Louisiana also supplies electric service in approximately 353 unincorporated communities, all of which are located in Louisiana parishes in which it holds non-exclusive franchises. ....- ;-t, }i6.8-9'fy-i!~fe.,iv "o.> i.30iti -lif,W?;': ~~ -l. .si.. Entergy Mississippi has received from the MPSC certificates of public convenience a'nd necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. such Under Mississippi statutory law, such certificates are exclusive. Entergy Mfisissippi may continue to serve in-municipal franchise is municipalities upon payment of a statutory franchise fee, regardless of whether an original still in existence. city Entergy New Orleans provides electric and gas service ir; the City'of New'Orleans pursuant to by Entergy Louisiana). These ordinances contain ordinances (except electric service in Algiers, which is provided utility a continuing option for the City of New Orleans to purchase Entergy New Orleans' electric and gas properties. *-'. ' "t 5-.1 '_ _.... . The buisin'ess of Sysiem Energy is limited to wholesale power sales. It has no distribution franchises. Propertkaiad Oilrier Generation e'irite,, X , : t' -. . j,' ': Generating Stations and The total capability of the generating stations owned and leased by the domestic utility companies System Energy as of December 31, 2004, is indicated below: Owned and Leased Capability MW(1) Company t, Total Gas/Oil Nu-Iear Coal Hydro Enterg~'Arkansas -' 4,709 1,613' 1,837 1,189 70"'
-- llig Gulf State's"} 6,4 4;z - !. ";968 -"627 w ;i i, Enwg Loisan £363 4,276 -*-ti1a087 - -
g EntergyAMississippi 2,490 4089 12,898 v Entergy New Orleans . 915 915
; System Energy ' : 1 ,143 _ .'i""_ 1,143 : '""*r Cl- J'_'.
Ttl 2i si53 i4184 i 0;35 ! 2,224 70 (1) "i'Qfwld and ]'dased 68pability' is'the dependable load caryng capability as demonst'rajed uridei actual on the primary fuel (assuming no curtai ients) that each station was' de'sign-&d'fo En"tergys d and capacity projectilons are reviewed to assess ting ain m for additional generating' caacity and iiirconnections. These reviews consider existing and rojected demand, the availablilty and pri6e Ol power, the lcti of new loads, and economy. Peak load in ie U.S.' Utility service lerritory is typically" arounhd '21,000'W, wth minimu'foa 'typii1y' around 9,000 MW. Atlliing f6r ani adequate reserve margin, Entergy has been short approximately 3,000 MW during the summer pe f.oa perio. 'In addition to its net short position at summer peak, Entergy considers its generation in three categories: (1) baseload (e.g. coal and nuclear); (2) load-following (e.g. combined cycle gas-fired); and (3) peaking. The relative supply and demand for these categories of generation vary by region of the Entergy System. For example, the north end of its system has more baseload coal and nuclear generation than regional demand requires, but is short load-following or intermediate generation. In the south end of the Entergy system, load would be more effectively served if gas-fired intermediate resources already in place were supplemented with additional solid fuel baseload generation. 113
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Until recently, Entergy covered its short position at summer peak almost entirely with purchases from the spot market. In the fall of 2002, Entergy began a process of issuing requests for proposal to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the domestic utility companies. The first request for proposal sought resources to provide summer 2003 and longer-term resources through a broad range of wholesale power products, including short-term (less than one year), limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. A detailed process which included the involvement of an independent monitor was developed to evaluate submitted bids. The following table illustrates the results of the request for proposal process for limited and short-term products. All of the contracts which were awarded and signed were with non-affiliates, with the exception of the contract covering 185 MW to 206 MW from RS Cogen. A Selected for Contracts Negotiation Signed Notes Fall 2002 550 MW 425 MW Limited-term resources contracted. Entergy Services also pursued discussions with several bidders for life-of-unit purchased power agreements or the acquisition of an ownership interest in existing generating facilities. These negotiations resulted in the Perryville acquisition agreement, discussed below. Supplemental 500 MW 220 MW Short-term purchase for the summer 2003. 2002 Spring 2003 380 MW 380 MW Limited-term resources contracted. Fall 2003 390 MW 390 MW Two separate resources contracted for a term of three years with deliveries beginning in the summer of 2004. In January 2004, Entergy Louisiana signed a definitive agreement to acquire the 718 MW Perryville power plant for $170 million. The agreement has subsequently been amended to allow the current plant owner to retain the interconnection facilities associated with the plant, resulting in a decrease in the acquisition price to $162 million. As a result of the amended terms, the FERC issued an order in October 2004 disclaiming jurisdiction over the acquisition. This order currently is subject to rehearing by the FERC. The plant is owned by a subsidiary of Cleco Corporation, which subsidiary submitted a bid in response to Entergy's Fall 2002 request for proposals for supply-side resources. The signing of the agreement followed a voluntary Chapter 11 bankruptcy filing by the plant's owner. Entergy expects that Entergy Louisiana will own 100 percent of the Perryville plant, and that Entergy Louisiana will sell 75 percent of the output to Entergy Gulf States under a long-term cost-of-service power purchase agreement. In addition, Entergy Louisiana and Entergy Gulf States executed an interim power purchase agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by December 2005) for 100 percent of the output of the Perryville power plant. In April 2004, the bankruptcy court approved Entergy Louisiana's agreement to acquire the plant. In March 2004, Entergy Gulf States and Entergy Louisiana filed with the LPSC for its approval of the acquisition and long-term cost-of-service power purchase agreement. Entergy is seeking approval from the LPSC of cost recovery for the acquisition, giving consideration to the need for the power and the prudence of Entergy Louisiana and Entergy Gulf States in engaging in the transaction. Hearings are scheduled for March 2005. Assuming regulatory approval by the LPSC, Entergy Louisiana expects the Perryville acquisition to close in mid-2005. 114
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy In addition to the purchases from non-affiliates shown above, Entergy Louisiana, Entergy New Orleans, and Entergy Arkansas made filings with their respective retail regulators seeking approval to enter into transactions with affiliates as shown in the following table: Status of Approval in Company Proposed Transactions Retail Jurisdiction Entergy 1), Purchased a 140 to 156 MW capacity purchase call option The LPSC found contracts Louisiana from RS Cogen for June 2003 through April 2006. 1) and 2) to be prudent and
- 2) Entered a life-of-unit purchase power agreement (PPA) to authorized Entergy purchase approximately 5 1MW (increasing to 61 MW in Louisiana to execute these 2010) of output from Entergy Power's share of contracts. The LPSC has Independence 2. not yet approved the life-
- 3) Enter a life-of-unit PPA with Entergy Gulf States to of-unit PPAs for proposals purchase two-thirds of the output of the 30% of River 3) and 4); a bridge contract Bend formerly owned by'Cajun (approximately 200 MW). however, is currently in
- 4) Enteri a life-of-resources PPA with Entergy Arkansas to place for contract 3) purchase approximately 110 MW of capacity not included effective through in Entergy Arkansas' retail rate base, consisting of a December 31, 2005. The portion of the output from ANO, White Bluff, outcome of the life-of-Independence, and Entergy Arkansas' share of Grand resources PPAs is still Gulf. pending FERC approval.
Entergy New 1) Purchased a 45 to 50AMW capacity purchase call option In May 2003, in Orleans from RS Cogen for June 2003 through April 2006. connection with a
- 2) Entered a life-of-unit PPA to purchase approximately settlement relating to 50 MW (increasing to 60 MW in 2010) of output from Entergy New Orleans' Entergy Power's share of Independence 2. cost-of-service study and
- 3) Entered a life-of-unit PPA with Entergy Gulf States to revenue requirement, the purchase one-third of the output of the 30% of River Bend City Council authorized formerly owned by Cajun (approximately 100 MW). Entergy New Orleans to
- 4) Entered a life-of-resources PPA with Entergy Arkansas to enter into contracts for the purchase approximately 110 MW of capacity not included proposed transactions.
in Entergy Arkansas' retail rate base, consisting of a portion of the output from ANO, White Bluff, Independence, and Entergy Arkansas' share' of Grand Gulf. Entergy i) Enter into the life-of-resources PPAs to sell power as In May 2003, the APSC Arkansas discussed in both Entergy Louisiana's and Entergy New found the PPAs involving Orleans' proposal 4) above. Entergy Arkansas in the public interest. Entergy also filed with the FERC the affiliate agreements described above. In May 2003, the FERC accepted the agreements for filing, subject to refund, with the contracts becoming effective on June 1, 2003. The FERC also established a hearing process to review the justness and reasonableness of the agreements. Several parties have intervened or filed protests regarding the request-for-proposals process and the agreements filed with the FERC, and the hearings in the proceeding ended in December 2004. An initial decision by the AU is still pending and is scheduled for July 2005. Interconnections Entergy's generating units are interconnected by a transmission system operating at various voltages up to 500 kV. These generating units consist primarily of steam-electric production facilities and are centrally dispatched and operated. Entergy's domestic utility companies are intercotnected with many neighboring utilities. In addition, the domestic utility companies are members of the Southeastern Electric Reliability Council (SERC). The primary 115
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy purpose of SERC is to ensure the reliability and adequacy of the electric bulk power supply in the southeast region of the- United States. SERC is a member of the North American Electric Reliability Council. Gas Property As of December 31, 2004, Entergy New Orleans distributed and transported natural gas for distribution solely within New Orleans, Louisiana, through a total of 33 miles of gas transmission pipeline, 1,495 miles of gas distribution pipeline, and 1,029 miles of gas service pipeline from the distribution mains to the customers. As of December 31, 2004, the gas properties of Entergy Gulf States, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Gulf States' financial position. Titles Entergy's generating stations and major transmission substations are generally located on properties owned in fee simple. Most of the transmission and distribution lines are constructed over private property or public rights-of-way pursuant to easements or appropriate franchises. The domestic utility companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations. Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy are subject to the liens of mortgages securing the mortgage bonds of such company. The Lewis Creek generating station is owned by GSG&T, Inc., a subsidiary of Entergy Gulf States, and is not subject to the lien of the Entergy Gulf States mortgage securing its first mortgage bonds. Lewis Creek is leased to and operated by Entergy Gulf States. Fuel Supply The generation portfolio of the U.S. Utility contains a high percentage of natural gas and nuclear generation. The sources of generation and average fuel cost per kWh for the domestic utility companies and System Energy for the years 2002-2004 were: Natural Gas Fuel Oil Nuclear Fuel Coal
% Cents % Cents % Cents % Cents of Per of Per of Per of Per Year Gen kWh Gen kWh Gen kWh Gen kWh 2004 23 7.31 6 5.02 52 .49 19 1.39 2003 26 6.53 4 5.04 52 .48. 18 1.26 2002 39 3.88 - 15.78 46 .47 15 1.37 Actual 2004 and projected 2005 sources of generation for the domestic utility companies and System Energy, including proposed power purchases from affiliates under power purchase agreements in 2005, are:
Natural Gas Fuel Oil Nuclear Coal 2004 2005 2004 .2005 2004 , 2005 2004 2005 Entergy Arkansas (a) 1% - 65% 64% 34% 35% Entergy Gulf States 41% 36% 1% - 36% 36% 22% 28% Entergy Louisiana 38% 40% 8% 8% 52% 50% 2% 2% Entergy Mississippi 9% 3% 46% 62% - - 45% 35% Entergy New Orleans 55% 55% - - 32% 31% 13% 14% System Energy - - . - 100%(b) 100%(b) - - - U.S. Utility (a) 23% 22% -6%- 8% 52% 50% 19% 20%. 116
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy (a) Hydroelectric power provided less than 1% of Entergy Arkansas' generation in 2004 and is expected to provide approximately 1% of its generation in 2005. (b) Capacity and energy from System Energy's interest in Grand Gulf I was historically allocated as follows: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans
- 17%. Pursuant to purchased power agreements that are the subject of a pending proceeding at the FERC, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf I to Entergy Louisiana and Entergy New Orleans.
Natural Gas The domestic utility companies have long-term firm and short-term interruptible gas contracts. Long-term firm contracts for power plants comprise less than 15% of the domestic utility companies' total requirements but can be called upon, if necessary, to satisfy a significant percentage of the utility companies' needs. Short-term contracts and spot-market purchases satisfy additional gas requirements. As of January 1, 2005, Entergy Gulf States owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations. Entergy Louisiana has a long-term natural gas supply contract, which expires in 2012, in which Entergy Louisiana agreed to purchase natural gas in annual amounts equal to approximately one-third of its projected annual fuel requirements for certain generating units. Annual demand charges associated with this contract are estimated to be $7.2 million. Such charges aggregate $58 million for the years 2005 through 2012. Many factors, including wellhead deliverability, storage and pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is tied to weather conditions as well as to the prices of other energy sources. Entergy's supplies of natural gas are expected to be adequate in 2005. However, pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the domestic utility companies will use alternate fuels, such as oil, or rely to a larger extent on coal, nuclear generation, and purchased power. Coal Entergy Arkansas has a long-term contract for low-sulfur Wyoming coal for Independence. This contract, which expires in 2011, provides for approximately 90% of Independence's expected coal requirements for 2005. Entergy Arkansas has entered into three medium term (three-year) contracts for approximately 67% of White Bluffs coal supply needs. These contracts are staggered in term so that one is renewed every year. Entergy Arkansas has an additional 16% of its 2005 coal requirement committed in a one-year contract.' Additional coal requirements for both Independence and White Bluff are satisfied by spot market or over the counter purchases. Entergy Arkansas has a long-term railroad transportation contract for the delivery of coal to both White' Bluff and Independence that expires in 2011. A second carrier now delivers a portion of White Bluffs coal requirements under a long-term transportation agreement that expires on December 31, 2006. Entergy Gulf States has a long-term contract, which contains periodic price re-openers, for the supply of low-sulfur Wyoming coal for Nelson Unit 6. Entergy Gulf States has entered discussions with the supplier regarding the first price re-opener. If a new price is negotiated, the agreement would extend to April 2007. Entergy Gulf States has executed two transportation requirements contractsgwith railroads to deliver coal to Nelson Unit 6 through 2007. The operator of Big Cajun 2,'Unit 3, Louisiana Generating, LLC, has advised Entergy Gulf States that it has coal supply and transportation contracts that should provide an adequate supply of coal for the operation of Big Cajun 2, Unit 3 for the foreseeable future.' 117
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Nuclear Fuel The inuclear fuel cycle consists of the following:
- mining and milling of uranium ore to produce a concentrate;
- conversion of the concentrate to uranium hexafluoride gas; -
- enrichment of the hexafluoride gas;
- fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
- disposal of spent fuel.
System Fuels, a company owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, is responsible for contracts to acquire nuclear material to be used in fueling Entergy's utility nuclear units, except for River Bend. System Fuels also maintains inventories of such materials during the various stages of processing. The domestic utility companies purchase enriched uranium hexafluoride from System Fuels, but contract separately for the fabrication of their own nucear' fuel. The requirements for River Bend are met pursuant to contracts made by Entergy Gulf States. Based upon currently planned fuel cycles, Entergy's nuclear units have contracts and inventory that provide adequate materials and services. Existing contracts for uranium concentrate, conversion of the concentrate to uranium hexafluoride, and enrichment of the uranium hexafluoride will provide a significant percentage of these materials and services over the next several years. Uranium market supply became much tighter in 2003 and early 2004 than in previous years. Costs and risks of obtaining supplies have increased for nuclear fuel users. It will be necessary for Entergy to enter into additional arrangements to acquire nuclear fuel in the future. It is not possible to predict the ultimate cost or availability of such arrangements. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These arrangements are subject to periodic renewal. See Note 9 to the domestic utility companies and System Energy financial statements for a discussion of nuclear fuel leases. Natural Gas Purchased for Resale Entcrgy New Orleans has several suppliers of natural gas. Its system is interconnected with,three interstate and three intrastate pipelines. Entergy New Orleans' primary suppliers currently are Atmos Energy and Louisiana Gas Services. Entergy New Orleans has a "no-notice" service gas purchase contract with Atmos Energy which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Atmos, Energy gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This, service is subject to FERC-approved rates. Entergy New. Orleans has firm contracts with its two intrastate suppliers and also makes interruptible spot market purchases. In recent years, natural gas deliveries to Entergy New Orleans have been subject. primarily to weather-related curtailments. However, Entergy New Orleans> experienced no such curtailments in 2004.;
,As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy New Orleans' suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline could curtail transportation capacity only in the event of pipeline system constraints. Based on the current supply of natural gas, and absent extreme weather-related curtailments, Entergy New Orleans does not anticipate any interruptions in natural gas deliveries to its customers.
Entergy Gulf States purchases natural gas for resale under a firm contract from Enbridge Marketing (U.S.) Inc. (formerly Mid Louisiana Gas Company) entered into September 2002 for a five-year period. The contract will continue annually at the end of the term unless prior notice is given by Entergy Gulf States. 118
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Federal Regulation State or local regulatory authorities, as described above, regulate the retail rates of Entergy's domestic utility companies. FERC regulates wholesale rates (including intrasystem sales pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy's sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy) The domestic utility companies historically have engaged in the coordinated planning, construction, and operation of generation and transmission facilities pursuant to the terms of the System Agreement. Under the terms of the System Agreement, generating capacity and other power resources are jointly operated by the domestic utility companies. The System Agreement provides, among other things, that parties having generating reserves greater than their load requirements (long companies) shall receive payments from those parties having deficiencies in generating reserves (short companies). Such payments are at amounts sufficient to cover certain of the long companies' costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred stock, and a fair rate of return on common equity investment. Under the System Agreement, these charges are based on costs associated with the long companies' steam electric generating units fueled by oil or gas. In addition, for all energy exchanged among the domestic utility companies under the System Agreement, the companies purchasing exchange energy are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs. Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies in their execution of the System Agreement, and seek support for local regulatory authority over System Agreement issues. Regarding the proceeding at the LPSC, Entergy believes that state and local regulators are preempted by federal law from reviewing and deciding System Agreement issues for themselves. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting FERC rate schedules that are part of the System Agreement, and from subsequently enforcing that interpretation. The LPSC interpreted a System Agreement rate schedule in the unrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed the LPSC's decision. In 2003, the U.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the decisions of the LPSC and the Louisiana Supreme Court. In February 2004, a FERC ALJ issued an Initial Decision in the LPSC-initiated proceeding at the FERC. The Initial Decision decided some issues in favor of the relief sought by the LPSC, and decided some issues against the relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALUs Initial Decision. Entergy's exceptions to the AL's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method. If the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to 119
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy companies whose costs currently are projected to exceed that average. If the FERC adopts jthe ALJs Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The ALUs Initial Decision would reallocate, production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost. An assessment of the potential effects of the AU's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased; power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu during the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALUs Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009: Average Annual Range of Annual Payments Payments or (Receipts) or (Receipts) for 2005-2009 Period, (In Millions) - (In Millions) Entergy Arkansas $154 to $281 - $215 Entergy Gulf States ($130) to ($15) ($63) - ; Entergy Louisiana ($199) to ($98) ($141) , Entergy Mississippi ($16) to $8 $1 Entergy New Orleans ($17) to ($5) ($12) Management believes that any changes in the allocation of production costs resulting from a FERC decision and related. retail proceedings should result in similar rate changes for retail customers, The, timing of recovery of these costs in rates could be the subject of additional proceedings at the APSC and elsewhere, however, and a delay in 'full; recovery of any increased allocation of production costs could result in additional financing requirements. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy' does not believe that the ultimate resolution of these proceedings will have a material effect, on its financial condition or results of operation. In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC.ALJs Initial Decision would have on Entergy Arkansas' customers., The APSC order establishes! an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order, of Investigation. The testimony emphasizes that the AL's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; and states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate. 120
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the AL's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations. In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Louisiana, as well as the -named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity. Transmission In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to'work to resolve various issues related to the establishment of such RTOs. In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal -was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations. Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should 'be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences. 121
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the petition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public, utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005. In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff,' filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time; although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion of the proposal currently scheduled for August 2005. FERC's Supply Margin Assessment In November 2001, FERC issued an order that established a new generation market power screen (called Supply Margin Assessment) for purposes of evaluating a utility's request for market-based, rate authority, applied that new screen to the Entergy System (among others), determined that Entergy and the others failed the screen within their respective control areas, and ordered these utilities to implement certain mitigation measures as a condition to their continued ability to buy and sell at market-based rates. Among other things, the mitigation measures would require that Entergy transact at cost-based rates when it sells in the hourly wholesale market within its control area. Entergy requested rehearing of the order, and FERC delayed the implementation of certain mitigation measures until such time as it had the opportunity to consider the rehearing request. In June 2003, the FERC proposed and ultimately adopted new market behavior rules and tariff provisions that would be applied to any market-based sale. Entergy modified its market-based rate tariffs to reflect the new provisions but requested rehearing of FERC's order. In April 2004, the FERC issued its Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy. In its April 2004 order, the FERC established a new interim generation market power analysis that will consider two indicative market power screens: (1) the pivotal supplier screen that is designed to measure an applicant's market power based on the applicant's share of uncommitted capacity at the time of the control area market's annual peak demand; and (2) the market share screen that is designed to evaluate an applicant's market share of uncommitted capacity on a seasonal basis. An integrated utility's native load obligation will be reflected in both screens; however, the proxy for native load obligation differs between the screens. For the uncommitted pivotal supplier screen, the proxy for native load is the average of the daily native load peaks during the month in which the annual peak load day occurs; for the uncommitted market share screen the proxy for native load is the minimum peak load day for each season. In the event an applicant fails either of these screens, there will be a rebuttable presumption that market power exists. The applicant will then have the opportunity to either: (1) submit a more detailed market power analysis that reflects market prices and measures an applicant's "economic capacity" and "available economic capacity" under the "delivered price test;" or (2) propose case-specific mitigation 122
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy tailored to the applicant's specific circumstances or adopt cost-based rates for sales within the applicant's control area. In its April 2004 order, the FERC also: (1) determined that transmission market power and the need to employ an independent entity to operate and administer an applicant's OASIS site is more properly considered in other proceedings, to the extent appropriate, and would not be considered in evaluating an applicant's generation market power for purposes of granting market-based rate authority; and (2) eliminated the exemption from the generation market power analysis for sales within an RTO/ISO that had approved market monitoring. Several parties, including Entergy, filed for rehearing of the April 2004 order. Among other things, Entergy argued that the market share screen is overly conservative and overstates vertically integrated utilities' ability to exercise market power. In July 2004, the FERC issued an order on rehearing reaffirming the use of the pivotal supplier and market share screens and clarified certain instructions for performing such analysis. With regard to the delivered price test analysis, the FERC declined to make a determination on whether an applicant's native load obligations will be reflected when evaluating an applicant's generation market power, but instead indicated that it would evaluate the arguments of both the applicant and intervenors as to which measure (one with or without native load obligations) more accurately reflects market conditions. Entergy appealed the April 2004 and July 2004 orders to the United States Court of Appeals for the District of Columbia Circuit. In February 2005, the D.C. Circuit granted the FERC's motion to dismiss Entergy's appeal on the grounds that Entergy's claims were premature. The D.C. Circuit found that Entergy's petition was. premature because the D.C. Circuit was not yet in a position to evaluate the manner in which the FERC will apply its new market power tests or whether the tests will have adverse consequences for Entergy. Thus, the D.C. Circuit did not rule on the merits of Entergy's appeal. Entergy filed with the FERC its generation market power analysis pursuant to the two indicative screens in August 2004. Entergy's analysis indicated that it passed the pivotal supplier screen for all relevant geographical regions, but failed the market share screen within its control area. At the same time, Entergy submitted the results of the delivered price test for Entergy, which indicate that Entergy does not have market power in any wholesale market when Entergy's native load obligations are reflected. In December 2004, the FERC issued an order pursuant to Section 206 of the Federal Power Act: (1) finding that Entergy failed the market share screen; (2) indicating that the FERC is continuing to review the delivered price test analysis submitted by Entergy; (3) establishing a refund effective date for Entergy's market-based wholesale sales within its control area; and (4) indicating that the FERC believes that it can reach a decision concerning Entergy's market-based rate authority by the second quarter of 2005. If the FERC were to revoke Entergy's or the domestic utility companies' market-based rate authority for wholesale sales within the Entergy control area, these entities would be limited to making wholesale sales pursuant to cost-based rate schedules approved by the FERC. The wholesale sales of the domestic utility companies and their affiliates, including Entergy's non-nuclear wholesale assets business, within the Entergy control area could either be cost-justified or are of such a limited amount that management does not believe that the revocation of their market-based rate authority would have a material effect on the financial, results of Entergy. Because Entergy believes that it does not possess market power and that the FERC's tests are flawed, Entergy intends to vigorously defend its market-based rate authority. The FERC has also initiated a rulemaking proceeding to address, among other things, whether the FERC should retain or modify its existing four-prong test for evaluating market-based rate applications (i.e., whether the applicant has generation or transmission market power, whether the applicant can erect barriers to entry, and whether there are affiliate abuse or reciprocal dealing concerns), and whether the FERC should adopt different approaches for affiliate transactions. The FERC has held a series of technical conferences to discuss these issues. Additionally, in February 2005, the FERC adopted revised reporting obligations for changes in status that apply to public utilities authorized to make wholesale sales of power at market-based rates. The FERC determined to replace the current triennial reporting requirement with more detailed guidelines concerning the types of events that will trigger a reporting obligation and the timing and format for such reports. The new rules will become part of all existing market-based rate tariffs during March 2005. 123
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Interconnection Orders The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy. In addition, Entergy Louisiana was recently directed, effective as of March 2001, to provide transmission credits, with interest, associated with a specific generator that asserted to the FERC that it retained in its contract for interconnection a right to execute the latest form of Entergy's standard interconnection agreement in lieu of its existing contract, which thereby would apply FERC's most recent interconnection cost allocation policies to that generator. Following an ALUs Initial Decision and an order affirming such decision by FERC, approximately $15 million in expenses and tax obligations previously paid by the generator have been ordered refunded in the form of transmission credits, to be utilized over time and applied to Entergy transmission service bills incurred after March 2001. Entergy has sought rehearing of the FERC's order. To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic; however, especially at the retail level, where the majority of the cost recovery would occur: Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators. Available Flowgate Capacity Proceeding On December 17, 2004, the FERC issued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised: by certain transmission customers and certain issues raised in a FERC audit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination, of (i) Entergy's implementation'of the AFC program, (ii) whether Entergy's implementation has complied'with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discrirninatory. Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues., Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy. Entergy believes that it has complied with the provisions of its open access transmission tariff, including the' provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the AFC proceeding is currently scheduled to commence in August 2005. ' - 124
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy FERC Audits In August 2002, the FERC initiated audits and reviews of Entergy's compliance with Order Nos. 888 and 889 and Entergy's open access transmission tariff. In March 2004, a separate audit was started concerning Entergy's administration of the Generator Operating Limits ("GOL") processes. Entergy responded to numerous FERC data requests and the FERC Staff members interviewed several employees. In December 2004, the FERC issued the GOL audit report in which it identified certain input and modeling errors in the implementation of the GOL process (which process was replaced in April 2004 with the AFC process). The report recommends that Entergy implement additional quality control and assurance procedures surrounding the processes for granting short term transmission service. Separately, the FERC investigation staff has provided to Entergy its preliminary findings in a non-public draft report identifying certain areas of concern related to Entergy's compliance with provisions of its open access transmission tariff. Entergy has submitted a comprehensive response and rebuttal to the specific concerns identified by the investigation staff but, at this point, believes that it has complied with the provisions of its open access transmission tariff. The draft report is not a final report and may be modified by the FERC staff based on Entergy's responses or otherwise. In addition, Entergy has the ability to appeal the final reports to the full FERC. The FERC is currently reviewing certain wholesale sales and purchases involving EPMC that occurred during the 1998-2001 time period. EPMC was an Entergy subsidiary engaged in non-regulated wholesale marketing and trading activities prior to the formation of Entergy-Koch. Entergy is working with the FERC investigation staff to provide information regarding these transactions. Other Customer-initiated Proceedings at FERC In September 2004, East Texas Electric Cooperative (ETEC), filed a complaint at the FERC against Entergy Arkansas relating to a contract dispute over the pricing of substitute energy at the co-owned coal unit, Independence Steam Electric Station (ISES). In October 2004 Arkansas Electric Cooperative (AECC) filed a similar complaint at FERC against Entergy Arkansas, addressing the same issue with respect to ISES and another co-owned coal unit, White Bluff Electric Station. Entergy Arkansas filed answers to these complaints in October 2004 and November 2004. FERC consolidated the cases, ordered a hearing in the consolidated proceeding, and established refund effective dates. The main issue in the case relates to the consequences under the governing contracts when the dispatch of the coal units is constrained due to system operating conditions. Entergy Arkansas believes that the contracts in dispute recognize the effects of dispatch constraints on the co-owned units and require all of the co-owners, including ETEC and AECC, to bear the burden of the reduced output. Entergy Arkansas expects an initial decision by a FERC ALJ in October 2005. On February 17, 2005, ExxonMobil Chemical Company and ExxonMobil Refining & Supply Company (ExxonMobil) filed a complaint with FERC against Entergy Services and the domestic utility companies. The complaint alleges that the Entergy defendants have violated Entergy's open access transmission tariff, as well as its interconnection and operating agreement with ExxonMobil, by not allowing ExxonMobil to net its station power needs at its industrial complex in Baton Rouge, Louisiana. ExxonMobil also alleges that the Entergy defendants have been charging rates that are not on file with the FERC and that the Entergy defendants' monthly facilities charge is contrary to the FERC's current interconnection pricing policy. ExxonMobil states that such violations have resulted in. monetary losses to it in excess of -$5 million. Entergy believes that it has complied with the provisions of its open access transmission tariff and the provisions of the interconnection 'and operating agreement. System Energy and Related Agreements System Energy recovers costs related to its interest in Grand 'Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi; and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In December 1995, System Energy commenced a rate proceeding at the FERC. In July 2001, the rate proceeding became final, with the FERC approving a prospective 10.94% return on equity. The FERC's decision also affected other aspects of System Energy's charges to the domestic utility companies that it supplies with power. In 1998, the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas' 125
Part I Item 1 Entergy Corporation, Domestic utility companies, and System Energy and Entergy Mississippi's acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by FERC. Unit Power Sales Agreement The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy's 90% ownership and leasehold interests in Grand Gulf to Entergy Arkansas (366%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy. New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered, so long as Grand Gulf remains in commercial operation. Payments under the Unit Power Sales Agreement are System Energy's only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers. In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf.. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas' cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans pending regulatory approvals that sell a portion of the output of Entergy Arkansas' retained share of Grand Gulf to those companies. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy Louisiana's share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers, 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC's approval, Availability Agreement The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the financing by System Energy of Grand Gulf. The Availability Agreement provided that System Energy join in the System Agreement on or before the date on which Grand Gulf 1 was placed in commercial operation and make availableto Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy's share of Grand Gulf. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy's total operating expenses for Grand Gulf (including depreciation at a specified rate) and interest charges. The September 1989 write-off of System Energy's investment in Grand Gulf 2, amounting to approximately $900 million, is being amortized for Availability Agreement purposes over 27 years. The allocation percentages under the Availability Agreement are fixed as follows:, Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement. System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its first 126
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy mortgage bonds and reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in, Note 9 to the financial statements under "Sale and Leaseback Transactions - Grand Gulf Lease Obligations." In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they. were prohibited by governmental action from making payments under the Availability Agreement (for example, if FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and- at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances. Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements, The payments must be made pro rata according to the amount of the respective obligations secured. - The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to FERC for approval with respect to the terms of such sale. No such filing with FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to FERC for approval. Other aspects of the Availability Agreement are subject to the jurisdiction of the SEC, whose approval has been obtained, under PUHCA. Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement. Therefore, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations. The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors. Capital Funds Agreement System Energy and Entergy Corporation have entered into the Capital Funds Agreement, whereby Entergy Corporation has agreed to supply System Energy with sufficient capital to (i) maintain System Energy's equity capital at an. amount equal to a minimum of 35% of its total capitalization (excluding short-term debt) and (ii) permit the continued commercial operation of Grand Gulf and pay in full all indebtedness for borrowed money of System Energy when due. Entergy Corporation has entered into various supplements to the Capital Funds Agreement. System Energy has assigned its rights under such supplements asssecurity for its first mortgage bonds and for reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 9 to the financial statements under "Sale and Leaseback Transactions - Grand Gulf Lease Obligations." Each such supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of Grand Gulf may be secured by System Energy's rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as defined below). In addition, in the supplements to the Capital Funds Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital contributions directly to System Energy sufficient to enable 127
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy System Energy to make payments when due on such indebtedness (Specific Payments). However, if there is an event of default, Entergy Corporation must make those payments directly to the holders of indebtedness benefiting from the supplemental agreements. The payments (other than the Specific Payments) must be made pro. rata according to the amount of the respective obligations benefiting from the supplemental agreements. The Capital Funds Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, upon obtaining the consent, if required, of those holders of System Energy's indebtedness then outstanding who have received the assignments of the Capital Funds Agreement. Service Companies Entergy Services, a, corporation wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the domestic utility companies. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the domestic utility companies and System Energy on an "at cost" basis, pursuant to service agreements approved by the SEC under PUHCA. Earnings Ratios of Domestic Utility Companies and System Energy The domestic utility companies' and System Energy's ratios of earnings to fixed charges and ratios of earnings to combined fixed charges and preferred dividends pursuant to Item 503 of SEC Regulation S-K are as follows: Ratios of Earnings to Fixed Charges Years Ended December 31,
'2004 2003 2002 2001 2000
* ' Entergy Arkansas ' 3.37 ' 3.17 - 2.79 3.29 '3.01
- Entergy Gulf States 3.04 1.51 2;49 2.36 '2.60 Entergy Louisiana 3.60 3.93 ' '3.14 2.76 3.33 Entergy Mississippi 3.41 3.06 2.48 2.14 2.33 Entergy New Orleans '3.60 1.73 (b) (c) ' 2.66 System Energy 3.95 3.66 3.25 2.12 2.41 Ratios of Earnings to Combined Fixed Charges and Preferred Dividends Years Ended December 31, 2004 2003 2002 2001 2000 Entergy Arkansas 2.98 2.79 2.53 2.99 2.70 Entergy Gulf States (a) 2.90 1.45 2.40 2.21 2.39 Entergy Louisiana ' 3.16 3.46 2.86 2.51 2.93 Entergy Mississippi 3.07 2.77 2.27 1.96 2.09 Entergy New Orleans 3.31 1.59 (b) (c) 2.43 (a) "Preferred Dividends" in the case of Entergy Gulf States also include dividends on preference stock, which was redeemed in July 2000.
(b) For Eitergy New Orleans, earnings for the twelve'months ended December 31, 2002 were not adequate to cover fixed charges and combined fixed charges and preferred dividends by $0.7 million and $3.4 million, respectively. (c) For Entergy New Orleans, earnings for the twelve months ended December 31, 2001 were not adequate to cover fixed charges and combined fixed charges and preferred dividends by $6.6 million and $9.5 million, respectively. 128
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Non-Utility Nuclear Entergy's Non-Utility Nuclear business owns and operates five nuclear power plants and is primarily focused on selling electric power produced by those plants to wholesale customers. This business also provides operations and management services to nuclear power plants owned by other utilities in the United States. Operations and management services, including decommissioning services, are provided through Entergy's wholly-owned subsidiary, Entergy Nuclear, Inc. Property Generating Stations Entergy's Non-Utility Nuclear business owns the following nuclear power plants: License. Maximum Expiration Power Plant Acquired Location Capacity Reactor Type Date Pilgrim July 1999 Plymouth, MA 688 MW Boiling Water Reactor 2012. FitzPatrick Nov. 2000 Oswego, NY 838 MW Boiling Water Reactor 2014 Indian Point 3 Nov. 2000 Westchester 994 MW Pressurized Water Reactor 2015 County, NY Indian Point 2 Sept. 2001 Westchester 1,028 MW Pressurized Water Reactor 2013 County, NY Vermont Yankee July 2002 Vernon, VT 510 MW Boiling Water Reactor 2012 Non-Utility Nuclear added 57 MW of capacity in 2004 through uprates and plans an additional 142 MW of uprates through 2006. The planned uprates include a total of 95 MW for Vermont Yankee that are currently pending approval by the NRC and the Public Service Board of Vermont. Interconnections The Pilgrim and Vermont Yankee plants are dispatched as a part of Independent System Operator (ISO) New England and the FitzPatrick and Indian Point plants are dispatched by the New York Independent System Operator (NYISO). The primary purpose of ISO New England is to direct the operations of the major generation and transmission facilities in the New England region and the primary purpose of NYISO is to direct the operations of the major generation and transmission facilities in New York state. Energy and Capacity Sales Entergy's Non-Utility Nuclear business has entered into power purchase agreements (PPAs) with creditworthy counterparties to sell the energy produced by its power plants at prices established in the PPAs. Entergy continues to pursue opportunities to extend the existing PPAs and to enter into new PPAs with other parties. Following is a summary of the amount of the Non-Utility Nuclear business' output that is currently sold forward under physical or financial contracts at fixed prices: 2005 2006 2007 2008 2009 Non-Utility Nuclear: Percent of planned generation sold forward: Unit-contingent 36% 20% 17% 1% 0% Unit-contingent with availability guarantees 54% 52% 38% 25% 0% Firm liquidated damages 4% 4% 2% 0%, 0% Total 94% 76% 57% 26% 0% Planned generation (TWh) 34 35 34 34 35 Average contracted price per MWh $39 $41 $42 $44 N/A 129
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy The Vermont Yankee acquisition included a 10-year PPA under which the former owners will buy the power produced by the plant, which is through the expiration in 2012 of the current operating license for the plant. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward monthly, beginning in November 2005, if power market prices drop below PPA prices. Accordingly, because the price is not fixed, the table above does not report power from that plant as sold forward after November 2005. A sale of power on a unit contingent basis coupled with an availability guarantee provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. To date, Entergy has not incurred any payment obligation to any power purchaser pursuant to an availability guarantee. All of Entergy's outstanding availability guarantees provide for dollar limits on Entergy's maximum liability under such guarantees. Some of the agreements to sell the power produced by Entergy's Non-Utility Nuclear power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The'Entergy subsidiary may be required to provide collateral based upon the difference between the current market and contracted power prices in the regions where the Non-Utility Nuclear business sells its power. The primary form of the collateral to satisfy these requirements would be an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral.' At December 31, 2004, based on power prices at that time, Entergy had in place as collateral $545.5 million of Entergy Corporation guarantees and $47.5 million of letters of credit. In the event of a decrease in Entergy Corporation's credit-rating to specified levels below investment grade, Entergy may be required to replace Entergy Corporation guarantees with cash or letters of credit under some of the agreements. + . - In addition to selling the power produced by its plants, the Non-Utility Nuclear business sells installed capacity to load-serving distribution companies in order for those companies to meet requirements placed on them by the ISO in their area. Following is; a summary of the amount of the Non-Utility Nuclear business' installed capacity that is currently sold forward, and the blended amount of the Non-Utility Nuclear business' planned generation output and installed capacity that is currently sold forward: ' - - 2005 2006 2007 2008, 2009 Non-Utility Nuclear: Percent of capacity sold forward: - ; Bundled capacity and energy contracts .;- 13% 13% 13% 13% 13% Capacity contracts 58% 67% 36% 22% 10%; Total- - 71% 80% 49%
- 35% ! 23%
Planned net MW in operation 4,155 4,200 4,200 4,200 4,200 Average capacity contract price per kW per month $1.2 $1.1 $1.1 $1.0 $0.9 Blended Capacity and Energy (based on revenues) % of planned generation and capacity sold forward 93% 87% 65% 36% 12% Average contract revenue per MWh - $40 $42 $43 $44- $43 As of December 31, 2004, approximately 99% of Entergy's countetparties to Non-Utility Nuclear's energy and capacity contracts have investment grade credit ratings. Fuel Supply Nuclear Fuel The nuclear fuel requirements for Pilgrim, FitzPatrick, Indian Point 2, Indian Point 3, and Vermont Yankee are met pursuant to contracts made by Entergy's Non-Utility Nuclear business. Entergy Nuclear Fuels Company is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for these non-utility nuclear plants. ! 130
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Based upon currently planned fuel cycles, Entergy's nuclear units have contracts and inventory that provide adequate materials and services. Existing contracts for uranium concentrate, conversion of the concentrate to uranium hexafluoride, and enrichment of the uranium hexafluoride will provide a significant percentage of these materials and services over the next several years. Uranium market supply became much tighter in recent years. Costs and risks of obtaining supplies have increased for nuclear fuel users. It will be necessary for Entergy to enter into additional arrangements to acquire nuclear fuel in the future. It is not possible to predict the ultimate cost or availability of such arrangements. Other Business Activities Entergy Nuclear, Inc. also pursues service agreements with other nuclear power plants owners who seek the advantages of Entergy's scale and expertise but do not necessarily want to sell their assets. Services provided by either Entergy Nuclear, Inc. or other Non-Utility Nuclear subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities. Entergy Nuclear, Inc. currently provides decommissioning services for the Maine Yankee nuclear power plant and continues to pursue opportunities for Non-Utility Nuclear with other nuclear plant owners through operating agreements or innovative arrangements such as structured leases. In September 2003, Entergy's Non-Utility Nuclear business agreed to provide administrative support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. The contract is for 10 years, the remaining term of the plant's operating license. Entergy will receive $13 million in 2005, and $14 million in 2006 and each of the remaining years of the contract. Entergy can also receive up to $6 million more per year beginning in 2007 if safety and regulatory goals are met. In addition, Entergy will be reimbursed for all employee-related expenses. Entergy Nuclear, Inc. also is a party to two business arrangements that assist Entergy Nuclear, Inc. in providing operation and management services. Entergy Nuclear, Inc., in partnership with Framatome ANP, offers operating license renewal and life extension services to nuclear power plants in the United States. Entergy Nuclear Inc., through its subsidiary, TLG Services, offers decommissioning, engineering, and related services to nuclear power plant owners. Energv Commodity Services The Energy Commodity Services segment includes Entergy's non-nuclear wholesale assets business and Entergy-Koch, LP. Entergy's non-nuclear wholesale assets business owns power plants capable of generating about 1,500 MW of electricity for sale in the wholesale market. Entergy-Koch, LP is a limited partnership owned 50% each by Entergy and Koch Industries, Inc. through subsidiaries. Entergy-Koch engaged in two major businesses: energy commodity marketing and trading through Entergy-Koch Trading, and gas transportation and storage through Gulf South Pipeline. Entergy-Koch sold both of these businesses in the fourth quarter 2004, and Entergy-Koch is no longer an operating entity. Previously, Entergy's Energy Commodity Services business also engaged in power development activities through Entergy Wholesale Operations, but these activities were discontinued in early 2002. 131
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Non-Nuclear Wholesale Assets Business Property Generating Stations The capacity of the generating stations owned in Entergy's non-nuclear wholesaje assets business as of December 31, 2004 is indicated below: Net Owned Plant Location Ownership Capacity(1) Type Ritchie Unit 2, 544 MW Helena, AR 100% 544 MW Gas/Oil Independence Unit 2, 842 MW Newark, AR 14% 121 MW(2) Coal Warren Power, 300 MW Vicksburg, MS i 75% 225 MW(2) Gas Turbine Top of Iowa, 80 MW (3) Worth County, IA 50% 40 MW Wind, White Deer, 80 MW (3) Amarillo, TX 50% 40 MW Wind RS Cogen, 425 MW (3) Lake Charles, LA 50% 213 MW Gas/Steam Harrison County, 550 MW Marshall, TX 61% 335 MW(2) Gas Turbine (1) "Net Owned Capacity" refers to the nameplate rating on the generating unit. (2) The owned MW capacity is the portion of the plant capacity owned by Entergy's non-nuclear wholesale assets business. For a complete listing of Entergy's joint-owned generating stations, refer to "Jointlv-Owned Generating Stations" in Note 1 to the consolidated financial statements. (3) Indirectly owned through interests in unconsolidated joint ventures. In addition to these generating stations, Entergy's non-nuclear wholesale assets business has a contract to take 60MW of the power from a portion of the Nelson 6 coal plant owned by a third party. Entergy sold its interest in the Crete power plant located in Illinois in January 2004., Energy and Capacity Sales Following is a summary of the amount of Energy Commodity Services' output and installed capacity that is currently sold forward under physical or financial contracts at fixed prices: 5 26 27 . .28 0 2005 2006 2007, 2008 -2009. Energy Commodity Services: Capacity Planned MW in operation 1,578 1,578 1,578 1,578 ; 1,578
% of capacity sold forward 44% 330/0 29% 29% ;19%,
Energy Planned generation (TWh) 3 3 3 3 4
% of planned generation sold forward 69% 54% 45% 45% 35%
Blended Capacity and Energy (based on revenues)
% of planned energy and capacity sold forward 63% 44% 38% 39% 22%
Average contract revenue per MWh $24 $24 $28 $28 $21 Entergy-Koch, LP Entergy-Koch is a limited partnership owned 50% each by Entergy and Koch Industries, Inc, through subsidiaries. Entergy-Koch began operations on February 1, 2001. Entergy contributed most of the assets and trading contracts of its power marketing and trading business and $414 million cash to the venture and Koch contributed its approximately 8,000-mile Koch Gateway Pipeline (renamed Gulf South Pipeline), gas storage facilities, and Koch Energy Trading, which marketed and traded electricity, gas, weather derivatives, and other 132
Part I Item 1 Entergy Corporation, Domestic utility companies, and System Energy energy-related commodities and services. As specified in the partnership agreement, Entergy contributed an additional $72.7 million to the partnership in January 2004. In the fourth quarter of 2004, Entergy-Koch sold its energy trading and pipeline businesses to third parties. The sales came after a review of strategic alternatives for enhancing the value of Entergy-Koch, LP. Entergy received $862 million of cash distributions in 2004 from Entergy-Koch after the business sales, and Entergy ultimately expects to receive total net cash distributions exceeding $1 billion, comprised of the after-tax cash from the distributions of the sales proceeds and the eventual liquidation of Entergy-Koch. Entergy currently expects the net cash distributions that it will receive will exceed its equity investment in Entergy-Koch, and expects to record a $60 million net-of-tax gain when it receives the remaining cash distributions, which it expects will occur in 2006. Regulation of Enteray's Business PUHCA The Public Utility Holding Company Act of 1935, as amended, regulates companies like Entergy Corporation that serve as holding companies to, domestic operating utilities. Some of the more significant impacts of PUHCA are that it:
- limits the operations of a registered holding company system to a single, integrated public utility, system, plus related systems and businesses;
- regulates transactions among affiliates within a holding company system;
- governs the issuance, acquisition, and disposition of securities and assets by registered holding companies and their subsidiaries;
- limits the entry by registered holding companies and their subsidiaries into businesses other than electric and/or gas utility businesses; and
- requires SEC approval for certain utility mergers and acquisitions.
Entergy continues to support the broad industry effort to pass legislation in the United States Congress to repeal PUHCA and transfer certain aspects of the oversight of public utility holding companies from the SEC to FERC. Entergy believes that PUHCA inhibits its ability to compete in the evolving electric energy marketplace and largely duplicates the oversight activities otherwise performed by FERC, other federal regulators, and state and local regulators. Federal Power Act The Federal Power Act regulates:
- the transmission and wholesale sale of electric energy in interstate commerce;
- the licensing of certain hydroelectric projects; and
- certain other activities, including accounting policies and practices of electric and gas utilities.
The Federal Power Act gives FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over some of the rates charged by Entergy Arkansas and Entergy Gulf States. FERC also, regulates the rates charged for intrasystem sales pursuant to the System Agreement. Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity. 133
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy State Regulation Entergy Arkansas is subject to regulation by the APSC, which includes the authority to:
- oversee utility service;
- set retail rates;
- determine reasonable and adequate service;
- require. proper accounting;
- control leasing;
- control the acquisition or sale of any public utility plant or property constituting' an operating unit or' system;
- set rates of depreciation;
- issue certificates of convenience and necessity and certificates of environmental compatibility and public need; and
- regulate the issuance and sale of certain securities.
Entergy Gulf States may be subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Whether such municipal jurisdiction currently exists is the subject of a declaratory judgment proceeding initiated at the PUCT by certain Cities served by Entergy Gulf States in December 2004. Entergy Gulf States' Texas business is also subject to regulation by the PUCT as to:
- retail rates and service;
- customer service standards; '
- certification' of new'transmission lines; and '
- extensions of service into new areas.
Entergy Gulf States' Louisiana electric and gas business and Entergy Louisiana are subject to regulation by the LPSC as to:
' utility service;'
- retail rates and charges; '
- certification of generating facilities;
- power or capacity purchase contracts; and
- depreciation, accounting, and other matters.
Entergy Louisiana is also subject to the jurisdiction of the Council with respect to such matters within Algiers in Orleans Parish. Entergy Mississippi is subject to regulation by the MPSC as to the following:
- utility service;,
- service areas;
- facilities; and
- retail rates.
Entergy Mississippi is also subject to regulation by the APSC as to, the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas. Entergy New Orleans is subject to regulation by the Council as to the following:
- utility service;
- retail rates and charges; 134
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy
- standards of service;
- depreciation, accounting, and issuance and sale of certain securities; and
- other matters.
Regulation of the Nuclear Power Industry Atomic Energy Act of 1954 and Energy Reorganization Act of 1974 Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend, Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy has made substantial capital expenditures at these nuclear plants because of revised safety requirements of the NRC in the past, and additional expenditures could be required in the future. Entergy's Non-Utility Nuclear business is subject to the NRC's jurisdiction as the owner and operator of Pilgrim, Indian Point Energy Center, FitzPatrick, and Vermont Yankee. Substantial capital expenditures at these nuclear plants because of revised safety requirements of the NRC could be required in the future. Nuclear Waste Policy Act of 1982 Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for,: and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy's nuclear owner/licensee subsidiaries provide for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE will furnish disposal service at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December31, 2004 of $156.3 million for the one-time fee. Entergy's Non-Utility Nuclear business has accepted assignment of the Pilgrim, FitzPatrick, Indian Point 3, Indian Point 2, and Vermont Yankee spent fuel disposal contracts with the DOE held by their previous owners. The previous owners have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the U.S. Utility plants. The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE will now' proceed with the licensing and, if the license is granted by the NRC, eventual construction of the repository will begin-and receipt of spent fuel may begin sometime after 2010. Considerable uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy's facilities for storage or disposal. As a result, future expenditures will be required to increase spent fuel storage capacity at Entergy's nuclear plant sites. As a result of the DOE's failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy's nuclear owner/licensee subsidiaries have incurred and will continue to incur damages.; These subsidiaries in November 2003 began litigation to recover the damages caused by the DOE's delay in performance. Management cannot predict the timing or amount of any potential recovery. Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are responsible for their own spent fuel storage. Current on-site spent fuel storage capacity at Grand Gulf 1, River Bend, and Waterford is estimated to be sufficient until approximately 2007, 2006, and 2012, respectively; dry cask storage facilities are planned to be placed into service at these units in 2007, 2005, and 2011, respectively. An ANO storage facility using dry casks began operation in 1996 and has been expanded since and will be further expanded 135
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy as needed. The spent fuel storage facility at Pilgrim is licensed to provide enough storage capacity until approximately 2012. The first dry spent fuel storage casks wete loaded at Fitzpatrick in 2002, and further casks will be loaded there as needed. Indian Point and Vermont Yankee currently have sufficient spent fuel storage capacity until approximately 2006 and 2007, respectively; dry cask storage facilities are planned to begin operation at both sites in 2006. Implementation of dry cask storage at Vermont Yankee is currently the subject of pending legislative and regulatory proceedings in Vermont. Nuclear Plant Decommissioning
*-Jo, ,U t ' i *w A w)>lj ' i v e . '. > ; i Ut e Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy recover from customets through electric rates the estimated decommissioning costs for ANO, the portion of River Bend subject to retail rate regulation, Waterford 3, and Grand Gulf, respectively. These amounts are deposited in trust funds that can only be used for future decommissioning costs. Entergy periodically reviews and updates estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs. - .
In June 2001, Entergy Arkansas received notification from the NRC of approval for a renewed operating license authorizing operations at ANO 1 through May 2034. In October 2003, a request was filed with the NRC to extend the operating license of ANO 2 for an additional 20 years. The APSC ordered Entergy Arkansas to use a 20-year life extension assumption for ANO 1 and 2, which resulted in the cessation of the collection of funds to decommission ANO 1 and 2 beginning in 2001. Entergy Arkansas' projections show that with the assumption of 20 years of extended operational life for both units, the current fund balance with earnings over the extended life will be sufficient to decommission both units. Every five years, Entergy Arkansas is required by the APSC to update the estimated costs to decommission ANO. In March 2003, Entergy Arkansas filed with the APSC its third five-year estimate of ANO decommissioning costs. The updated estimate- indicated the current cost to decommission the two ANO units would be, $936 million compared to $813 million in the 1997 estimate. In September 2003, the APSC approved a stipulation, between the APSC Staff andEntergy Arkansas resolving issues in the decommissioning cost estimate proceeding. Entergy Arkansas and the APSC Staff agreed to exclude, at this time, certain spent fuel management costs because of uncertainty associated with the responsibility of the DOE for all or a portion of those costs as a result of Entergy Arkansas' contract with the DOE to start taking spent fuel from ANO beginning in 1998. Entergy Arkansas reserves the right.to seek a decision from the APSC on this issue prior to the next required decommissioning cost filing should significant changes in relevant facts and circumstances warrant. In December 2002, the LPSC approved a settlement between Entergy Gulf States and the LPSC staff. The settlement included, among other things, the approval to cease collection of funds to decommission River Bend based on an assumed license extension for River Bend. t . , . .. *- 1' ',,J.-fl3 1 riJ
Žj As part of the Pilgrim, Indian Point 1 and 2, and Vermont Yankee purchases, Boston Edison, Consolidated Edison, and VYNPC, respectively, transferred decommissioning trust funds, along -with the liability to decommission the plants, to Entergy. Entergy believes that the decommissioning trust funds will be adequate to cover future decommissioning costs for these plants without any additional deposits to the trusts. wi :.f ; t it U-,!i For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liability. NYPA and Entergy executed decommissioning agreements, which specify their decommissioning obligations. NYPA has the right to require.Entergy to assume the decommissioning liability provided that it assigns the corresponding decommissioning trust, up to a specified level, to Entergy. If the decommissioning liability is retained by NYPA, Entergy will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. Entergy believes that the amounts available to it under either scenario are sufficient to cover the future decommissioning costs without any additional contributions to the trusts. In conjunction with the Pilgrim acquisition, Entergy received Pilgrim's decommissioning trust fund. Entergy believes that Pilgrim's decommissioning fund will be adequate to cover future decommissioning costs for the plant without any additional deposits to the trust. As part of the Indian Point 1 and 2 purchase, Consolidated Edison transferred the decommissioning trust fund and the liability 'to decommission Indian Point 1 and 2 to Entergy. Entergy also funded an additional $25 million to the decommissioning trust fund and believes that the trust will be adequate to cover future decommissioning costs for 136
Part I Item 1 Entergy Corporation, Domestic utility companies, and System Energy Indian Point 1 and 2 without any additional deposits to the trust. uJ j II JLi ! i: i0 i/) i i jlJ.)I iL J 1..81 f o I :iii ; ? J. .. .:i 3 J i0f)i; i1'- ,-Ui Ij,I ; i ',IC I 10.. 3 U'ii Additional information with respect to decommissioning costs for ANO, River Bend, Waterford 3, Grand Gulf, Pilgrim, Indian Point 1, Indian Point 2, Indian Point 3, and FitzPatrick is found in Note 8 to the financial statements. .. a iIS 3i ' .- litub i ._a - Du'fl
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- f njyj;ijr; :iiiti The Energy Policy Act of 1992 requires all electric utilities (including Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy) that purchased uranium enrichment services from the DOE to contribute up to a total of $150 million annually over approximately 15 'years (adjusted for inflation, up to a total of
$2.25 billion) for decontamination and decommissioning of enrichment facilities. At December 31, 2004, two years of assessments remain. In accordance with the Energy Policy Act of 1992, contributions to decontamination and decommissioning funds are recovered through rates in the same nWamner-as other fuel costs. The estimated annual contributions by Entergy for decontamination and decommissioning fees are discussed in, Note 8 to the financial statements. Entergy will oppose any 'attempts to extend the assessments past this date, but cannot state with certainty that an extension will not be made. * - a.' ' . 'iiI 1 4i Price-Anderson Act - Ati
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The Price-Anderson Act limits public liability for a single nuclear incident to approximately $100.6 million per reactor (with currently 104 nuclear industry reactors participating). 'Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy, and Entergy's Non-Utility Nuclear business have protection with respect to this liability through a combination of private insurance and an industry assessment program, as well as insurance for property damage, costs of replacement power, and other risks relating to "nuclear generating units. Insurance applicable to the nuclear programs of Entergy is discussed in Note 8 to the financial statements. . Environmental Regulation ;.--t ? 'i'r3 1fi50 1sJ..Jlotir fl to ncV-trii~$, :. PJ JI I '3ZTi 'J'Ajkt Lif}Z1
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'.w.i..Entergy's facilities and operations are' subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances 'and hazardous and solid wastes, and other environmental matters. Management believes that its affected companies are in substantial compliance with environmental regulations currently applicable to their facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
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The Clean Air Act and its subsequent Amendments (the Clean Air Act) established several programs that currently or in the future may affect Entergy's fossil-fueled generation facilities:
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- New source review and preconstruction permits for new sources -of criteria air pollutants and significant modifications to existing facilities; i Acid rain program for control of sulfur dioxide (SO 2 ) and nitrogeni oxides (NO,); *i 3.. 3.
- OZone noh-attainmnt -drea'pMgfdram for control of NO, 'aid volatile organic conipounds; ta
" Hazardous 6iitaiiis'sioreduction program}p;i A l A i'.'K
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r for administration and enforceittW a'and other Clean Air Ac programs. New Source Review " ,' ' "' . Preconstruction permits are required for new facilities and for existing facilities that inderg6'a rnodification that is not classified as routine repair, maintenance, or replacement. Units that undergo a non-routine modification must obtain a perini miodicatin6i! and miay le required 'to insital adlitiinal air pollution cl6htrol technologies. Entergy has an 6ikstAid'p~toceds for iientifying ffi additionial permitting approval and as followed the"e ieuatlds'aiN'd as-sociated guidnce pv6~ideddby'the'fii teVsaiind the federal govenhiletf with reard to 137
Part I Item 1 Entergy Corporation, Domestic utility companies, and System Energy the determination of routine repair, maintenance, and replacement. In recent years, however, EPA has begun an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine and that have failed to obtain a permit modification. Entergy to date has not been included in any of these enforcement actions. Nevertheless, various courts and EPA have been inconsistent in their judgments regarding what modifications are considered routine. In 2003, EPA promulgated a rule to attempt to clarify this issue, but the rule has been challenged in the United States Court of Appeals for the District of Columbia Circuit, and its effectiveness has been stayed by the court. In June 2004, EPA granted a request to reconsider certain aspects of the rule. Acid Rain Program The Clean Air Act provides SO2 allowances to most of the affected Entergy generating units for emissions based upon past emission levels and operating characteristics. Each allowance is an entitlement to emit one ton of SO2 per year. Plant owners are required to possess allowances for SO2 emissions from affected generating units. Virtually all Entergy fossil-fueled generating units are subject to SO2 allowance requirements. Entergy could be required to purchase additional allowances when it generates power using fuel oil. Fuel oil usage is determined by economic dispatch and influenced by the price of natural gas, incremental emission allowance costs, and the availability and cost of purchased power. Ozone Non-attainment Entergy Gulf States and Entergy Louisiana each operate fossil-fueled generating units in geographic areas that are not in attainment of the currently-enforced national ambient air quality standards for ozone. Texas non-attainment areas that impact Entergy are the Houston-Galveston and the Beaumont-Port Arthur areas. In Louisiana, Entergy is affected by the non-attainment status of the Baton Rouge area. Areas in non-attainment are classified as "moderate," "serious," or "severe." When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards. Texas and Louisiana submitted plans for the Beaumont-Port Arthur and Baton Rouge areas that included an extension of the regulatory deadline to gain attainment. The EPA initially approved these plans and the deadline extensions, but through litigation and a decision of the United States Court of Appeals for the Fifth Circuit in December 2002, the approval of the state plans has been withdrawn as violating provisions and deadlines required by the Clean Air Act. The EPA has now reclassified the Beaumont-Port Arthur area from "moderate" to "serious" and has reclassified the Baton Rouge area from "serious" to "severe". These actions will require that Texas and Louisiana adopt plans to restrict the emission of certain air pollutants and to make progress toward eventual attainment of national standards. Texas adopted and forwarded to the EPA for approval revisions to the state implementation plan in December 2004. Based on this submittal, Entergy Gulf States believes that new NO, control equipment will not be required at the Beaumont-Port Arthur area facilities. The Louisiana plan revisions were due in June 2004; however, due to legal and regulatory disputes over requirements unrelated to Entergy's interests, the state has chosen to delay the submittal. The final content and effect on Entergy of these developing plans is unknown, but Entergy continues to monitor events in these areas. In April 2004, EPA issued a final rule, effective June 2005, stating that areas designated as non-attainment under a new 8-hour ozone standard shall have one year to adjust to the new requirements. For Louisiana, the Baton Rouge area would be classified as a "marginal" (rather than "severe") non-attainment area under the new standard with an attainment date of June 2007. For Texas, the BeaumontlPort Arthur area would be designated as a "marginal" (rather than "serious") non-attainment area under the new standard with an attainment date of June 2007 and the Houston-Galveston area would be designated as "moderate" non-attainment under the new standard with an attainment date of June 2010. Hazardous Air Pollutants In December 2000, the EPA made a determination that coal and oil-fired steam electric generating units should be regulated under the section of the Clean Air Act relating to, emissions of hazardous air pollutants (HAPs). The principal HAPs of concern are mercury from coal and nickel from oil. The EPA has proposed regulations for 138
Part I Item I Entergy Corporation, Domestic utility companies,,and System,Energy these sources and initially set a deadline of December 2004 for finalizing the rules. Entergy owns units that would be subject to these regulations. The EPA has since postponed finalization of mercury and nickel HAPs regulations until the second quarter of 2005. The regulations may require coal and oil-fired units to reduce mercury and nickel emissions through various methods, including installation of controls, switching fuels or fuel suppliers, reducing utilization of unity, or some combination of these methods. The earliest expected compliance date for this rule would be 2007, and Entergy could begin to incur costs of compliance as early as 2006 with the work taking up to three years to complete. These costs should be offset by advances in control technology or through the implementation.-of proposed cap and trade provisions which are not final at this time. Interstate Air Transport In January 2004, the EPA proposed the Interstate Air Quality Rule, renamed the Clean Air Interstate Rule (CAIR), which intends to reduce S02 and NO, emissions from plants in order to improve air quality in the northeastern United States. The EPA has postponed issuing a final rule until the second quarter of,2005. The rule has the potential to require significant pollution control capital and/or operating costs (including any potential impacts to the value of SO2 allowances). Entergy's capital investment and annual operation and maintenance allowance purchase costs will depend on the economic assessment of NO. and S02 allowance markets, cost of control technologies, and unit usage as well as other uncertainties described below. The capital financial impact could be offset by proposed emission markets which would allow operation and maintenance purchases or use of allocated credits; however, the allocation of the emission allowances and the set up of the market will determine the ultimate cost to Entergy. Entergy is concerned that the allocation may be unfairly skewed towards states with relatively higher emissions. Entergy will continue to study the proposed rule's impact to its generation fleet and will work to ensure that all states are treated fairly in the allocation of emission credits. i In May 2004, the EPA re-proposed the Best Retrofit Control Technology (BART) regulations which could potentially result in a requirement to install S02 pollution control technology on certain of Entergy's coal and. oil generation units. The impact of this proposed rule is unclear, but could result in significant increased capital and operating costs on certain units: Future Legislative and Regulatory Developments In addition to the specific-instances described above, there are a number of legislative and- regulatory initiatives relating to the reduction of emissions that are under consideration at the federal, state, and international level. Because of the nature of Entergy's business, the adoption of each of these could affect its operations.;- These initiatives include:
- designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
- EPA initiatives related to regional haze;
- introduction of several bills in Congress proposing firther limits on NOR, SO2 , mercury, or limits on carbon dioxide (CO2) emissions; and
- pursuit by the Bush administration of a voluntary program intended to reduce C02 emissions.
Entergy continues to monitor these actions in order to analyze their potential operational and cost implications. In anticipation of the potential imposition of CO2 emission limits on the electric industry in the future, Entergy has initiated actions designed to reduce its exposure to potential new governmental requirements related to C0 2 emissions. These actions include establishment of a formal program to stabilize power plant CO2 emissions at year 2000 levels through 2005 and support for national legislation that would increase planning certainty for electric utilities while addressing emissions in a, responsible and flexible manner. iBy virtue of its proportionally large investment in low or non-emitting gas-fired and nuclear generation technologies, Entergy's overall C02 emission "intensity," or rate of C02 emitted per kilowatt-hour of electricity generated, is already among 139
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy the lowest in the industry. Total CO2 emissions representing the company's ownership share of power plants in the United States were approximately 53.24 million tons in 2000, 49.58 million tons in 2001, 44.20 million tons in 2002, 36.78 million tons in 2003, and 38.28 million tons in 2004. Clean Water Act The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act or CWA) provide the statutory basis for the National Pollutant Discharge Elimination System (NPDES) permit program and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The CWA requires all discharges of pollutants to waters of the United States to be permitted. 316(b) Cooling Water Intake Structures The EPA finalized new regulations in July 2004.governing the intake of water at large existing power plants that employ cooling water intake structures. The rule seeks to reduce perceived impacts on aquatic resources by requiring covered facilities to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic impacts. Entergy, other industry members and industry groups, environmental groups, and a coalition of northeastern and mid-Atlantic states have challenged various aspects of the rule. This challenge currently is lodged in the United States Court of Appeals for the Second Circuit in New York City after a motion to transfer from the Ninth Circuit in San Francisco was granted in December 2004. Entergy's non-utility nuclear generation business is currently in various stages of the data evaluation and discharge permitting process for its generation facilities. Indian Point is involved in an administrative permitting process with the New York environmental authority for renewal of the Indian Point 2 and 3 discharge permits. In November 2003, the New York State Department of Environmental Conservation (NYDEC) issued a draft permit indicating that closed cycle cooling would be considered the "best technology available" for minimizing perceived adverse environmental impacts attributable to the intake and discharge of cooling water at Indian Point 2 and 3. The draft permit would require Entergy to take certain steps to assess the feasibility of retrofitting the site to install cooling towers before re-licensing Indian Point 2 and 3, whose current licenses with the NRC 'expire in 2013 and 2015. The draft permit could also require, upon its becoming effective, the facilities to take an annual 42' unit-day outage and provide a payment into a NYDEC account until the start of cooling tower construction. Entergy is participating in the administrative process in order to have the draft permit modified prior to final issuance and opposes any requirement to install cooling towers or to begin annual outages at Indian Point 2 and 3. Accordingly, Entergy also has filed a separate action in New York state court seeking a determination that the state cooling water intake structure regulation underpinning the NYDEC's draft permit for Indian Point 2 and 3 was improperly promulgated and is thus void. The New York trial court dismissed Entergy's claim, and Entergy has appealed to the New York Court of Appeals. Pilgrim received approval from EPA allowing the full 3 1/2-year schedule for compliance demonstration as is outlined in the new rule and will also pursue appropriate supplementation of the existing record regarding perceived impacts, options and costs. Entergy's other Non-Utility Nuclear generation facilities are in the process of reviewing data, considering implementation options, providing information required by the current rule to EPA and the affected states, and requesting the 3 1/2-year submission schedule allowed by the rule, where necessary. Oil Pollution Prevention Regulation The EPA published a revised Oil Pollution Prevention rule in July 2002., The rule affects Entergy's operation of its approximately 3,500 transmission and distribution electrical equipment installations that are potentially subject to the rule. While the published rule provides a great deal of flexibility to the regulated community insofar as allowable strategies, it also provided the EPA with a great deal of discretion in evaluation of a facility's compliance with the rule. In September 2004, EPA solicited comments on alternative management strategies for oil-filled electrical equipment that were proposed by the Utility Solid Waste Activities Group and Entergy. Entergy is currently in the final stages of revising existing Integrated Response Plans and Spill Prevention, Control and Countermeasures Plans to meet the requirements of the rule and does not expect significant compliance costs. 140
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Comprehensive Environmental Response. Compensation. and Liability Act of 1980 The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA and, indirectly, the states, to mandate clean-up, or reimbursement of clean-up costs, by owners or operators of sites from which hazardous substances may be or have been released. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. -CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. The domestic utility companies have sent waste materials to various disposal sites over the years. In addition, environmental laws now regulate certain of the companies' operating procedures and maintenance practices which historically were not subject to regulation. Some disposal sites used by Entergy have been the subject of governmental action under CERCLA, resulting in site clean-up activities. The domestic utility companies have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected companies have established reserves for such environmental clean-up and restoration activities. Details of material CERCLA liabilities are discussed for each operating company in the "Other Environmental Matters" section below. Other Environmental Matters Entergy Gulf States Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Gulf States and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Gulf States' premises (see "Litigation" below). Entergy Gulf States is currently involved in a remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, was apparently routed to a portion of the property for disposal. The same area has also been used as a landfill. In 1999, Entergy Gulf States signed a second Administrative Consent Order with the EPA to perform removal action at the site. In 2002, approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. In 2003, a cap was constructed over the remedial area to prevent the migration of contamination to the surface. Entergy Gulf States anticipates commencement of a ten-year groundwater monitoring study upon issuance of a negotiated order by the EPA, which is expected to issue the order in early 2005. Entergy Gulf States believes that its ultimate responsibility for this site will not materially exceed its existing clean-up provision of$1.5 million. In 1994, Entergy Gulf States performed a site assessment in conjunction with a construction project at the Louisiana Station Generating Plant (Louisiana Station). In 1995, a further assessment confirmed subsurface soil and groundwater impact to three areas on the plant site. After validation, a notification was made to the LDEQ and a phased process was executed to remediate each area of concern. The final phase of groundwater clean-up and monitoring at Louisiana Station is expected to continue through 2005. The remediation cost incurred through December 31, 2004 for this site was $6.7 million. Future costs are not expected to exceed the existing provision of
$0.8 million.
Entergy Louisiana and Entergy New Orleans Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Louisiana and Entergy New Orleans and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Louisiana's and Entergy New Orleans' premises (see "Litigation" below). The Southern Transformer Shop located in New Orleans served both Entergy Louisiana and Entergy New Orleans. This transformer shop is now closed and soil and groundwater assessment activities have resumed since the demolition of the onsite buildings and structures was completed in early 2004. Entergy has entered into the Voluntary Remediation Program with the LDEQ and submitted a Site Investigation Workplan. A liability of 141
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy approximately $350,000 has been established for environmental assessment and remediation costs with estimated completion by the end of 2005. During 1993, the LDEQ issued new rules for solid waste regulation, including regulation of wastewater impoundments. Entergy Louisiana and Entergy New Orleans have determined that certain of their power plant wastewater impoundments were affected by these regulations and chose to remediate and repair or close them. Completion of this work is pending LDEQ approval. LDEQ has issued notices of deficiencies for certain of these sites. As a result, recorded liabilities in the amounts of $5.8 million for Entergy Louisiana and $0.5 million for Entergy New Orleans existed at December 31, 2004 for wastewater remediation and repairs and closures. Management of Entergy Louisiana and Entergy New Orleans believes these reserves are adequate based on current estimates. Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana The Texas Commission on Environmental Quality (Commission) notified Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana in September through November 2003 that the Commission believes those entities are potentially responsible parties (PRPs) concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination exists at the site. Entergy Gulf States and Entergy Louisiana sent transformers to this facility during the 1980s. There has been no indication that Entergy Arkansas ever used this facility. Entergy Gulf States, Entergy Louisiana, and Entergy Arkansas have responded to an information request from the Commission and will continue to cooperate in this investigation. It, is likely that Entergy Gulf States and Entergy Louisiana will be required to contribute to the remediation of contaminated groundwater at the site, but the contributions likely will be less than those of other SESCO customers that continued to use the site long after 1990, and the list of PRPs who likely will share in the cost is long. Based on current information, the estimate of Entergy's portion of the liability is $0.6 million. Entergy New Orleans In March 2004, agents of the United States Fish and Wildlife Service conducted an inspection of Entergy New Orleans' Michoud power plant and found a number of dead brown pelicans near the facility's water intake structure and fish-return trough. Brown pelicans are an endangered species in Louisiana. The United States Attorney's Office for the Eastern District of Louisiana (Attorney's Office) issued a grand jury subpoena to an Entergy New Orleans employee in May 2004 to give evidence regarding the cause of death of the pelicans. The Attorney's Office then agreed to meet with Entergy New Orleans rather than requiring the employee to testify. As a result of that meeting, Entergy New Orleans conducted an internal investigation of the matter and submitted a report to the Attorney's Office in August 2004. Entergy New Orleans also constructed an engineered walkway and cover over the intake structure and feeding trough to eliminate pelican access to the area. Entergy New. Orleans continues negotiations with the Attorney's Office regarding final resolution of this matter. Litliration Certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment in these states poses a-significant business risk. Ratenayer Lawsuits (Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and Entergy New Orleans) Entergy New Orleans Fuel Clause Lawsuit In April 1999, a group of ratepayers filed a complaint against Entergy New Orleans, Entergy Corporation, Entergy Services, and Entergy Power in state court in Orleans Parish purportedly on behalf of all Entergy New 142
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Orleans ratepayers. The plaintiffs seek treble damages for alleged injuries arising from the defendants' alleged violations of Louisiana's antitrust laws in connection with certain costs passed on to ratepayers in Entergy New Orleans' fuel adjustment filings with the City Council. In particular, plaintiffs allege that Entergy New Orleans improperly included certain costs in the calculation of fuel charges and that Entergy New Orleans imprudently purchased high-cost fuel from other Entergy affiliates. Plaintiffs allege that Entergy New Orleans and the other defendant Entergy companies conspired to make these purchases to the detriment of Entergy New Orleans' ratepayers and to the benefit of Entergy's shareholders, in violation of Louisiana's antitrust laws. Plaintiffs also seek to recover interest and attorneys' fees. Entergy filed exceptions to the plaintiffs' allegations, asserting, among other things, that jurisdiction over these issues rests with the City Council and FERC. In March 2004, the plaintiffs supplemented and amended their petition. If necessary, at the appropriate time, Entergy will also raise its defenses to the antitrust claims. The suit in state court has been stayed by stipulation of the parties pending a decision by the City Council in the proceeding discussed in the next paragraph. Plaintiffs also filed this complaint with the City Council in order to initiate a review by the City Council of the plaintiffs' allegations and to force restitution to ratepayers of all costs they allege were improperly and imprudently included in the fuel adjustment filings. Testimony was filed on behalf of the plaintiffs in this proceeding asserting, among other things, that Entergy New Orleans and other defendants have engaged in fuel procurement and power purchasing practices and included costs in Entergy New Orleans' fuel adjustment that could have resulted in Entergy New Orleans customers being overcharged by more than $100 million over a period of years. Hearings were held in February and March 2002. In February 2004, the City Council approved a resolution that resulted in a refund to customers of $11.3 million, including interest, during the months of June through September 2004. The resolution concludes, among other things, that the record does not support an allegation that Entergy New Orleans' actions or inactions, either alone or in concert with Entergy or any of its affiliates, constituted a misrepresentation or a suppression of the truth made in order to obtain an unjust advantage of Entergy New Orleans, or to cause loss, inconvenience or harm to its ratepayers. The plaintiffs have appealed the City Council resolution to the state court in Orleans Parish. Oral argument on the plaintiffs' appeal was conducted in February 2005. Entergy New Orleans Rate of Return Lawsuit In April 1998, a group of residential and business ratepayers filed a complaint against Entergy New Orleans in state court in Orleans Parish purportedly on behalf of all ratepayers in New Orleans. The plaintiffs allege that Entergy New Orleans overcharged ratepayers by at least $300 million since 1975 in violation of limits on Entergy New Orleans' rate of return that the plaintiffs allege were established by ordinances passed by the Council in 1922. The plaintiffs seek, among other things, (i) a declaratory judgment that such franchise ordinances have been violated; and (ii) a remand to the Council for the establishment of the amount of overcharges plus interest. Entergy New Orleans believes the lawsuit is without merit. Entergy New Orleans has charged only those rates authorized by the Council in accordance with applicable law. In May 2000, a court of appeal granted Entergy New Orleans' exception to jurisdiction in the case and dismissed the proceeding. The Louisiana Supreme Court denied the plaintiff's request for a writ of certiorari. The plaintiffs then commenced a similar proceeding before the Council. The plaintiffs and the advisors for the Council each filed their first round of testimony in January 2002. In their testimony, the plaintiffs allege that Entergy New Orleans earned in excess of the legally authorized rate of return during the period 1979 to 2000 and that Entergy New Orleans should be required to refund between $240 million and $825 million to its ratepayers. In the testimony submitted by the Council advisors, the advisors allege that Entergy New Orleans has not earned in excess of its authorized rate of return for the period at issue and that no refund is therefore warranted. A hearing scheduled in June 2002 was canceled. In December 2003, the Council Advisors filed a motion in the Council proceedings to bifurcate the hearing in this matter, such that the effect of the provision of the 1922 Ordinance in setting lawful rates would be considered first. Only if it is determined that this provision establishes a limitation, would the remaining issues be reached. The motion to bifurcate was granted by the City Council in April 2004, and a hearing on the first part of the bifurcated proceeding is currently scheduled to begin in June 2005. 143
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Texas Power Price Lawsuit In August 2003, a lawsuit was filed in the district court of Chambers County, Texas by Texas residents on behalf of a purported class apparently of the Texas retail customers of Entergy Gulf States who were billed and paid for electric power from January 1, 1994 to the present." The named defendants are Entergy Corporatibn, Entergy Services, Entergy Power, Entergy Power Marketing Corp., Arkansas Electric Cooperative Corporation and Vntergy Arkansas. Entergy Gulf States is not a named defendant, but is alleged to be a co-conspirator. The court has granted the request of Entergy Gulf States to intervene in the lawsuit to protect its interests. Plaintiffs allege that the defendants implemented a "price gouging accounting scheme" to sell to plaintiffs and similarly situated utility customers higher priced power generated by the defendants while' rejecting and/or reselling to off-system utilities, less expensive power offered and/or purchased from off-system suppliers and/or generated by the Entergy system. In particular, plaintiffs allege that the defendants manipulated and continue to manipulate the dispatch of generation so that power is purchased from affiliated expensive resources instead of buying cheaper off-system power. Plaintiffs estimate that customers in Texas were charged at least $57 million above prevailing market prices for power. Plaintiffs seek actual, consequential and exemplary damages, costs and attorneys' fees;- and disgorgement of profits. In September 2003, the Entergy defendants removed the lawsuit to the federal court in Galveston, and in October 2003, filed a pleading seeking dismissal of the plaintiffs' claims.' In Octobet 2003, the plaintiffs filed a motion to remand the case to state court. In January 2004, the federal court determined that it did not have jurisdiction over the subject matter of the lawsuit, and remanded the case to the state district court in Chambers County. In November 2004, the state district court dismissed the case based on a lack of jurisdiction. The plaintiffs have initiated appellate proceedings in the Court of Appeals, ' Entergy Louisiana Formula Ratemaking Plan Lawsuit In May 1998, a group of ratepayers filed a complaint against Entergy Louisiana and the LPSC in state court in East Baton Rouge Parish purportedly on behalf of all Entergy Louisiana ratepayers. The plaintiffs allege that the formula ratemaking plan authorized by the LPSC has allowed Entergy Louisiana to earn amounts in excess of a fair return. The plaintiffs seek, among other things, (i) a declaratory judgment that the formula ratemaking plan is an improper ratemaking practice; and (ii) a refund of the amounts allegedly charged in excess of proper rateniaking practices. This case has not been active, and abandonment issues are being evaluated. At this time, management cannot determine the amount of damages being sought. ' . l' Murphy Oil Lawsuit (Entergy Corporation and Entergy Louisiana) Residents located near the Murphy Oil Refinery in Meraux, Louisiana filed several lawsuits in state court in St, Bernard Parish, Louisiana against Murphy Oil, Entergy Louisiana, and others for injuries they allegedly suffered as a result of an explosion at the refinery in June 1995. -The lawsuits were consolidated and a class of plaintiffs was certified. Plaintiffs alleged, among other things, that an electrical fault at an Entergy -Louisiana, substation contributed to causing the explosion. Murphy Oil filed a cross-claim against Entergy Louisiana based on the same allegation, in which Murphy Oil seeks recovery of any damages it has paid to the plaintiffs.. Claiborne P. Deming, who became a director of Entergy Corporation in 2002, is the President and Chief Executive Officer of Murphy Oil. Murphy Oil and other defendants settled with the plaintiffs for $8.8 million, but Entergy Louisiana did not participate in the settlement. After trial for the remaining parties in the proceeding, the judge issued a decision finding Entergy Louisiana 40% responsible and awarding monetary damages, which total approximately $11 million with interest against Entergy Louisiana. Entergy Louisiana appealed the judgment to the Court of Appeals. Entergy Louisiana has insurance in place for claims of this type, and management does not expect a material adverse financial effect from this decision. , 144
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Fiber Optic Cable Litigation (Entergy Corporation, Entergy Gulf States, and Entergy Louisiana and Entergy Mississippi) In 1998, a group of property owners filed a class action suit against Entergy Corporation, Entergy Gulf States, Entergy Services and Entergy Technology Holding Company in state court in Jefferson County, Texas purportedly on behalf of all property owners in each of the states throughout the Entergy service area who have conveyed easements to the defendants. The lawsuit alleged that Entergy installed fiber optic cable across their property without obtaining appropriate easements. The plaintiffs sought actual damages for the use of the land and a share of the profits made through use of the fiber optic cables and punitive damages. The state court petition was voluntarily dismissed, and the plaintiffs commenced a class action suit with the same claims in the United States District Court in Beaumont, Texas. Both sides have filed motions for summary judgment, which were heard by the court in late 2001. In 2003, the district judge ruled that as a matter of law, all of the Texas easements permit Entergy to utilize the fiber for their own communications. Further, the court ruled that approximately two-thirds of the Texas easements allow Entergy to use the fiber for external or third party communications. Entergy believes that any damages suffered by the remaining one-third plaintiff landowners are negligible and that there is no basis for the claim seeking a share of profits. In April 2004, the trial court entered an order denying the plaintiffs' request that this case be certified as a class. The plaintiffs have appealed this ruling to the United States Court of Appeals for the Fifth Circuit. At this time, management cannot determine the specific amount of damages being sought. Several property owners have filed a class action suit against Entergy Louisiana, Entergy Services, ETHC, and Entergy Technology Company in state court in St. James Parish, Louisiana purportedly on behalf of all property owners in Louisiana who have conveyed easements to the defendants. The lawsuit alleges that Entergy installed fiber optic cable across their property without obtaining appropriate easements. The plaintiffs seek actual damages for the use of the land and a share of the profits made through use of the fiber optic cables and punitive damages. Entergy removed the case to federal court in New Orleans; however, the District Court remanded the case back to state court. While Entergy appealed this ruling, recently the United States Court of Appeals for the Fifth Circuit denied this appeal. In December 2003, the trial court held a hearing to determine if a class should be certified. On February 18, 2004, the trial court entered an order certifying this matter as a class. Entergy has appealed this ruling to the Louisiana Fifth Circuit Court of Appeals, and oral arguments have been held. At this time, management cannot determine the specific amount of damages being sought. Several property owners have filed separate lawsuits against Entergy Corporation, Entergy Mississippi, Entergy Services, ETHC, and ETC in state court in various counties in Mississippi alleging that Entergy Mississippi installed fiber optic cable across their properties without obtaining appropriate easements. The plaintiffs seek actual damages for the use of the land, a share of the profits made through use of the fiber optic cables, and at least $20 million in punitive damages in one case, and an unspecified amount of punitive damages in the other cases. Asbestos and Hazardous Waste Suits (Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans) Numerous lawsuits have been filed in federal and state courts in, Texas, Louisiana, and Mississippi primarily by contractor employees in the 1950-1980 timeframe against Entergy Gulf States, Entergy Louisiana, Entergy New Orleans, and Entergy Mississippi as premises owners of power plants, for damages caused by alleged exposure to asbestos or other hazardous material. Many other defendants are named in these lawsuits as well. Currently, there are approximately 480 lawsuits involving approximately 10,000 claims. Reserves have been established that should be adequate to cover any exposure. Additionally, negotiations continue with insurers to recover more reimbursement, while new coverage is being secured to minimize anticipated future potential exposures. Management believes that loss exposure has been and will continue to be handled successfully so that the ultimate resolution of these matters will not be material, in the aggregate, to the companies' financial position or results of operation. 145
Part I Item I Entergy Corporation, Domestic utility companies, and System Energy Employment Litigation (Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy) Entergy Corporation and the domestic utility companies are defendants in numerous lawsuits that have been filed by former employees alleging that they were wrongfully terminated and/or discriminated against on the basis of age, race, sex, and/or other protected characteristics. Entergy Corporation and the domestic utility companies are vigorously defending these suits and deny any liability to the plaintiffs. However, no assurance can be given as to the outcome of these cases, and at this time management cannot estimate the total amount of damages sought. Included in the employment litigation are two cases filed in state court in Claiborne County, Mississippi in December 2002. The two cases were filed by former employees of Entergy Operations who were based at Grand Gulf. Entergy Operations and Entergy employees are named as defendants. The cases make employment-related claims, and seek in total $53 million in alleged actual damages and $168 million in punitive damages. Entergy subsequently removed both proceedings to the federal district in Jackson, Mississippi. Entergy cannot predict the ultimate outcome of this proceeding. Research Spendin2 Entergy is a member of the Electric Power Research Institute (EPRI). EPRI conducts a broad range of research in major technical fields related to the electric utility industry. Entergy participates in various EPRI projects based on Entergy's needs and available resources. The domestic utility companies contributed $1.6 million in 2004, $1.5 million in 2003, and $2.1 million in 2002 to EPRI. The Non-Utility Nuclear business contributed $3.2 million in 2004 and $3 million in both 2003 and 2002 to EPRI. Employees Employees are an integral' part of Entergy's commitment to serving its customers. As of December 31, 2004, Entergy employed 14,425 people. U.S. Utility: Entergy Arkansas 1,494 Entergy Gulf States 1,641
-Entergy Louisiana 943 Entergy Mississippi '793 Entergy New Orleans 403 System Energy Entergy Operations 2,735 Entergy Services 2,704 Entergy Nuclear Operations 3,245 Other subsidiaries *277 Total Full-time 14,235 Part-time 190 Total Entergy 14,425 Approximately 4,900 employees are represented by the International Brotherhood of Electrical Workers Union, the Utility Workers Union of America, and the International Brotherhood of Teamsters Union.
146
ENTERGY ARKANSAS, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS Results of Operations Net Income 2004 Compared to 2003 Net income increased $16.2 million due to lower other operation and maintenance expenses, a lower effective income tax rate for 2004 compared to 2003, and lower interest charges. The increase was partially offset by lower net revenue. 2003 Compared to 2002 Net income decreased $9.6 million due to lower net revenue, higher depreciation and amortization expenses, and a higher effective income tax rate for 2003 compared to 2002. The decrease was substantially offset by lower other operation and maintenance expenses, higher other income, and lower interest charges. Net Revenue 2004 Compared to 2003 Net revenue, which is Entergy Arkansas' measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2004 to 2003. (In Millions) 2003 net revenue $998.7 Deferred fuel cost revisions (16.9) Other (3.4) 2004 net revenue $978.4 Deferred fuel cost revisions includes the difference between the estimated deferred fuel expense and the actual calculation of recoverable fuel expense, which occurs on an annual basis. Deferred fuel cost revisions decreased net revenue due to a revised estimate of fuel costs filed for recovery at Entergy Arkansas in the March 2004 energy cost recovery rider, which reduced net revenue by $11.5 million. The remainder of the variance is due to the 2002 energy cost recovery true-up, made in the first quarter of 2003, which increased net revenue in 2003. Gross operatingrevenues, fuel andpurchasedpower expenses, and other regulatorycredits Gross operating revenues increased primarily due to:
- an increase of $20.7 million in fuel cost recovery revenues due to an increase in the energy cost recovery rider effective April 2004 (fuel cost recovery revenues are discussed in Note 2 to the domestic utility companies and System Energy financial statements);
- an increase of $15.5 million in Grand Gulf revenues due to an increase in the Grand Gulf rider effective January 2004;
- an increase of $13.9 million in gross wholesale revenue primarily due to increased sales to affiliated systems; and
- an increase of $9.5 million due to volume/weather primarily resulting from increased usage during the unbilled sales period, partially offset by the effect of milder weather on billed sales in 2004.
147
Entergy Arkansas, Inc. Management's Financial Discussion and Analysis Fuel and purchased power expenses increased primarily due to increased recovery of deferred fuel and purchased power costs primarily due to an increase in April 2004 in the energy cost recovery rider and the true-ups to the 2003 and 2002 energy cost recovery rider filings. Other regulatory credits decreased primarily due to the over-recovery of Grand Gulf costs due to an increase in the Grand Gulf rider effective January 2004. 2003 Compared to 2002 Net revenue, which is Entergy Arkansas' measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2003 to 2002. (In Millions) 2002 net revenue $1,095.9 March 2002 settlement agreement (154.0) Volume/weather (7.7) Asset retirement obligation 30.1 Net wholesale revenue 16.6 Deferred fuel cost revisions 10.2 Other 7.6 2003 net revenue $998.7
.The March 2002 settlement agreement resolved a request for recovery of ice storm costs incurred in December 2000 with an offset of those costs for funds contributed to pay for future stranded costs. A 1997 settlement provided for the collection of earnings in excess of an 11% return on equity in a transition cost account (TCA) to offset stranded costs if retail open access were implemented.
In mid- and late December 2000, two separate ice storms left 226,000 and 212,500 Entergy Arkansas customers, respectively, without electric power in its service area. Entergy Arkansas filed a proposal to recover costs plus carrying charges associated with power restoration caused by the ice storms. Entergy Arkansas' final storm damage cost determination reflected costs of approximately $195 million. The APSC approved a settlement agreement submitted in March 2002 by Entergy Arkansas, the APSC staff, and the Arkansas Attorney General. In the March 2002 settlement, the parties agreed that $153 million of the ice storm costs would be classified as incremental ice storm expenses that can be offset against the TCA on a rate class basis, and any excess of ice storm costs over the amount available in the TCA would be deferred and amortized over 30 years, although such excess costs were not allowed to be included as a separate component of rate base. The allocated ice storm*expenses exceeded the available TCA funds by $15.8 million which was recorded as a regulatory asset in June 2002. In accordance with the settlement agreement and following the APSC's approval of the 2001 earnings review related to the TCA, Entergy Arkansas filed to return $18.1 million of the TCA to certain large general service class customers that paid more into the TCA than their allocation of storm costs. The APSC approved the return of funds to the large general service customer class in the form of refund checks in August 2002. As part of the implementation of the March 2002 settlement agreement provisions, the TCA procedure ceased with the 2001 earnings evaluation. Of the remaining ice storm costs, $32.2 million was addressed through established ratemaking procedures, including $22.2 million classified as capital additions, while $3.8 million of the ice storm costs was not recovered through rates.-. The effect on net income of the March 2002 settlement agreement and 2001 earnings review was a $2.2 million increase in 2003, because the decrease in net revenue was offset by the decrease in operation and maintenance expenses discussed below., 148
Entergy Arkansas, Inc. Management's Financial Discussion and Analysis The volume/weather variance is the result of less favorable sales volume primarily due to the effect of colder winter weather in December 2002. The asset retirement obligation variance was dueto the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," adopted in January 2003. See "Critical Accounting Estimates" for more details on SFAS 143. The increase was offset by an increase in decommissioning expense and has no effect on net income. The net wholesale revenue variance was primarily due to an increase in sales volume to Entergy New Orleans pursuant to a purchased power agreement and also due to higher wholesale prices and volume. Deferred fuel cost revisions includes the difference between the estimated deferred fuel expense and the actual calculation of recoverable fuel expense, which occurs on an annual basis. In 2002, the deferred fuel expense estimate was larger than the actual recoverable fuel expense, which decreased net revenue. In 2003, the actual recoverable fuel expense was larger than the deferred fuel expense estimate, which increased net revenue. Gross operatingrevenues, fuel andpurchasedpower expenses, and other regulatory credits
,.Gross operating.revenues increased primarily due to an increase of $95.7 million in gross wholesale revenue due to the same factors discussed above that increased net wholesale revenue and also due to increased sales to affiliates in addition to the Entergy New Orleans sales mentioned above. The increase was partially offset by a decrease of $74.4 millionin fuel cost recovery revenues due to a decrease ine the annual recovery rider in October 2002.
Fuel and purchased power expenses decreased primarily due to the displacement of higher-priced natural gas generation by lower-priced purchased power and coal generation. Other regulatory credits decreased primarily due to the March 2002 settlement agreement and 2001 earnings review mentioned above, which increased other regulatory credits in 2002 to offset $159.9 million in other operation and maintenance expenses related to the December 2000 ice storms. The decrease was partially offset by the asset retirement obligation mentioned. above, which increased regulatory, credits in 2003 to offset the increase in decommissioning expense. Other Income Statement Variances 2004 Compared to 2003 Other operation and maintenance expenses decreased primarily due to voluntary severance accruals of $31.8 million in 2003. The decrease was partially offset by.the following:
- an increase of $6.6 million in customer service support costs; and
- an increase of $5.1 million in benefits costs.
Interest charges decreased primarily due to the refinancing of First Mortgage Bonds in mid-2003. 2003 Compared to 2002 Other operation and maintenance expenses decreased primarily due to expenses in 2002 of $159.9 million due to theMarch 2002 settlement agreement and,2001 earnings review which allowed Entergy Arkansas to recover a large majority of 2000 and 2001 ice storm repair expenses through the previously-collected transition cost account amounts (which was offset by a corresponding decrease in other regulatory credits and has no effect on net income). Decreases of $18.7 million in administrative and general expenses and $4.7 million in contract labor costs also contributed to the decrease. The decrease was partially offset by the following:
- voluntary severance accruals of $31.8 million in 2003; and
- an increase of $10.4 million in benefits costs.
149
Entergy Arkansas, Inc. Managernenfs Financial Discussion and Analysis Decommissioning expense increased due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations." The increase in decommissioning expense was offset by increases in other regulatory credits and interest and dividend income and has no effect on net income. Depreciation and amortization expenses increased primarily due to an increase in plant in service. Other income increased primarily due to:
- an increase of $7.3 million in interest and dividend income due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations." As mentioned above, the increase was offset in decommissioning expense and has no effect on net income; and
- an increase of $4.8 million in the allowance for equity funds used during construction due to an increase in construction work in progress.
Interest charges decreased primarily due to:
- an increase in interest expense in 2002 resulting from a true-up of the annual fuel recovery rider in March 2002 of $4.5 million;
- interest recorded in 2002 of $4.1 million (offset by a corresponding decrease in other regulatory credits and has no effect on net income) on the transition cost account obligation, which was terminated as a result of the March 2002 settlement agreement; and
- an increase in 2003 of $3.0 million in the allowance for borrowed funds used during construction due to an increase in construction work in progress.
Income Taxes The effective income tax rates for 2004, 2003, and 2002 were 38.5%, 45.5%, and 34.5%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate. The lower effective income tax rate in 2004 compared to 2003 was primarily due to book and tax differences related to utility plant items and flow-through items. Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet. Liquidity and Capital Resources Cash Flow Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows: 2004 2003 2002 (In Thousands) Cash and cash equivalents at beginning of period $8,834 $95,513 $103,466 Cash flow provided by (used in): Operating activities 446,298 437,520 357,421 Investing activities (269,385) (337,509) (249,438) Financing activities (96,003) (186,690) (115,936) Net increase (decrease) in cash and cash equivalents 80,910 (86,679) (7,953) Cash and cash equivalents at end of period $89,744 $8,834 $95,513 150
Entergy Arkansas, Inc. Managemenfs Financial Discussion and Analysis Operating Activities Cash flow from operations increased $8.8 million in 2004 compared to 2003 primarily due to income tax benefits received in 2004, and increased recovery of deferred fuel costs. This increase was substantially offset by money pool activity. In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $1.171 billion deduction for Entergy Arkansas on Entergy's 2003 income tax return. There was -no cash benefit from the method change in 2003. In 2004, Entergy Arkansas realized $173 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. As of December 31, 2004, Entergy Arkansas has a net operating loss (NOL) carnyforward for tax purposes of $766.9 million, principally resulting from the change in tax accounting method related to cost of goods sold. If the tax accounting method change is sustained, Entergy Arkansas expects to utilize the NOL carryforward through 2006. Cash flow from operations increased $80.1 million in 2003 compared to 2002 primarily due to income taxes paid of $2.2 million in 2003 compared to income taxes paid of $83.9 million in 2002, and money pool activity. ! This increase was partially offset by decreased recovery of deferred fuel costs in 2003. Entergy Arkansas' receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years: 2004 2003 2002 2001 (In Thousands)
$23,561 ($69,153) $4,279 $23,794 Money pool activity used $92.7 million of Entergy Arkansas' operating cash flow in 2004, provided $73.4 million in 2003, and provided $19.5 million in 2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.
Inyesting Activities The decrease of $68.1 million in net cash used in investing activities in 2004 compared to 2003 was primarily due to a decrease in construction expenditures resulting from rless transmission upgrade work requested by merchant generators in 2004 combined with lower spending on customer support projects in 2004.' The increase' of $88.1 million in net cash 'used in investing activities in 2003 compared to 2002 was primarily due to an increase in construction expenditures of $57.4 million and the maturity of $38.4 million of other temporary investments in the first quarter of 2002. Construction expenditures increased in 2003 primarily due to the following:
- a FERC ruling that shifted responsibility for transmission upgrade work performed for independent power producers to Entergy Arkansas; and
- the ANO 1 steam generator, reactor vessel head, and transformer replacement project.
Financing Activities The decrease of $90.7 million in net cash used in financing activities in 2004 compared to 2003 was primarily due to the net redemption of $2.4 million of long-term debt in 2004 compared to $109.3 million in 2003, partially offset by the payment of $16.2 million more in common stock dividends during the same period. 151
Entergy Arkansas, Inc. Management's Financial Discussion and Analysis The increase of $70.8 million in net cash used in financing activities in 2003 compared to 2002 was primarily due to the net redemption of $109.3 million of long-term debt in 2003 compared to the net issuance of
$18.4 million in 2002, partially offset by the payment of $56.3 million less in common stock dividends during the same period.
See Note 5 to the domestic utility companies and System Energy financial statements for details on long-term debt. Uses of Capital Entergy Arkansas requires capital resources for:
- construction and other capital investments;
- debt and preferred stock maturities;
- working capital purposes, including the financing of fuel and purchased power costs; and
/
- dividend and interest payments.
Following are the amounts of Entergy Arkansas' planned construction and other capital investments, existing debt and lease obligations, and other purchase obligations: 2005 2006-2007 2008-2009 after 2009 Total (In Millions) Planned construction and capital investment (1) $321 $455 N/A N/A $776 Long-term debt $147 $ . $1 $1,191 $1,339 Capital lease payments $10 $9 $2 $2 $23 Operating leases $24 $38 $23 $54 $139 Purchase obligations (2) $433 $832 $827 $2,840 $4,932 Nuclear fuel lease obligations (3) $42 $52 N/A N/A $94 (1) Includes approximately $175 to 180 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. (2) Purchase obligations represent the minimum purchase obligation or cancellation charge for' contractual obligations to purchase goods or services. For Entergy Arkansas almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the domestic utility companies and System Energy financial statements. (3) It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations. In addition to these contractual obligations, Entergy Arkansas expects to contribute $20.6 million to its pension plans and $16.1 million to other postretirement plans in 2005. On July 25, 2002, the Board authorized Entergy Arkansas and Entergy Operations' to replace the ANO I steam generators and reactor vessel closure head. Entergy management estimates the cost of the fabrication and replacement to be approximately $235 million, of which approximately $96 million has been incurred through 2004.
$115 million is expected to be incurred in 2005, with the remainder of the costs expected in 2006. Management expects that the replacement will occur during a planned refueling outage in 2005. Entergy Arkansas filed with the APSC in January 2003 a request for a declaratory order thatthe investment in the replacement is in the public interest.
The APSC issued the requested order in May 2003. This order is analogous to the order received in 1998 prior to the replacement of the ANO 2 steam generators. See "Nuclear Matters" below for further discussion of the replacement of the ANO I steam generators and reactor vessel closure head. 152
Entergy Arkansas, Inc. Management's Financial Discussion and Analysis In addition to the steam generators and reactor vessel closure head replacement, the planned capital investment estimate for Entergy Arkansas also reflects capital required to support existing business and customer growth. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, market volatility, economic trends, environmental compliance, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the domestic utility companies and System Energy financial statements. As a wholly-owned subsidiary, Entergy Arkansas pays dividends to Entergy Corporation from its earnings at a percentage determined monthly. Entergy Arkansas' long-term debt indentures restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock. As of December 31, 2004, Entergy Arkansas had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million. Sources of Capital Entergy Arkansas' sources to meet its capital requirements include:
- internally generated funds;
- cash on hand;
- debt or preferred stock issuances; and
- bank financing under new or existing facilities (Entergy Arkansas has a 364-day credit facility available with an expiration date of April 2005 in the amount of $85 million, of which none was drawn at December 31, 2004).
Entergy Arkansas issued first mortgage bonds in 2004 as follows: Issue Date Description Maturity Amount (In Thousands) October 2004 6.38% Series November 2034 $60,000 The proceeds were used to redeem junior subordinated debentures as follows: Retirement Description Maturity Amount Date (In Thousands) November 2004 8.50% Series September 2045 $61,856 Entergy Arkansas may refinance or redeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable. All debt and common and preferred stock issuances by Entergy Arkansas require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs. Short-term borrowings by Entergy Arkansas, including borrowings under the money pool, are limited to an amount authorized by the SEC, which is $235 million. Under its SEC Order and without further authorization, Entergy Arkansas cannot incur additional short-term indebtedness unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy Arkansas, as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Arkansas' short-term borrowing limits. 153
Entergy Arkansas, Ine. Management's Financial Discussion and Analysis Signiflcant Factors and Known Trends Utility Restructuring In April 1999, the Arkansas legislature enacted Act 1556, the Arkansas Electric Consumer Choice Act, providing for competition in the electric utility.industmy through retail open access. In December 2001, the APSC recommended to the Arkansas General Assembly that legislation be enacted during the 2003 legislative session to either repeal; Act 1556 or, further delay retail open access until at. least 2010. In February 2003, the Arkansas legislaturt voted to repeal Act 1556 and the repeal was signed into law by the governor. At.; C restruct i g .t th whole .l'.elha beu
' At FERC, restructuring at the wholesale level has begun but has been delayed. It is too early to predict the ultimate effects of changes in U.S. energy markets. Restructuring issues are complex and are continually affected by events at the national, regional, state, and local levels. However, these changes may result, in the long term, in fundamental changes in the way traditional integrated utilities and holding company systems, like the Entergy system, conduct their business. Some of these changes may be positive for Entergy, while others may not.
System Agreement Proceedings The domestic utility companies historically have engaged in the coordinated planning, construction, and operation of generating and transmission facilities under the terms of an agreement called the System Agreement that has been approved by the FERC. Litigation involving the System Agreement is being pursued by the LPSC at both the' FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies in their execution of the System Agreement, and seek support for local regulatory authority over System Agreement issues. Regarding the proceeding at the LPSC, Entergy believes that state and'local regulators are preempted by federal law from reviewing and deciding System Agreement issues for themselves. An unrelated case between the LPSC and Entergy Louisiana raised the question of w'hether- a state regulator is preempted by federal law from reviewing and interpreting FERC rate schedules that are part of the System Agreement, and from subsequently enforcing that interpretation. The LPSC interpreted a System Agreement rate schedule in the unrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed the LPSC's decision. In 2003, the U.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the decisions of the LPSC and the Louisiana Supreme Court. In February 2004, a FERC ALJ issued an Initial Decision in the LPSC-initiated proceeding at the FERC. The Initial Decision decided some issues in favor of the relief sought by the LPSC, and decided some issues against the relief sought by the LPSC.. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALUs Initial Decision. Entergy's exceptions to the ALUs Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision'and previously has been' rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsisteiit with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial' Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision' improperly 'rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the, full costs of the Vidalia'project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve&sharing costs rather than the current method. i If the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase'in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy Sytem' average, and a material decrease-in the total production costs the FERC allocates to companiesg'whose costs currently are*projected to exceed that average. If the FERC adopts the AL's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The AL's Initial Decision would reallocate production 154
Entergy Arkansas, Inc. Managemenfs Financial Discussion and Analysis costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost. An assessment of the potential effects 'of the AL's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85ImmBtu for the 1995-2004 period, and averaging $3A3/mmBtu during the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the AL's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009: Average Annual Range of Annual Payments Payments or (Receipts) or (Receipts) for 2005-2009 Period (In Millions) (In Millions) Entergy Arkansas $154 to $281 $215 Entergy Gulf States ($130) to ($15) ($63) Entergy Louisiana ($199) to ($98) ($141) Entergy Mississippi ($16) to $8 $1 Entergy New Orleans ($17) to ($5) ($12) Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. The timing of recovery of these costs in rates could be the subject of additional proceedings at the APSC and elsewhere, however, and a delay in full recovery of any increased allocation of production costs could result in additional financing requirements. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy Arkansas does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation. In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC AL's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy 'Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the AL's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; and states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate. In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse 155
Entergy Arkansas, Inc. Management's Financial Discussion and Analysis financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the ALUs Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations. In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement. until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Louisiana, as well as the named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity. Transmission In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs. In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement' process (WPP). r-The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations, Entergy also proposed to have the ICT. administer a transmission expansion pricing protocol that will; increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect,Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review-at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences. In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy; The petition also indicates that, subject to the outcome of the petition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional 156
Entergy Arkansas, Inc. Management's Financial Discussion and Analysis functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy, Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005. In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion of the proposal currently scheduled for August 2005. Interconnection Orders
- The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos, including $42 million for Entergy Arkansas. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy. To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators.
Available Flowgate Capacity Proceeding On December 17, 2004, the FERC issued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised in a FERC audit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC program, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory. Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of 157
Entergy Arkansas, Inc. Management's Financial Discussion and Analysis the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing
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.Iffl t j 1 1 x J-Entergy believes that it has complied with the provisions of it' oprecess transmission tariff, including the provisions addressing the implementation of the AFC methodology; hoWever, the ultimate scope of this proceeding cannot be predicted at this time.' A hearing in the AFC proceeding is currently scheduled to commence in August 2005. _A9 ~~3/4 h 4 10 o ' ta,J;, O I .i-i£
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;.,9siA Market and Credit Risks Entergy Arkansas has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial' instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement; i'A. r . -J Sno e i Interest Rate and Equity Price Risk - Decommissioning Trust Funds : - -.
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-:.I Entergy Arkansas' nuclear decommissioning trust funds are- exposed to fluctuations in equity prices and interest rates. The NRC requires Entergy Arkansas to maintain trusts to fund the costs of decommissgiotting ANO 1 and ANO 2. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the ANO trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 12 to the domestic utility companies and System Energy financial statements. ,;. - *-*** ' i By, i I'>4 ';ILX. 5 '0' 2 State and Local Rate Regulatory Risks . *'u .LA a The rates that Entergy Arkansas charges for its services arte-ani important item influencing Entergy Arkansas' financial position, results of operations, and liquidity. Entergy Arkansas-is closely regulated and the rates charged to its customers are determined in regulatory proceedings. A gove rntal agency, the APSC, is, primarily responsible for approval of the rates charged to customers. Entergy Arkansas' fuel costs recovered from customers al'e also subject to regulatory scrutiny. Refer to Note 2 to the domestic utility companies 'and System Energ&-financial statements for fuel recovery and retail rate proceedings. -l'e .-?' -. -; .l -i i:*.. ifit 01 t 11 Nuclear Matters
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Entergy Arkansas owns and operates, through an affiliate, the ANO 1 and ANO 2 nuclear power plants. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks from the use, storage, handling and disposal of high-level and low-'level radioactive materials, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of either ANO 1 or ANO 2, Entergy Arkansas may be required'to file with the APSC a rate nfechanism'to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ; In August 2001, the NRC issued a bulletin requesting all pressUrized water'teactof owners and ojeratdts to report on the structural integrity of their reactor vessel head penefration nozzles to justify continued operations past December 31, 2001. These types of reactors are susceptible to stress corrosion cracking of the reactoi vessel head nozzles. ANO 1 and ANO 2 are pressurized water reactOrs: In December 2001, Entergy issued a request for proposal to provide replacement steam generators for ANO 1. Entergy subsequently entered a contract for delivery of the replacement generators in August 2005 in time for installatio'ni during the scheduled refueling outage. Both the new steam generators and the reactor vessel head will be installed in the fall of 2005. To date, thefe has been no primary side stress corrosion cracking identified in the ANO 2`ioact'oteSesel head.' Inspectioiil of the ANO 2 reactor vessel head will continue during planned refueling outages - a -.<i . . .. . 158
Entergy Arkansas, Inc. Management's Financial Discussiobn'and Analysis
;-i' Efitergy Arkansas filed with the APSC in January 2003 a reqV61st for a declaratory order that the investment in the replacement is in the public interest. The APSC issued the -requested order in May 2003. This order is analogous to the order rdceived in 1998 prior to the replacement of the ANO 2 steam generators.
Environmental Risks
=;:I... j1/4:.-. thi f;l[Cicfatrnntl to east;: wir .321,; JaiN b519&dJo.9 ?Petri i.'I,;i lvJe K <it ,2 it Entergy Arkansas' facilities-and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, watet quality, control of toxic substances afid hazardous and solid wastes, and other environmental matt&s. Management believes that Eniergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because etvironrffiental regulations are subject to change, future compliancelcosts cannot bte precisely estimated. ' : . If
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Critical Accounting Estimates HSJ kit' ltOz 4 : <Ut ;t} The preparation of Entergy Arkansas' financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgni6nts thatcan haVeta significant effect on reported finaiciail o6sitioh; results of operations, and cash flows. Management has identified the f6llowing accountinfg policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements could produce estimates that Woiuld haVe-a material effect on the presentation of Entergy Arkansas' financial position or results of operations. . Jr. ,. 'i' 2) -'i' ti) Nuclear Decommissioning Costs -' stp <P1 .A P. LI! HUT... 1-0'fIiuttJ Itlft)sŽ1 *
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- . Regulations require Entergy Arkansas to decommission the ANO 1 and ANO 2 nuclear power plants after the facilities are taken out of service, and money is collected and deposited in trust funds during the facilities' operating lives in order to provide for this obligation. Entergy Arkansas conducts periodic decommissioning cost studies (typically updated every five years) to estimate the costs that will be incurred to decommission the facilities.
The following key assumptions have a significant effect on these estimates: -..... 1ti .J. ' Kr. less vi~i UD.i Ji l t(JV' sh 3 i .X,?. : ta ,aisI'.tsii J.i! t A t-.'i. Li, 5 Sfl 0n * < ;Al )v1s i a <.N, . .
- Cost Escalation Factors - Entergy Arkansas' decommissi6ningStidies include an assumption that decommissioning costs will escalate over present cost levels by an annual factor approximating CPI-U. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11%.
- Timing - The date of the plant's retirement must be estimated and an assumption must be made whether decommissioning will bogmi immediately upon plant retirement, or whether the plant will be held in IIrI I "safestore" status for later decotnis'sioning, as permitted by applicable regulations. While the effect of 4> -
it these assumptions cannot be determined with precision, assuming either license extension or use of a,,,
."safestore" status can possibly decrease the present valu&of these obligations. As discussed in Note 8 to*
4J-A the domestic utility companies and System Energy financial statements, Entergy Arkansas recorded a revision in 2004 to its estimated decommissioning cost liability for ANO 1 and ANO 2 to reflect changes due to a new decommissioning study. The changes in probability for ANO 1 and ANO 2 had no effect on
-P^net income because, as discussed further below, any ambfouhtt recorded related to SFAS 143 are offset by the recording of regulatory as*ets or regulatory liabilities when projected decommissioning costs are .
collected in rates. tbi; Z. X :) BaAa d)M o Iyt i . C; imc... euaru ? II .
- Spent Fuel Disposal -Federal regulatio" require the DOS WVtpr6vide a permanentfrepsitory for the storag'e of spent nuclear fuel, and legislation has beeft'pased by Congress to develop this repository at Yucca Mountain, Nevada. Until this site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenarice of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities can have a significant effect (as much as 16% of estimated decorfihiissi6 iingI5sts). These estimates could change in the fuiture based on the timing of the op-ehing of the Vucd ModWrfain facility, the Schedule for shipferifts to
* "- that facility when it is olened, or other factors.- t'1IA 01 ; sd vU.i f7 Jr. t-.di 1;
- Technology 'and Regulation T-to date, ith&re limifed faticale-ixperiencen nwith ihU-uiedSiafes actual decomrmissioning of large iiuclear facilities& s i&periede Is-ga:inied and technology chariges, cost '
159
Entergy Arkansas, Inc. Management's Financial Discussion and Analysis estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. Entergy Arkansas' decommissioning cost studies assume current technologies and regulations. Through 2001, Entergy Arkansas collected the projected costs of decommissioning ANO I and ANO 2 through rates charged to customers. Now, based on assumptions approved by the APSC, including an assumed license extension for ANO 2 (ANO 1's license has already been extended), which significantly extends the earnings period, and the sufficiency of previously collected funds, Entergy Arkansas is not collecting additional funds to decommission ANO I and ANO 2 in its current rates. The assumptions will be reviewed annually and reflected in Entergy Arkansas' filing of its annual determination of the nuclear decommissioning rate rider. The amounts that were collected through rates, which were based upon decommissioning cost studies, were deposited in decommissioning trust funds. SFAS 143 Eptergy Arkansas implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy Arkansas' asset retirement obligations, and the measurement and recording of Entergy Arkansas' decommissioning obligations outlined above changed significantly with the implementation of SFAS 143. The most significant differences in the measurement of these obligations are outlined below:
- Recording of full obligation - SFAS 143 requires that the fair value of an asset retirement obligation be recorded when it is incurred. This caused the recorded decommissioning obligation of Entergy Arkansas to increase significantly, as Entergy Arkansas had previously only recorded this obligation as the related costs were collected from customers, and as earnings were recorded on the related trust funds.
- Fair value approach - SFAS 143 requires that these obligations be measured using a fair value approach.
Among other things, this entails the assumption that the costs will be incurred by a third party and will, therefore include appropriate profit margins and risk premiums. Entergy Arkansas' decommissioning studies to date have been based on Entergy Arkansas performing the work, and have not included any such margins or premiums. Inclusion of these items increases cost estimates.
- Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted risk-free rate.
The net effect of implementing this standard for Entergy Arkansas was recorded as a regulatory asset, with no resulting impact on Entergy Arkansas' net income. Entergy Arkansas recorded this regulatory asset because its existing rate mechanism is based on the original or historical cost standard that allows Entergy Arkansas to recover all ultimate costs of decommissioning existing assets from current and future customers. Upon implementation, assets and liabilities increased by $532 million in 2003 as a result of recording the asset retirement obligation at its fair value as determined under SWAS 143, increasing total utility! plant by $106 million, reducing accumulated depreciation by $252 million, and recording the related regulatory asset of $174 million.
- In the first quarter of 2004, Entergy Arkansas recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for ANO I and 2 as a result of revised decommissioning costs and changes in assumptions regarding the timing of when the decommissioning of the plants will begin. The revised, estimate resulted in a $107,7 million reduction in its decommissioning liability, along with a $19,5 million reduction in utility plant and an $88.2 million reduction in the related regulatory asset.
Unbilled Revenue As discussed in Note I to the domestic utility companies and System Energy financial statements, Entergy Arkansas records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is 160
Entergy Arkansas, Inc. Management's Financial Discussion and Analysis primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regarding price such as the fuel cost recovery mechanism. Pension and Other Postretirement Benefits Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretiremnent health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's' reported costs of providing these benefits, as described in Note 10 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate ofthese costs is a critical accounting estimate. Assumptions Key actuarial assumptions utilized in determining these costs include:
- Discount rates used in determining the future benefit obligations;
- Projected health care cost trend rates;
- Expected long-term rate of return on plan assets; and
- Rate of increase in future compensation levels.
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and worse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits.: In addition, these trends have caused Entergy to make a number of adjustments to its assumptions. In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 6.75% in 2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to a 10% increase in health care costs in 2005 gradually decreasing each successive year, until it reaches a 4.5% annual increase in health care costs in 2011 and beyond. In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities, and 4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51,% equity securities and 49% fixed income securities. Based on recent market trends, Entergy reduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 8.75% for 2002 and 2003 to 8.5% in 2004. The assumed rate of increase in future compensation levels used to calculate benefit obligations was 3.25% in 2002, 2003, and 2004. 161
Entergy Arkansas, Inc. Management's Financial Discussion and Analysis Cost Sensitivity The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (dollars in thousands): Change in Impact on 2004 Impact on Projected Actuarial Assumption Assumption Pension Cost Benefit Obligation Increase/(Decrease) Discount rate (0.25%) $2,001 $20,608 Rate of return on plan assets (0.25%) $1,055 Rate of increase in compensation 0.25% $907 $5,200 The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (dollars in thousands): Impact on Accumulated Change in Impact on 2004 Postrefirement Benefit Actuarial Assumption Assumption Postrefirement Benefit Cost Obligation Increase/(Decrease) Health care cost trend 0.25% $557 $3,633 Discount rate (0.25%) $342 $4,623 Each fluctuation above assumes that the other components of the calculation are held constant. Accounting Mechanisms In accordance with SFAS No. 87, -"Employers' Accounting for Pensions," Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into cost only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.
'Additionally, Entergy accounts for the impact of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years. depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87.
Costs and Funding Total pension cost for Entergy Arkansas in 2004 was $16.5 million.' Entergy Arkansas anticipates 2005 pension cost to increase to $21.8 million due to decrease in the discount rate' (from 6.25% to 6.00%) and the expected rate 'of return (from 8.75% to 8.5%) used to 'calculate benefit obligations. Entergy Arkansas contributed
$5.3 million to its pension plan in 2004, and anticipates making $20.6 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, partially offset by the Pension Funding Equity Act relief passed in April 2004.
Entergy Arkansas' accumulated benefit obligation at December 31, 2004, 2003, and 2002 exceeded plan assets. As a result, Entergy Arkansas was required to recognize an additional minimum liability as prescribed by SFAS 87 at December 31, 2004, 2003, and 2002. At December 31, 2004, Entergy Arkansas increased its additional minimum liability to $81.2 million from $54.9 million at December 31, 2003. Entergy Arkansas decreased its intangible asset for the unrecognized prior service cost to $10.3 million at December 31, 2004 from $13.3 million at December 31, 2003. Entergy Arkansas also increased the regulatory asset to $70.8 million at December 31, 2004 from $41.6 million at December 31, 2003. Net income for 2004, 2003, and 2002 was not impacted. 162
Entergy Arkansas, Inc. Managemnent's Financial Discussion and Analysis Total postretirement health care and life insurance benefit costs for Entergy Arkansas in 2004 were $12.8 million, including $5 million in savings due, to the estimated effect of future Medicare Part D subsidies. Entergy Arkansas expects 2005 postretiremenit healih care and lIfe intsuraince benefit costs to a'pproximate $13.7 million, including $5.8 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the decrease in the disc olunt rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate used to calculate benefit obligations.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders Entergy Arkansas, Inc.: ;, - We have audited the accompanying balance sheets of Entergy Arkansas, Inc. as of December 31, 2004 and 2003, and the related statements of income, retained earnings, and cash flows (pages 165 through 170 and applicable items in pages 284 through 348) for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Arkansas, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 5 and Note 8 to the notes to respective financial statements, in 2003 Entergy Arkansas, Inc. adopted the provisions of Statement of Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, and Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting. DELOITTE & TOUCHE LLP New Orleans, Louisiana March 8, 2005 164
ENTERGY ARKANSAS, INC. INCOME STATEMENTS For the Years Ended December 31, 2004 2003 2002 (In Thousands) OPERATING REVENUES Domestic electric $1,653,145 $1,589,670 $1,561,110 OPERATING EXPENSES Operation and Maintenance: Fuel, fuel-related expenses, and gas purchased for resale 210,394 153,866 294,244 Purchased power 484,849 476,447 355,211 Nuclear refueling outage expenses 24,568 23,638 24,387 Other operation and maintenance 384,424 402,108 543,677 Decommissioning 32,902 35,887 Taxes other than income taxes 35,848 37,385 38,127 Depreciation and amortization 206,926 202,497 187,525 Other regulatory credits - net (20,501) (39,347) (184,270) TOTAL 1,359,410 1,292,481 1,258,901 OPERATING INCOME 293,735 297,189 302,209 OTHER INCOME Allowance for equity funds used during construction 11,737 12,153 7,324 Interest and dividend income 10,298 9,790 2,467 Miscellaneous - net (6,354) (4,332) (6,442) TOTAL 15,681 17,611 3,349 INTEREST AND OTHER CHARGES Interest on long-term debt 79,521 87,666 89,923 Other interest - net I I 4,909 3,555 13,287 Allowance for borrowed funds used during construction (6,288) (7,726) (4,699) TOTAL 78,142 83,495 98,511 INCOME BEFORE INCOME TAXES 231,274 231,305 207,047 Income taxes 89,064 105,296 71,404 NET INCOME 142,210 126,009 135,643 Preferred dividend requirements and other 7,776 7,776 7,776 EARNINGS APPLICABLE TO COMMON STOCK $134,434 $118,233 $127,867 See Notes to Respective Financial Statements. 165
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ENTERGY ARKANSAS, INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2004 2003 2002 (In Thousands) OPERATING ACTIVITIES Net income $142,210 $126,009 $135,643 Adjustments to reconcile net income to net cash flow provided by operating activities: Reserve for regulatory adjustments 3,099 1,739 Other regulatory credits - net (20,501) (39,347) (184,270) Depreciation, amortization, and decommissioning 239,828 238,384 187,525 Deferred income taxes and investment tax credits 65,847 48,357 54,955 Changes in working capital: Receivables (86,564) (29,616) 50,898 Fuel inventory 2,424 4,159 (6,509) Accounts payable (40,871) 40,615 39,077 137,767 48,791 (69,812) Taxes accrued Interest accrued (48) (6,348) (2,772) Deferred fuel costs 6,880 (46,333) 59,849 Other working capital accounts 4,753 (79,331) (33,698) Provision for estimated losses and reserves (5,172) 8,686 (9,952) Changes in other regulatory assets 37,668 (54,745) 182,244 Other (41,022) 176,500 (45,757) Net cash flow provided by operating activities 446,298 437,520 357,421 INVESTING ACTIVITIES - - Construction expenditures (270,427) (334,556) (277,189) Allowance for equity funds used during construction 11,737 12,153 7,324 Nuclear fuel purchases (8,101) (60,685) (68,127) Proceeds from sale/leaseback of nuclear fuel 8,101 60,685 68,127 Decommissioning trust contributions and realized change in trust assets (8,860) (8i279) (17,970) Changes in other investments - net 1,856
- 38,397 Other regulatory investments (3,691) (6,827)
Net cash flow used in investing activities (269,385) (337,509) (249,438) FINANCING ACTIVITIES Proceeds from the issuance of long-term debt 59,429 361,726 188,407 Retirement of long-term debt (61,856) (471,040) (170,000) Changes in short-term borrowings (667) Dividends paid: Common stock' (85,800) (69,600) (125,900) (7,7700) ' (7,776) (7,776) Preferred stock Net cash flow used in financing activities 1.(96,003) (186,690) (115,936) Net increase (decrease) in cash and cash equivalents 80,910 (86,679) (7,953) Cash and cash equivalents at beginning of period 8,834 - 95,513 103,466 Cash and cash equivalents at end of period $89,744 $8,834 S95,513 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid/(received) during the period for Interest - net of amount capitalized $78,144 $91,142, $100,965 ($103,476) $2,177 ' ' $83,911 Income taxes Noncash investing and financing activities: Long-term debt refunded with proceeds from long-term debt issued in prior periods ($47,000) See Notes to Respective Financial Statements. 167
ENTERGY ARKANSAS, INC. BALANCE SHEETS ASSETS December 31, 2004 2003 (In Thousands) CURRENT ASSETS Cash and cash equivalents: Cash $7,133 $8,834 Temporary cash investments - at cost, which approximates market . 82,611 Total cash and cash equivalents . 89,744- 8,834 Accounts receivable: Customer 87,131 69,036 Allowance for doubtful accounts (11,039) (9,020) Associated companies 72,472 50,390 Other 72,425 30,930 Accrued unbilled revenues 71,643 64,732 Total accounts receivable 292,632 206,068 Deferred fuel costs 7,368 10,557 Accumulated deferred income taxes 27,306 18,362 Fuel inventory - at average cost 4,298 6,722 Materials and supplies - at average cost 85,076 80,506 Deferred nuclear refueling outage costs 16,485 19,793 Prepayments and other 6,154 23,938 TOTAL 529,063 374,780 OTHER PROPERTY AND INVESTMENTS Investment in affiliates - at equity 11,208 11,212 Decommissioning trust funds i 383,784 360,485 Non-utility property - at cost (less accumulated depreciation) 1,453 1,456 Other 2,976 4,832 TOTAL 399,421 377,985 UTILITY PLANT Electric 6,124,359 5,948,090 Property under capital lease 17,500 24,047 Constructiorn work in progress 226,172 238,807 Nuclear fuel under capital lease 93,855 102,691 Nuclear fuel 12,201 7,466 TOTAL UTILITY PLANT 6,474,087 6,321,101 Less - accumulated depreciation and amortization 2,753,525. 2,627,441 UTILITY PLANT - NET 3,720,562 3,693,660 DEFERRED DEBITS AND OTHER ASSETS Regulatory assets: SFAS 109 regulatory asset - net 101,658 128,311 Other regulatory assets 400,174 437,544 Other 42,514 45,798 TOTAL 544,346 611,653 TOTAL ASSETS $5,193,392 $5,058,078 See Notes to Respective Financial Statements. 168
ENTERGY ARKANSAS, INC. I* BALANCE SHEETS LIABILITIES AND SHAREHOLDERS' EQUITY December 31, 2004 2003 (In Thousands) CURRENT LIABILITIES Currently maturing long-term debt $147,000 Accounts payable: Associated companies 68,829 106,958 Other 89,896 92,638 Customer deposits 41,639 37,693 Taxes accrued 35,874 Interest accrued 21,376 21,424 Obligations under capital leases 49,816 59,089 Other 19,648 16,924 TOTAL. 474,078 334,726 NON-CURRENT LIABILITIES Accumulated deferred income taxes and taxes accrued 1,121,623. 996,455 Accumulated deferred investment tax credits 68,452 73,280 Obligations under capital leases 61,538 67,648 Other regulatory liabilities 67,362 52,923 Decommissioning 492,745 567,546 Accumulated provisions 34,977 40,149 Long-term debt 1,191,763 1,338,378 Other 237,447 192,200 TOTAL 3,275,907 3,328,579 Commitments and Contingencies SHAREHOLDERS' EQUITY Preferred stock without sinking fund 116,350 116,350 Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 2004 and 2003 470 470 Paid-in capital 591,127 591,127 Retained earnings 735,460 686,826 TOTAL 1,443,407 1,394,773 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $5,193,392 $5,058,078 See Notes to Respective Financial Statements. 169
ENTERGY ARKANSAS, INC. STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 2004 2003 2002 (In Thousands) Retained Earnings, January I $686,826 $638,193 $636,226 Add: Net income 142,210 126,009 135,643 Deduct: Dividends declared: Preferred stock 7,776 7,776 7,776 Common stock 85,800 69,600 125,900 Total 93,576 77,376 133,676 Retained Earnings, December 31 $735,460 $686,826 $638,193 See Notes to Respective Financial Statements. 170
ENTERGY ARKANSAS, INC. SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 2004 2003 2002 2001 2000 (In Thousands) Operating revenues $1,653,145 $1,589,670 $1,561,110 $1,776,776 $1,762,635 Net Income $142,210 $126,009 $135,643 $178,185 $137,047 Total assets $5,193,392 $5,058,078 $4,569,511 $4,451,580 $4,228,211 Long-term obligations (1) $1,253,301 $1,406,026 $1,246,567 $1,417,262 $1,401,062 (1) Included long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. 2004 2003 2002 2001 2000 (Dollars In Millions) Electric Operating Revenues: Residential $539 $526 $556 $586 $561 Commercial 305 291 304 330 307 Industrial 318 305 330 371 353 Governmental 16 15 16 15 Total retail 1,178 1,137 1,205 1,303 1,236 Sales for resale: Associated companies 250 234 165 240 246 Non-associated companies 186 188 164 201 235 Other 39 31 27 33 46 Total $1,653 $1,590 $1,561 $1,777 $1,763 Billed Electric Energy Sales (GWh): Residential 7,028 7,057 7,050 6,918 6,791 Commercial 5,428 5,328 5,221 5,162 5,063 Industrial 7,004 6,999 -7,074 7,052 7,240 Governmental 275 266 255 245 239 Total retail 19,735 19,650 19,600 19,377 19,333 Sales for resale: Associated companies 7,437 7,036 6,811 7,217 6,513 Non-associated companies 4,911 5,399 - 5,069 4,909 5,537 Total 32,083 32,085 31,480 31,503 31,383 171
ENTERGY GULF STATES, INC.. - MIANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS Results of Operations Net Income 2004 Compared to 2003 Net income increased $149.7. million primarily due to the following:
- the $107.7 million accrual ($65.6 million net-of-tax) in June 2003 for the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. See Note 2 to the domestic utility companies and System Energy financial statements for more details regarding the River Bend abeyed plant costs; - - '
- the $21.3 million net-of-tax cumulative effect of accounting change in 2003 due to the implementation of SFAS 143. See "Critical Accounting Estimates" below for more information on the implementation of' SFAS 143;
- an increase if $39.7 million (pre-tax) in net revenue, as discussed below;
- miscellaneous income of $27.7 million (pre-tax) resulting from a revision of the decommissioning liability for River Bend and of $10 million (pre-tax) resulting from a reduction in the loss provision for an environmental clean-up site, both of which occurred in 2004 and are discussed below;
- a decrease of $23.2 million (pre-tax) in interest charges on long-term debt, as discussed below; and
- a decrease of $12.0 million (pre-tax) in other operation and maintenance expenses, as discussed below.
The increase was partially offset by a higher effective income tax rate. 2003 Compared to 2002 Entergy Gulf States experienced a significant decline in net income in 2003 compared to 2002 primarily due to the following:
* ' the $107.7 million accrual ($65.6 million net-of-tax) for the loss that would be associated with a final, nonappealable decision disallowing abeyed River Bend plant costs. See Note 2 to the domestic utility companies and; System Energy financial statements for more details regarding the River Bend abeyed plant costs; .
- the $21.3 million net-of-tax cumulative effect of accounting change due to the implementation of SFAS 143.
See "Critical Accounting Estimates" below for more information on the implementation'of SFAS 143;
- a decrease of $20.6 million (pre-tax) in net revenuej as discussed below; and '
- an increase of $19.2 million (pre-tax) in other operation and maintenance expenses, as discussed below.
The decrease was partially offset by a lower effective income tax rate. Net Revenue 2004 Compared to 2003 Net revenue, which is Entergy Gulf States' measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2004 to 2003. 1*7'
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis (In Millions) 2003 net revenue $1,110.1 Volume/weather 26.7 Net wholesale revenue 13.0 Summer capacity charges 5.5 Price applied to unbilled sales 4.8 Fuel recovery revenues (14.2) Other V 3.9 2004 set revenue $1,149.8 The volume/weather variance resulted primarily from an increase of 1,179 GWh in electricity usage in the industrial sector. Billed usage also increased a total of 291 GWh in the residential, commercial, and governmental sectors.; The increase in net wholesale revenue is primarily due to an increase in sales volume to municipal and co-op customers. Summer capacity charges variance is due to the amortization in 2003 of deferred capacity charges for the summer of 2001 compared to the absence of the amortization in 2004. The amortization of these capacity charges began in June 2002 and ended in May 2003. The price applied to unbilled sales variance resulted primarily from an increase in the fuel price applied to unbilled sales. Fuel recovery revenues represent an under-recovery of fuel charges that are recovered in base rates. Entergy Gulf States recorded $22.6 million of provisions in 2004 for potential rate refunds. These provisions are not included in the Net Revenue table above because they are more than offset by provisions recorded in 2003. Grossoperatingrevenuesfel andpurchasedpowerexpenses, and other regulatorycredits Gross operating revenues increased primarily due to an increase of $187.8 million in fuel cost recovery revenues as a result of higher -fuel rates in both the Louisiana and Texas jurisdictions. The increases in volume/weather and wholesale revenue, discussed above, also contributed to the increase. Fuel and purchased power expenses increased primarily due to:
- increased recovery of deferred fuel costs due to higher fuel rates;
- increases in the market prices of natural gas, coal, and purchased power; and
- an increase in electricity usage, discussed above.
Other regulatory credits increased primarily due to the amortization in 2003 of deferred capacity charges for the summer of 2001 compared to the absence of amortization in 2004. The amortization of these charges began in June 2002 and ended in May 2003. 2003 Compared to 2002 Net revenue, which is Entergy Gulf States' measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2003 to 2002. 173
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis (In Millions) 2002 net revenue $1,130.7 Volume/weather 17.8 Fuel write-offs in 2002 15.3 Net wholesale revenue 10.2-Base rate decreases (23.3), NISCO gain recognized in 2002 , (15.2), Rate refund provisions (11.3) Other (14.1) 2003 net revenue $1,110.1 The volume/weather variance was due to higher electric sales volume in the service territory. Billed usage increased a total of 517 GWh in the residential and commercial sectors. The increase was partially offset by a decrease in industrial usage of 470 GWh due to the loss of two large industrial customers to cogeneration. The customers accounted for approximately 1% of Entergy Gulf States' net revenue in 2002. In 2002, deferred fuel costs of $8.9 million related to a Texas fuel reconciliation case were written off and $6.5 million in expense resulted from an adjustment in the deregulated asset plan percentage as the result of a power uprate at RiverBend. . i The increase in net wholesale revenue was primarily due to an increase in sales volume to municipal and co-op customers and also to affiliated systems related to Entergy's generation resource planning.. The base rate decreases were effective June 2002 and January 2003, both in the Louisiana jurisdiction. The January 2003 baseratedecrease of $22.1 million had a, minimal impact on net income due tona corresponding reduction in nuclear depreciation and decommissioning expenses associated with the change in accounting to reflect an assumed extension of River Bend's useful life. ; , In 2002, a gain of $15.2 million was recognized for the Louisiana portion of the 1988 Nelson Units 1 and 2 sale. Entergy Gulf States received approval from the LPSC to discontinue applying amortization of the gain against recoverable fuel, resulting in the recognition of the deferred gain in income. t6 ' .t ! I . . ! A 1. 1 : . . . t . .- . Rate refund provisions caused a decrease in net revenue due to additional provisions recorded in 2003 compared to 2002 for potential rate actions and refunds. ,,- , Gross operatingrevenues andfuel andpurchasedpower expenses Gross operating revenues increased, primarily due to an increase of $440.2 million in fuel cost, recovery revenues as a result of higher fuel rates in both the Louisiana and Texas Jurisdictions. Fuel and purchased power expenses increased $471.1 million due to an increase in the market prices of natural gas and purchased power. , . Other Income Statement Variances 2004 Compared to 2003 Other operation and maintenance expenses decreased primarilydueto:
- voluntary severance program accruals of $22.5 million in 2003, and
- a decrease of $4.3 million in nuclear material and labor costs due to reduced staff in 2004.
174
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis The decrease was partially offset by the following:
- an increase of $8.5 million in benefit costs; and -
- an increase of $5 million in customer service support costs.
Miscellaneous income - net increased $145.6 million primarily due to:
- the $107.7. million accrual in June 2003 for the loss that would be associated with a final, non-appealable decision disallowing abeyed River Bend plant costs. See Note 2 to the domestic utility companies and System Energy financial statements for more details regarding the River Bend abeyed plant costs;
- the River Bend decommissioning cost liability revision made in accordance with a new decommissioning cost study that reflected an expected life extension for the plant. For the portion of River Bend not subject to cost-based ratemaldng, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7
.million;and
- a'reduction of approximately $10 million in the loss provision related to an environmental clean-up site.
Interest on long-term debt decreased $23.2 million primarily dueto the financing and debt restructuring program implemented in 2003, which resulted in extended maturities and lower interest rates in Entergy Gulf States' debt portfolio. 2003 Compared to 2002 , Other operation and maintenance expenses increased primarily due to voluntary severance accruals of $22.5 million in 2003. Decommissioning expense increased primarily due to the implementation of SFAS 143. The increase in decommissioning expense was offset by increases in other regulatory credits and interest and dividend income and has no effect on net income. , , ; - Depreciation and amortization expenses decreased primarily due to decreased rates associated with the assumed life extension of River Bend, partially offset by higher depreciation due to an increase in plant in service. The decrease in depreciation, related to the assumed license extension of River Bend has a minimal impact on net income because it was offset by the January 2003 base rate decrease discussed in "Net Revenue" above. Other income decreased primarily due to the abeyed River Bend plant cost accrual discussed above. Interest expense on long-term-debt increased primarily due to the issuance of $340 million of First Mortgage Bonds in November 2002, $600 million in June 2003, and, $440 million in July 2003, partially offset by the retirement of $293 million of First Mortgage Bonds in March 2003 and $745 million in the third quarter of 2003. Income Taxes .. - The effective income tax rates for 2004, 2003, and 2002 were 36.0%, 21.3%, and 27.5%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35% to the effective income, tax rate. Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet. 7 5 . *
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Entergy Gulf States, Inc. Management's Financial Discussion and Analysis Liquiditv and Capital Resources Cash Flow Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows: 2004 2003 2002
; (In Thousands)
Cash and cash equivalents at beginning of period $206,030 $318,404 $123,728
-Cash flow provided by (used in):
Operating activities 649,458 425,963 500,654 Investing activities, (389,344) ;(446,639) (351,456) Financing activities (459,170) (91,698) 45,478
. Net increase (decrease) in cash and cash equivalents : (199,056) (112,374) 194,676 Cash and cash equivalents at end of period - $6,974 $206,030 $318,404
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Operating Activities Cash flow from operations increased $223.5 million in 2004 compared to 2003 primarily due to money pool activity. Decreased vendor payments, increased recovery of deferred fuel costs, and lower interest payments also contributed to the increase. In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations 'of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $674 million deduction for Entergy Gulf States on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004 Entergy Gulf States realized $69 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS oil audit. As of December 31, 2004, Entergy Gulf States has a net operating loss (NOL) carryforward for tax purposes of $447.5 million, principally resulting from the' change in tax accounting method related to cost of goods sold. If the tax accounting method change is sustained, Entergy Gulf States expects to utilize the NOL carryforward through 2006. Cash flow from operations decreased $74.7 million in 2003 compared to 2002 primarily due to money pool activity, higher working capital needs, and increased vendor payments in 2003 relating to storm expense accruals in late-2002. The decrease was partially offset by lower income tax payments. Entergy Gulf States' receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years: 2004 - 2003 2002 2001
*r J : ., , . t (In Thousands),
($59,720) $69,354 $18,131 $27,665 Money pool activity provided $129.1 million of Entergy Gulf States' operating cash flows in 2004, used $51.2 million in 2003, and provided $9.5 million in 2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool. Investing Activities Net cash used in investing activities decreased $57.3 million in 2004 compared to 2003 primarily due to the maturity in 2004 of $23.6 million of other temporary investments that had been made in 2003, which provided cash 176
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis in 2004. Also contributing to the decrease was a $27.2 million decrease in under-recovered fuel and purchased power expenses in Texas that have been deferred and !are expected to be collected over a period greater than twelve months. See Note 1 to the domestic utility companies and System Energy financial statements for further discussion of the accounting for fuel costs. Net cash used in investing activities increased $95.2 million in 2003 compared to 2002 primarily due to an increase of $23.6 million in other temporary investments in 2003 compared to the maturity of $44.6 million of other temporary investments that provided cash in 2002. The increase was also due to an increase of $37.7 million in under-recovered fuel and purchased power expenses in Texas that have been deferred and are expected to be collected over a period greater than twelve months. See Note 1 to. the domestic utility companies and System Energy financial statements for further discussion of the accounting for fuel costs. Financing Activities Net cash used in financing activities increased $367.5 million in 2004 compared to 2003 primarily due to the net reduction of $357 million of long-term debt in 2004 compared to $15.4 million in 2003 as well as an increase of $26.2 million in common stock dividends paid. Entergy Gulf States used $91.7 million of cash in financing activities in 2003 compared to providing $45.5 million of cash in 2002 primarily due to the net reduction of $15.4 million of long-term debt in 2003 compared to the net issuance of $143.4 million of long-term debt in 2002. The increase in cash used in financing activities was partially offset by a decrease of $23.1 million in common stock dividends paid. See Note 5 to the domestic utility companies and System Energy financial statements for details on long-term debt., Uses of Capital Entergy Gulf States requires capital resources for:
- construction and other capital investments;
- debt and preferred stock maturities;
- working capital purposes, including the financing of fuel and purchased power costs; and
- dividend and interest payments.
.. Followingare the amounts of Entergy Gulf States' planned construction and other capital investments, existing debt and lease obligations, and other purchase obligations:
2005 2006-2007 2008-2009 after 2009 Total (In Millions) Planned construction and capital investment (1) $275 $505 N/A N/A $780 Long-term debt $98 - $550 $1,341 $1,989 Operating leases $27 $41 $19 $115 $202 Purchase obligations (2) $164 $78 $6 - $21 $269 Other long-term liabilities $3 $7 - $7 - $17 Nuclear fuel lease obligations (3) $33 $38 , N/A N/A $71 (1) Includes approximately $210 to 220 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. (2) Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services: For Entergy Gulf States it primarily includes unconditional fuel and purchased power obligations. (3) It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, 177
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, the lessee in each case must repurchase sufficient nuclear, fuel to allow the lessor to meet its obligations. -
! , ' ' i In addition to these contractual obligations, Entergy Gulf States expects to contribute $18.9 million to its pension plans and $14.3 million to other postretirement plans in 2005.
The planned capital investment estimate for Entergy Gulf States reflects. capital required to support existing business and customer growth. The estimated capital- expenditures are subject to periodic review and modification and may vary based'on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, business restructuring, and the ability, to access capital.. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the domestic utility companies and System Energy financial statements. In addition to the purchase obligations presented in the table above, Entergy Gulf States expects to have an obligation to; purchase' power, from the Perryville power plant. In January, 2004, Entergy Louisiana signed a definitive agreemeht to acquire the 718 MW Perryville power plant for $170 million. The agreement has subsequently been amended to allow the current plant owner to retain the interconnection facilities associated with the plant, resulting in a decrease in the acquisition price to $162 million. As a result of the amended terms, the FERC issued an order in October 2004 disclaiming jurisdiction over the acquisition. This order currently is subject to rehearing by the FERC. The plant is owned by a subsidiary of Cleco Corporation, which subsidiary submitted a bid in response to Entergy's Fall 2002 request-'for proposals.for supply-side resources. The signing of the agreement followed a voluntary Chapter 11 bankruptcy filing by the plant's owner. Entergy expects that Entergy Louisiana will own 100 percent of the Perryville plant, and that Entergy Louisiana will sell 75 percent of the output to Entergy Gulf States under a long-term cost-of-service power purchase agreement. In addition,-EntergyLouisiana and Entergy Gulf States executed an interim power purchase agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by December 2005) for 100 percent of the output of the Perryville power plant. In April 2004, the bankruptcy court approved Entergy Louisiana's agreement to acquire. the'plant. In March 2004, Entergy Gulf States and Entergy Louisiana filed with the LPSC for its approval of the acquisition and long-term cost-of-service power purchase agreement. Entergy is seeking approval from the LPSC' of cost recovery for the acquisition, giving consideration to the need for the power and the prudence, of Entergy Louisiana and Entergy Gulf States in engaging in the transaction. Hearings are scheduled for March 2005. 'Assuming' regulatory approval by the LPSC, Entergy Louisiana expects the Perryville acquisition to close in mid-2005. As a wholly-owned subsidiary, Entergy Gulf States pays dividends to Vntergy Corporation fromfits earnings at a percentage determined monthly. Entergy Gulf States is restricted by long-term debt indentures in the payment of cash dividehds or -other distributions on its commoi and preferred st6ck. Currently, all' of Entergy'Gulf States' retained earnings are available for distribution. Sources of Capitat Entergy Gulf States' sources to meet its capital requirements include:
- internally generated funds;
-* cash on hand;
- debt or preferred stock issuances; and
- bank financing under new or existing facilities.
The following table lists First Mortgage Bonds issued by Entergy Gulf States in 2004:"
-. IIssue Date' Description ' . Maturity 'Amount-,
. *I (In Thousands)
October 2004 4.875% Series - . November 2011 $200,000 I November 2004 Libor + 0.4% Series December,2009 225,000 November 2004 5.6% Series December 2014 !, 0,000
' ' I- $475,000 178
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis The following table lists First Mortgage Bonds retired by Entergy Gulf States in 2004: Retirement Date Description Maturity Amount (In Thousands) April 2004 8.25% Series April 2004 $292,000 December 2004 Libor + 0.9% Series June 2007 275,000 December 2004 5.2% Series December 2007 200,000
$767,000 Entergy Gulf States may refinance or redeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
In addition, in September 2004, Entergy Gulf States purchased its $62 million 5.65% Series tax-exempt bonds from the holders, pursuant to a mandatory tender provision, and has not remarketed the bonds at this time. All debt and common and preferred stock issuances by Entergy Gulf States require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in its corporate charter, bond indentures, and other agreements. Entergy Gulf States has sufficient capacity under these tests to meet its foreseeable capital needs. Borrowings and securities issuances by Entergy Gulf States are limited to amounts authorized by the SEC. The current short-term borrowing limitation, including borrowings under the money pool, is $340 million. Under its SEC Orders and without further SEC authorization, Entergy Gulf States cannot incur additional indebtedness or issue other securities unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy Gulf States (other than its preferred stock), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Gulf States' short-term borrowing limits. Significant Factors and Known Trends Transition to Retail Competition Texas As ordered by the PUCT, in January 2003, Entergy Gulf States filed its proposal for an interim solution (retail open access without a FERC-approved RTO), which among other elements, included:
- the recommendation that retail open access in Entergy Gulf States' Texas service territory, including corporate unbundling, occur by January 1, 2004, or else be delayed until at least January 1,2007. If retail open access is delayed past January 1,2004, Entergy Gulf States seeks authorization to separate into two bundled utilities, one subject to the retail jurisdiction of the PUCT and one subject to the retail jurisdiction of the LPSC.
- the recommendation that Entergy's transmission organization, possibly with the oversight of another entity, will continue to serve as the transmission authority for purposes of retail open access in Entergy Gulf States' service territory.
- the recommendation that the decision points be identified that would require prior to January 1,2004, the PUCT's determination, based upon objective criteria, whether to proceed with further efforts toward retail open access in Entergy Gulf States' Texas service territory.
After considering the proposal, in an April 2003 order the PUCT set forth a sequence of proceedings and activities designed to initiate an interim solution. These proceedings and activities included initiating a proceeding to certify an independent organization to administer market protocols and ensure nondiscriminatory access to transmission and distribution systems. 179
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis In July 2004 the PUCT denied Entergy's application to certify Entergy's transmission organization as an independent organization under Texas law. In its order, the PUCT also ordered: the cessation of efforts to develop an interim solution for retail open access in Entergy Gulf States' Texas service territory, termination of the pilot project in that territory, and a delay in retail open access in that territory until either a FERC-approved RTO is in place or some other independent transmission entity is certified under Texas law. Several parties have appealed the termination of the pilot program aspect of the order, claiming the issue was not properly a part of the proceeding.' In February 2005, bills were submitted in the Texas Legislature that would clarify that Entergy Gulf States is no longer subject to a rate freeze and specify that retail open access will not commence in Entergy Gulf States' Texas service territory until the PUCT certifies a power region. Louisiana In November 2001, the LPSC decided not to move forward with retail open access for any customers at this time. The LPSC instead directed its staff to hold collaborative group meetings concerning open access from time to time, and to have the LPSC staff monitor developments in neighboring states and to report to the LPSC regarding the progress of retail access developments in those states. In September 2004, in response to a study funded by certain industrial customers that evaluated a limited industrial-only retail choice program, the LPSC asked the LPSC staff to solicit comments and obtain information from utilities, customers, and other interested parties concerning the potential costs and benefits of a limited choice program, the impact of such a program on other customers, as well as issues such as stranded costs and transmission service. Comments from interested parties were filed with the LPSC on January 14, 2005. The LPSC has not established a procedural framework for consideration of the comments. At this time, it is not certain what further action, if any, the LPSC might take in response to the information it received. Jurisdictional Separation Plan , Pursuit of Entergy Gulf States' business separation plan mandated by Texas law in connection with retail open access in the Texas service territory has been complicated by the existence of retail operations in Louisiana subject to the jurisdiction of the LPSC. During the course of Entergy Gulf States' retail open access proceedings with the PUCT, the LPSC has been holding independent proceedings concerning the proposed separation of Entergy Gulf States' business. Unlike the plan filed with the PUCT in 2000 (and amended through 2001), discussed below, to separate Entergy Gulf States' Texas generation, transmission, distribution, and retail electric functions into separate companies, the investigation recently initiated in the LPSC proceedings is evaluating a jurisdictional split of Entergy Gulf States into a Louisiana company and a Texas company. In a status conference held in September 2004 before an ALJ, the LPSC staff asserted that uncertainty with respect to retail open access in Texas should not control whether or when the LPSC should require the jurisdictional separation of Entergy Gulf States and recommended that an investigation concerning the proposed-jurisdictional separation proceed. Entergy Gulf States submitted a preliminary methodology developed by Entergy for the jurisdictional separation of Entergy Gulf States if the regulators should determine that a jurisdictional separation is in the public interest. Although it contains many components that are similar to those set forth in the business separation plan filed with the PUCT, the preliminary methodology filed with the LPSC provides for the separation of Entergy Gulf States into a Louisiana vertically integrated utility company and a' Texas vertically integrated utility company;* ratherthan the separation of Entergy Gulf States' Texas generation, transmission, distribution, and retail electric' functions into separate companies as is envisioned in the plan filed with the PUCT. A procedural schedule was established in the status conference that sets discovery through February 2005, testimony through the first half of June 2005, and a hearing beginning later in June 2005. Approvals of the FERC, the SEC, the PUCT, and the NRC may also be required for certain matters before any implementation of the jurisdictional separation of Entergy Gulf $tates. Business Separation Plan under the Texas Retail Open Access Law Entergy Gulf States' business separation plan for Texas retail open access developed pursuant to the Texas restructuring law provides for the separation of its generation, transmission, distribution, and retail electric functions into separate companies. It has been amended during the course of various PUQT and LPSC proceedings and is subject to further change and regulatory proceedings. Entergy Gulf States filed the business separation plan with the 180
Entergy Gulf States, In3. Management's Financial Discussion and Analysis PUCT in January 2000 and amended that plan in June and November 2000 and January 2001. In July 2000, 'the PUCT approved the amended business separation plan in an interim order. In December 2001, the PUCT abated the proceeding and indicated it will consider a final order in a timely manner consistent with a settlement agreement delaying retail open access. The outcome of the LPSC proceedings described below, which have resulted in amendments to the plan beyond what was approved by the PUCT, have been and will continue to be reported to the PUCT and the Office of Public Utility Counsel and may require additional PUCT action before the business separation plan could become final. The LPSC opened a docket to identify the changes in corporate structure and operations of Entergy Gulf States, and their potential impact on Louisiana retail ratepayers, resulting from restructuring in Texas. In those proceedings, Entergy Gulf States and the LPSC staff reached a settlement on certain Texas business separation plan issues, and after a May 2001 hearing, the LPSC issued an interim order in July 2001 approving the settlement. In July 2001, Entergy Gulf States and the LPSC Staff completed an additional settlement on business separation plan issues relating to the separation of Texas distribution and transmission. A hearing on the distribution and transmission settlement was held and the LPSC approved the settlement in September 2001. Issues related to the separation of generation are still unresolved. The plan approved by the LPSC in September 2001 provides that Entergy Gulf States will be separated into the following principal companies if retail open access were to commence in Texas:
- a Texas distribution company, which will own and operate Entergy Gulf States' electric distribution system in Texas;
- an intermediate transmission company;
- a Texas generation company (which may be more than one legal entity), which initially will purchase capacity and energy from the generating assets allocated to Texas load (Texas generating assets), and eventually will own those assets;
- Texas retail electric providers, which will provide competitive retail electric service in Texas; and
- Entergy Gulf States-Louisiana.
Pursuant to the LPSC-approved plan, Entergy Gulf States-Louisiana would:
- own and operate Entergy Gulf States' electric distribution system in Louisiana, the Texas generating assets (until they are transferred to the Texas generation company), the remainder of Entergy Gulf States' generating assets, and Entergy Gulf States' other businesses that are not separated, and own Entergy Gulf States' transmission assets allocated to Louisiana (until they are transferred to the intermediate transmission company described in the next bullet); and
- indirectly own a portion of an intermediate transmission company, which will own Entergy Gulf States' electric transmission assets allocated to Texas, and later Entergy Gulf States' transmission assets allocated to Louisiana.
System Agreement Proceedings The domestic utility companies historically have engaged in the coordinated planning, construction, and operation of generating and transmission facilities under the terms of an agreement called the System Agreement that has been approved by the FERC. Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies in their execution of the System Agreement, and seek support for local regulatory authority over System Agreement issues. In February 2004, a FERC ALJ issued an Initial Decision in the LPSC-initiated proceeding at the FERC. The Initial Decision decided some issues in favor of the relief sought by the LPSC, and decided some issues against the relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALJ's Initial Decision. Entergy's exceptions to the ALJ's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource 181
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement;, the Initial Decision's remedy ignores the historical pattern of production cost disparities-on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method. If the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average. If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The AL's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companieswhose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost. An assessment of the potential effects of the AL's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of, natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entery Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43ImmBtu during the ten-year period 1995-2004 and $4.58/mmBtu duringthe five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85lmmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the AL's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could resultassuming annual average gas prices range from $6.39/mmBtu in 2005 declining td $4.97/mmBtu by 2009: Average Annual Range of Annual Payments Payments or (Receipts) or (Receipts) for 2005-2009 Period (In Millions) (In Millions) Entergy Arkansas , $154 to $281 $215 Entergy Gulf States ($130) to ($15) ($63) Entergy Louisiana ($199) to ($98) ($141) Entergy Mississippi ($16) to $8 $1 Entergy New Orleans ($17) to ($5) ($12) Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similFr rate changes for retail customers. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy Gulf States does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation. 182
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC AL's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its. high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the ALUs Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; and states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate. In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the AL's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations. In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Louisiana, as well as the named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity. The LPSC instituted a companion ex-parte System Agreement investigation to litigate several of the System Agreement issues that the LPSC is litigating before the FERC in the previously discussed System Agreement proceeding. This companion proceeding will require the LPSC to interpret various provisions of the System Agreement, including those relating to minimum-run and must-run units, the propriety of the methods used for billing and dispatch on the Entergy System, and the use of a rolling, twelve-month average of system peaks for allocating certain costs. In addition, by this companion proceeding the LPSC is questioning whether Entergy Louisiana and Entergy Gulf States were prudent for not seeking changes to the System Agreement previously, so as to lower costs imposed upon their ratepayers and to increase costs imposed upon ratepayers of other domestic utility companies. The LPSC -staff has filed testimony suggesting that the remedy for the alleged imprudence of Entergy Louisiana and Entergy Gulf;States should be a reduction in allowed rate of return on common equity of 100 basis points. The domestic utility companies have challenged the propriety of the LPSC's litigating System Agreement issues. Nevertheless, on January 16, 2002 the LPSC affirmed a decision of its AU upholding the LPSC staffs right to litigate System Agreement issues at the LPSC, rather than before the FERC. The procedural schedule is suspended at this time and an evidentiary hearing is not scheduled. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting FERC rate schedules that are part of the System Agreement, and from subsequently enforcing that interpretation. The LPSC interpreted a System Agreement rate schedule in the unrelated case, and then sought to enforce its interpretation. The 183
Entergy Gulf States, Inc. Managements Financial Discussion and Analysis Louisiana Supreme Court affirmed. In 2003, the U.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the decisions of the LPSC and the Louisiana Supreme Court. t Transmission In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs. In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the 'ICT broad oversight authority over transmission planning and operations. Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences.' In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff, and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. I The petition also indicates that, subject to the outcome of the petition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become' a "public utility" or "tranismission provider and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005. ' In,March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General' Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT'proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an applicationiwith the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a' separate hearing on theWPP 184
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis portion of the proposal currently scheduled for August 2005. -. Interconnection Orders The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to, connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos, including $28 million for Entergy Gulf States. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy. To the extent the Entergy companies are ,ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates., The recovery of these costs is not automatic, however, especially at the retail level,: where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators. Available Flowgate Capacity Proceeding On December 17, 2004, the FERC issued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission, service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised in a FERC audit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC program, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory. Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy. Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the AFC proceeding is currently scheduled to commence in August 2005. State and Local Rate Regulatory Risks The rates that Entergy Gulf States charges for its services are an important item influencing its financial position, results of operations, and liquidity. Entergy Gulf States is closely regulated and the rates charged to its customers are determined in regulatory proceedings, except for a portion of its operations. Governmental agencies, the LPSC and the PUCT, are primarily responsible for approval of the rates charged to customers. Entergy Gulf States is operating in Texas under the terms of a December 2001 settlement agreement approved by the PUCT. -The settlement provided for a base rate freeze that has remained in effect during the delay in the implementation of retail open access in Entergy Gulf States' Texas service territory. In view of the PUCT order in 185
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis July 2004 to further delay retail open access in the Texas service territory, Entergy Gulf States filed a retail electric rate case and fuel reconciliation proceeding with the PUCT in August 2004 seeking the following:
- approval of a base rate increase of $42.6 million annually for the Texas retail jurisdiction;
- approval to implement a $14.1 million per year rider to recover, over a 15-year period, $110.9 million of incurred costs related to its efforts to transition to a competitive retail market in accordance with the Texas restructuring law;
- approval to implement a proposed $11.3 million franchise fee rider to recover payments to municipalities charging such fees; and
- a requested return on equity of 11.5%.
In addition, Entergy Gulf States' fuel reconciliation filing made in conjunction with the base rate case sought'to reconcile approximately $288 million in fuel and purchased power costs incurred during the period September 2003 through March 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case and fuel reconciliation proceeding indicating that Entergy Gulf States is still subject to a rate freeze based on an agreement, approved by PUCT order in 2001, stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless the rate freeze is lifted by the PUCT prior thereto. Entergy Gulf States believes the PUCT has misinterpreted the settlement and has appealed the PUCT order to the Travis County District Court and intends to pursue other available remedies. Dismissal of Entergy Gulf States' rate case does not preclude it from seeking recovery of the transition to competition costs when the rate freeze is no longer in effect. ' Similarly,' the dismissal of the rate case does not preclude Entergy Gulf States from seeking the reconciliation of fuel and purchased power costs of $288 million for the period September 2003 through March 2004 when, at the appropriate time, similar costs are reconciled in the future. As discussed above, in February 2005, bills were submitted in the Texas Legislature that would clarify that Entergy Gulf States is no longer subject to a rate freeze and specify that retail open access will not commience in Entergy Gulf States' Texas service territory until the PUCT certifies a power region. In September 2004, the LPSC consolidated various dockets that were the subject of settlement discussions between the LPSC staff and Entergy Gulf States and Entergy Louisiana. The LPSC directed its staff to continue the settlement discussions and submit any proposed settlement to the LPSC for its consideration. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement that currently includes an'offer to refund $76 million to Entergy Gulf States' Louisiana customers, with no immediate change in current base rates. If the LPSC approves the proposed settlement, Entergy Gulf States will be'regulated under a three-year formula rate plan that, among other provisions, establishes' a ROE mid-point of 10.65% and permits Entergy Gulf States to recover incremental capacity costs without filing a traditional base rate proceeding. The settlement resolves all issues in, and will result in the dismissal of, Entergy Gulf States' fourth, fifth, sixth, seventh, and eighth annual earnings reviews, Entergy Gulf States' ninth post-merger earnings review and revenue requirement analysis, a fuel review for Entergy Gulf States, dockets established to consider issues concerning power purchases for both Entergy Gulf States and Entergy Louisiana for the summers of 2001, 2002, 2003, and 2004, and a'docket concerning retail issues arising under the Entergy System Agreement. The settlement does not include the System Agreement case pending at FERC. The LPSC has solicited comments on the' proposed settlement from the parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005. Refer to Note 2 to the domestic utility and System Entergy financial statements for details of the proceedings included in the proposed settlement. In July 2004, Entergy Gulf States filed with the LPSC an application for a change in its gas base rates and charges seeking an increase of $9.1 million. Entergy Gulf States also is'seeking approval of certain proposed rate design, rate schedule, and policy changes. Discovery is underway, and a decision is expected during the third quarter of 2005. In addition to rate proceedings, Entergy Gulf States' fuel costs recovered from customers are subject to regulatory scrutiny. Entergy Gulf States' retail rate matters and proceedings, including fuel cost recovery-related issues, are discussed in Note 2 to the domestic utility companies and System Energy financial statements: ' 186
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis Industrial, Commercial, and Wholesale Customers Entergy Gulf States' large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Gulf States' industrial customer base. Entergy Gulf States responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Despite these actions, Entergy Gulf States expects to lose one large industrial customer to cogeneration in 2005. Current sales-to that 'customer account for approximately $12 million of Entergy Gulf States' net revenue annually. Entergy Gulf States actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Gulf States does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Gulf States' marketing efforts in retaining industrial customers. - Market and Credit Risks Entergy Gulf States has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Interest Rate and Equity Price Risk - Decommissioning Trust Funds Entergy Gulf States' nuclear decommissioning trust funds expose it to fluctuations in equity prices and interest rates. The NRC requires Entergy Gulf States to maintain trusts to fund the costs of decommissioning River Bend. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the River Bend trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 12 to the domestic utility companies and System Energy financial statements. Nuclear Matters Entergy Gulf States owns and operates, through an affiliate, the River Bend nuclear power plant. Entergy Gulf States is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling, and disposal of high-level and low-level radioactive materials, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of River Bend, Entergy Gulf States may be required to provide additional funds or credit supportto satisfy regulatory requirements for decommissioning. Environmental Risks, Entergy Gulf States' facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Gulf States is .in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated. Litigation Risks The states of Louisiana and Texas in which Entergy Gulf States operates have proven to be unusually litigious environments. Judges and juries in these states fhave demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy Gulf 187
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis States uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment in these states poses a business risk. Critical Accounting Estimates ' The preparation of Entergy Gulf States' financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy Gulf States' financial position or results of operations. Nuclear Decommissioning Costs Regulations require Entergy Gulf States to decommission the River Bend nuclear power plant after the facility is taken out of service, and money is collected and deposited in trust funds during the facility's operating life in order to provide for this obligation. Entergy Gulf States conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be, incurred to decommission the facility. The following key assumptions have a significant effect on these estimates:
- Cost Escalation Factors - Entergy Gulf States' decommissioning study includes an assumption that decommissioning costs will escalate over present cost levels by an annual factor averaging approximately CPI-U to 4.5%. A 50 basis point change in this assumption could change the ultimate cost of.
decommissioning a facility by as much as. 11%.
- Timing - The date of the plant's retirement must be estimated and an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore" status for later decommissioning, as permitted by applicable regulations. While the effect of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can possibly decrease the present value of these obligations. As discussed in Note 8 to the domestic utility companies and System Energy financial statements, Entergy Gulf States recorded revisions in 2004 to its estimated decommissioning cost liability for River Bend to reflect changes in assumptions regarding license renewal. Under these license renewal assumptions,'decomnmiissioninig of nuclear plants is assumed to occur at a date later than the original license expiration, thereby lowering the estimate of the decommissioning cost liability. The revised license renewal assumptions for the unregulated portion of Entergy Gulf States increased income in 2004 by $17 million net-of-tax for the excess of the reduction in the liability over the amount of undepreciated asset retirement cost at the time of adoption of SFAS 143. For the regulated portion of Entergy Gulf States, the revised assumptions'had no effect on net income because, as discussed further below, any amounts recorded related to SFAg- 143 are offset by the recording of regulatory assets or regulatory liabilities when projected decommissioning costs are collected in rates. Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will affect net income for the unregulated portion of Entergy Gulf States. Any increase in the liability recorded due to such changes are capitalized and depreciated over the asset's remaining economic life in accordance with SFAS 143.
- Spent Fuel Disposal - Federal regulations require the DOE to provide a permanent repository for the storage of spent nuclear fuel, and legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. Until this site is available, however, nuclear plant'operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities can have a significant effect (as much as 16% of estimated decommissioning costs). Entergy Gulf States' '
decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timting of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
- Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost 188
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. Entergy Gulf States' decommissioning cost studies assume current technologies and regulations. Entergy Gulf States collects the projected costs of decommissioning River Bend through rates charged to customers for the portion of the plant subject to cost-based ratemaking. The amounts collected through rates, which are based upon decommissioning cost studies, are deposited in decommissioning trust funds. In December 2002, decommissioning collections from customers for the Louisiana-regulated portion of River Bend were suspended as a result of the settlement with the LPSC of Entergy Gulf States' fourth through eighth earnings reviews. If decommissioning cost study estimates are changed and approved by regulators, collections from customers would also change. Approximately half of River Bend is not subject to cost-based ratemaking. When Entergy Gulf States acquired the 30% share of River Bend formerly owned by Cajun, Entergy Gulf States obtained decommissioning trust funds of $132 million, which have since grown to $158 million. Entergy Gulf States believes that these funds will be sufficient to cover the costs of decommissioning this portion of River Bend, and no further collections or deposits are being made for these costs. SFAS 143 Entergy Gulf States implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy Gulf States' asset retirement obligations, and the measurement and recording of Entergy Gulf States' decommissioning obligations changed significantly with the implementation of SFAS 143. The most significant differences in the measurement of these obligations are outlined below:
- Recording of full obligation - SFAS 143 requires that the fair value of an asset retirement obligation be recorded when it is incurred. This caused the recorded decommissioning obligation of Entergy Gulf States to increase significantly, as Entergy Gulf States had previously only recorded this obligation as the related costs were collected from customers, and as earnings were recorded on the related trust funds.
- Fair value approach - SFAS 143 requires that these obligations be measured using a fair value approach.
Among other things, this entails the assumption that the costs will be incurred by a third party and will therefore include appropriate profit margins and risk premiums. Entergy Gulf States' decommissioning studies had been based on Entergy Gulf States performing the work and did not include any'such margins or premiums.
- Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted risk-free rate.
The net effect of implementing SFAS 143 for the portion of River Bend subject to cost-based ratemaking was recorded as a regulatory asset, with no resulting impact on Entergy Gulf, States' net income. Entergy Gulf States recorded this regulatory asset because its existing rate mechanism is based on the original or historical cost standard that allows Entergy Gulf States to recover all ultimate costs of decommissioning existing assets from current and future customers. Upon implementation of SFAS 143 in 2003, assets and liabilities increased as a result of increasing the asset retirement obligation by $129 million to its fair value as determined under SFAS 143, reducing accumulated depreciation by $63 million, and recording the related regulatory asset of $32 million. The net effect of implementing SFAS 143 for the portion of River Bend not subject to cost-based ratemaking resulted in an earnings decrease of $21 million net-of-tax as a result of a one-time cumulative effect of accounting change. In the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected an expected life extension for the plant. The revised estimate resulted in a $166.4 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $49.6 million reduction in non-utility property, a $40.1 million reduction in the related regulatory asset, and a regulatory liability of $17.7 million. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement 189
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous income of $27.7 million. , Application of SFAS 71 The application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation," has a significant and pervasive impact on accounting and reporting for Entergy Gulf States. Entergy Gulf States' financial statements primarily reflect assets and costs based on existing cost-based ratemaking regulation in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Under traditional ratemaking practice, Entergy Gulf States is granted a geographic franchise to sell electricity. In return, Entergy Gulf States must make investments and incur obligations to serve customers. Prudently incurred costs are recovered from customers along with a return on investment. Regulators may require Entergy Gulf States to defer collecting from customers some operating costs until a future date. These deferred costs are recorded as regulatory assets in the financial statements. In order to continue applying SFAS 71 to its financial statements, Entergy Gulf States' rates must be set on a cost-of-service basis by an authorized body and the rates must be charged to and collected from customers... If the generation portion of a utility company moves toward competition, it is possible that generation rates will no longer be set on a cost-of-service basis. If that occurs, the generation portion of the business could be required to discontinue application of SFAS 71. The result of discontinuing application of SFAS 71 would be the removal of regulatory assets and liabilities from the balance sheet, and could include the recording of asset impairments. This result is because some of the costs or commitments incurred under a regulated pricing system might be impaired or not recovered in a competitive market. These costs are referred to as stranded costs. Unbilled Revenue As discussed in Note I to the domestic utility companies and System Energy financial statements, Entergy Gulf States records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month, including fuel price in Entergy Gulf States' Louisiana jurisdiction. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period and fuel price fluctuations, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regarding. price such as the fuel cost recovery mechanism. Pension and Other Postretirement Benefits Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy, Entergy's reported costs of providing these benefits, as described in Note 10 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms.. Because of the complexity of these calculations, the tong-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate. 190
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis Assumptions Key actuarial assumptions utilized in determining these costs include:
- Discount rates used in determining the future benefit obligations;
- Projected health care cost trend rates;
- Expected long-term rate of return on plan assets; and
- Rate of increase in future compensation levels.
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and worse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions. In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 6.75% in 2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to a 10% increase in health care costs' in 2005 gradually decreasing each successive year, until it reaches a 4.5% annual increase in health care costs in 2011 and beyond. In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities, and 4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities and 49% fixed income securities. Based on recent market trends, Entergy reduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 8.75% for 2002 and 2003 to 8.5% in 2004. The assumed rate of increase in future compensation levels used to calculate benefit obligations was 3.25% in 2002, 2003, and 2004. Cost Sensitivity The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (dollars in thousands): Change in Impact on 2004 Impact on Projected Actuarial Assumption Assumption Pension Cost Benefit Obligation Increase/(Decrease) Discount rate (0.25%) $1,994 $16,385 Rate of return on plan assets (0.25%) $1,134 Rate of increase in compensation 0.25% $726 $4,157 The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (dollars in thousands): Impact on Accumulated Change In Impact on 2004 Postretirement Benefit Actuarial Assumption Assumption Postretirement Benefit Cost Obligation Increase/(Decrease) Health care cost trend 0.25% $847 $4,751 Discount rate (0.25%) $510 $5,677 Each fluctuation above assumes that the other components of the calculation are held constant. 191
Entergy Gulf States, Inc. Management's Financial Discussion and Analysis Accounting Mechanisms In accordance with SFAS No. 87, "Employers' Accounting for Pensions," Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into cost only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. Additionally, Entergy accounts for the impact of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period,, the. future value of assets will be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87. Costs and Funding Total pension cost for Entergy Gulf States in 2004 was $0.4 million. Entergy Gulf States anticipates 2005 pension cost to increase to $7.3 million due to decrease in the discount rate,,(from, 6.25% to 6.00%), and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. Entergy Gulf States contributed $17 thousand to its pension plan in 2004, and anticipates making $18.9,million in contributions in 2005. The, rise in pension funding requirements is due to declining interest rates and the phased-in effept of asset underperformance from 2000 to 2002, partially offset by the Pension Funding Equity Act relief passed in April 2004. At December 31, 2003 and 2004, Entergy Gulf States' accumulated benefit obligation was: less than plan assets, therefore there was no additional minimum pension liabilityjrequired to be recognized. Net income, for 2004, 2003, and 2002 was not impacted. Total postretirement health care and life insurance benefit costs for Entergy Gulf States in 2004 were $17.,6 million, including $4.4 million in savings due to, the estimated effect of future Medicare Part D subsidies. Entergy Gulf States expects 2005 postretirement health care and life insurance benefit costs to be approximately $19.6 million, including $5.1 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the decrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate~used to calculate benefit obligations.
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192
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders Entergy Gulf States, Inc.: We have audited the accompanying balance sheets of Entergy Gulf States, Inc. as of December 31, 2004 and 2003, and the related statements of income, retained earnings and comprehensive income, and cash flows (pages 194 through 198 and applicable items in pages 284 through 348) for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion,-such financial statements present fairly, in all material respects, the financial position of Entergy Gulf States, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 5 and Note 8 to the notes to respective financial statements, in 2003 Entergy Gulf States, Inc. adopted the provisions of Statement of Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, and Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of-the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the 'Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting. DELOITTE & TOUCHE LLP New Orleans, Louisiana . March 8, 2005 193
ENTERGY GULF STATES, INC INCOME STATEMENTS - f For the Years Ended December 31, 2004.- 2003 --- 2002 (In Thousands) OPERATING REVENUES, Domestic electric $2,821,296 $2,579,916 $2,141,873. Natural gas ' 61,088 59,821 42,006 TOTAL 2,882,384 ' 2,639,737 2,183,879 q ( . I OPERATING EXPENSES Operation and Maintenance: Fuel, fuel,-related expenses, and gas purchased for resale 772,914 ' 693,612 692,901' Purchased power ' 969,*9 ' 838,498 368,140 Nuclear refueling outage expenses - 55,969 I I [14,045 ' 12,190 Other operation and maintenance
- 445,413 457,428 438,259 Decommissioning I -- 13,645 14,268 3,980 Taxes other than income taxes , j, f118,081 : , 117,009 120,295 Depreciation and amortization 197,234 199,583 204,202 Other regulatory credits - net (10,070) (2,476) (7,818)
TOTAL ' 2,522,965 2,331,967 1,832,149 OPERATING INCOME -. . 359,419 307,770 351,730 OTHER INCOME (DEDUCTIONS) Allowance for equity funds used during construction 13,027 15,855 11,010 Interest and dividend income 15,753 17,902 8,866 Miscellaneous - net' '36,180 (109,389) 3,560 TOTAL 64,960 (75,632V 23,436 INTEREST AND OTHER CHARGES Interest on long-term debt 125,356 , 148,516 ¢ 149,343 Other interest - net 8,242 8,827 . , . 5,497, Allowance for borrowed fuids used during construction Zj(9,7i) " (13,349) ' (9,749) TOTAL . I 123,827 143,994 .' 135,091 -
. . I.. ,a I INCOME BEFORE INCOME TAXES AND. , 3 5 8,4 :-
2 0 I, CUMULATIVE EFFECT OF ACCOUNTING CHANGE ;1 .- , 300,552 88,144, ~ 240,075' ' Income taxes 108,288 24,249 65,997 INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 192,264 ! 63,895 * ' 174,078 CUMULATIVE EFFECT OF ACCOUNTING -, !I . CHANGE (net of income taxes of S12,713) (21,333) NET INCOME 192,264 42,562 174,078 Preferred dividend requirements and other 4,472 4,701 4,888 EARNINGS APPLICABLE TO COMMON STOCK $187,792 $37,861 $169,190 See Notes to Respective Financial Statements. 194
ENTERGY GULF STATES, INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2004 2003 2002
- . (In Thousands)
AIN
. A .V_
TI OPERATING ACTIVITIES Net income $192,264 $42,562 $174,078 Adjustments to reconcile net income to net cash flow provided by operating activities: Reserve for regulatory adjustments 24,112 12,605 11,147 Other regulatory credits - net (10,070) * (2,476) (7,818) Depreciation, amortization, and decommissioning 210,879 213,851 208,182 Deferred income taxes and investment tax credits 57,908 24,574 (11,576) Cumulative effect of accounting change 21,333 Changes in working capital: Receivables 14,774 (96,409) 18,155 Fuel inventory 1,205 (1,469) 4,617 Accounts payable 59,846 (17,013) 83,428 Taxes accrued 99,955 12,618 (24,740) Interest accrued (3,834) (1,900) (4,544) Deferred fuel costs 78,200 59,165 65,556 Other working capital accounts 7,426 11,874 (19,551) Provision for estimated losses and reserves (13,844) 115,878 1,478 Changes in other regulatory assets (10,060) 3,983 (51,490) Other (59,303) 26,787 53,732 Net cash flow provided by operating activities 649,458 425,963 500,654 INVESTING ACTIVITIES Construction expenditures (357,720) (348,507) (355,334) Allowance for equity funds used during construction ' t,027 3' 15,855 11,010 Nuclear fuel purchases (45,085) (39,959) (21,820) Proceeds from sale/leaseback of nuclear fuel !I ' , j 38,800 38,029 21,923 Decommissioning trust contributions and realized change in trust assets (12,070) (11,428) (12,488) Changes in other temporary investments --net 23,579 (23,579) 44,643 Other regulatory investments (49,875) (77,050) (39,390) Net cash flow used in investing activities - (389,344) (446,639) (351,456) FINANCING ACTIVITIES Proceeds from the issuance of long-term debt 472,039 1,032,682 337,481 Retirement of long-term debt (829,000) (1,048,129) (194,057) Redemption of preferred stock (3,450) (3,450) (1,858) Dividends paid: Common stock (94,300) '(68,100) (91,200) Preferred stock (4,459) (4,701) (4,888) Net cash flow provided by (used in) financing activities (459,170) (91,698) 45,478 Net increase (decrease) in cash and cash equivalents (199,056) (112,374) 194,676 206,030 318,404 123,728 Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period $6,974 $206,030 $318,404 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid/(received) during the period for: Interest - net of amount capitalized $130,491 S152,655 $143,961 Income taxes ($28,169) ($30,987) $98,734 See Notes to Respective Financial Statements. 195
ENTERGY GULF STATES, INC. BALANCE SHEETS ' ' ASSETS December 31, 2004 2003 (In Thousands) CURRENT ASSETS Cash and cash equivalents: Cash I I $5,627 . $20 754
. . 4 Temporary cash investments - at cost,,
which approximates market 1,347 185,276 Total cash and cash equivalents 6,974 206,030 Other temporary investments 23,579 Accounts receivable: Customer 124,801 115,729 Allowance for doubtful accounts (2,687) (4,856) Associated companies 13,980 76,726 Other 40,697 27,243 Accrued unbilled revenues 137,719 114,442 Total accounts receivable 314,510 329,284 Deferred fuel costs 90,124 118,449 Accumulated deferred income taxes 14,339 II , ,6,116 Fuel inventory - at average cost 49,658 50,863 Materials and supplies - at average cost 101,922 99,357 Prepayments and other 20,556 51,236 TOTAL i 598,083 r 884,914 OTHER PROPERTY AND INVESTMENTS Decommissioning trust funds 290,952 267,917 Non-utility property - at cost (less accumulated depreciation) 94,052 '139,911 Other 22,012 21,852 TOTAL 407,016 '429,680 UTILITY PLANT Electric 8,418,119 8,208,394 Property under capital lease *1 I 11,009 Natural gas 78,627. 7--- -' ' 69,180 Construction work in progress 331,703 325,888 Nuclear fuel under capital lease 71,279 63,684 TOTAL UTILITY PLANT 8,899,728 8,678,155 Less - accumulated depreciation and amortization 4,047,182 3,953,275 UTILITY PLANT - NET 4,852,546 4,724,880 DEFERRED DEBITS AND OTHER ASSETS Regulatory assets: SFAS 109 regulatory asset - net 444,799 442,062 Other regulatory assets - 285,017 320,363 Long-term receivables 23,228 19,375 1i Other 44,713 33,588 TOTAL 797,757 815,388 TOTAL ASSETS . $6,655,402 $6,854,862 See Notes to Respective Financial Statements. 196
ENTERGY GULF STATES, INC. BALANCE SHEETS LIABILITIES AND SHAREHOLDERS' EQUITY December 31, 2004 2003 (In Thousands) CURRENT LIABILITIES Currently maturing long-term debt $98,000 $354,000 Accounts payable: Associated companies 153,069 84,394 Other 147,337 156,166 Customer deposits 53,229 47,044 Taxes accrued 22,882
-- 8,238 Nuclear refueling outage costs Interest accrued 32,742
- 36,576 Obligations under capital leases 33,518 34,075 Other 19,912 14,755 TOTAL 560,689 735,248 NON-CURRENT LIABILITIES Accumulated deferred income taxes and taxes accrued 1,533,804 1,422,776 Accumulated deferred investment tax credits 138,616 144,323 Obligations under capital leases 37,711 40,618 Other regulatory liabilities 34,009 13,885 Decommissioning and retirement cost liabilities 152,095 298,785 Transition to competition 79,098 79,098 Regulatory reserves 81,455 57,343 Accumulated provisions 66,875 75,868 Long-term debt 1,891,478 1,989,613 Preferred stock with sinking fund 17,400 20,852 Other 229,408 233,985 TOTAL 4,261,949 4,377,146 Commitments and Contingencies SHAREHOLDERS' EQUITY Preferred stock without sinking fund 47,327 47,327 Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 100 shares in 2004 and 2003 114,055 114,055 Paid-in capital 1,157,486 1,157,484 Retained earnings 513,182 419,690 Accumulated other comprehensive income 714 3,912 TOTAL 1,832,764 1,742,468 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $6,655,402 $6,854,862 See Notes to Respective Financial Statements.
197
ENTERGY GULF,STATES, INC., STATEMENTS OF RETAINED EARNINGS AND COMPREHENSIVE INCOME
' Fat the Years Ended December 31, 2004 2003 2002 (In Thousands)
RETAINED EARNINGS Retained Earnings -Beginning of period $419,690 S449,929 $371,939 Add -Net Income 192,264 S192,264 42,562 $42,562 174,078 S174,078 Deduct Dividends declared on common stock 94,300 68,100 91,200 Preferred dividend requirements and other 4,472 4,472 4,701 4,701 4,888 4,888 Total 98,772 72,801 96,088 Retained Earnings -End of period $513,182 S419,690 $449,929 ACCUMULATED OTHER COMPREHENSIVE INCOME (Net of Taxes): Balance at beginning of period Accumulated derivative instrument fair value changes $3,912 S3,286 Net derivative instrument fair value changes arising during the period (3,198) (3,198) 626 626 3,286 3,286 Balance at end of period.- Accumulated derivative instrument fair value changes $714 $3,912 _3,286 Comprehensive Income $184,594 $S38,487 $172,476 See Notes to Respective Financial Statements. 198
ENTERGY GULF STATES, INC. SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 2004 2003 2002 2001 2000 (In Thousands) Operating revenues $2,882,384 $2,639,737 $2,183,879 $2,648,560 $2,511,240 Net Income $192,264 $45,262 $174,078 $179,444 $180,343 Total assets $6,655,402 $6,854,862 $6,599,533 $6,209,741 $6,134,017 Long-term obligations (1) $1,946,589 $2,051,083 $2,096,329 $2,130,245 $1,978,149 (1) Included long-term debt (excluding currently maturing debt), preferred stock with sinking fund, and noncurrent capital lease obligations. 2004 2003 2002 2001 2000 (Dollars In Millions) Electric Operating Revenues: Residential $881 $829 $700 $788 - $717, Commercial 672 614 502 587 505, Industrial 976 853 695 946 871 Governmental 37 39. 34 38 33 Total retail 2,566 2,335 1,931. 2,359 2,126 Sales for resale: Associated companies 52 42 28 73 94 Non-associated companies 160 150 139 146 113 Other 43 53 44 13 138 Total $2,821 $2,580 $2,142 $2,591 $2,471 Billed Electric Energy Sales (GWh): Residential 9,803 9,739 - 9,502 9,059 9,405 Commercial 8,444 8,174 7,894 7,668 7,660 Industrial 16,596 15,417 15,887 16,658 17,960 Governmental 432 475 477 452 450 Total retail 35,275 33,805 33,760 33,837 35,475 Sales for resale: ii Associated companies 1,528 1,185 . I 708 1,087 1,381 Non-associated companies 3,172 3,358 4,391 3,305 3,248 Total 39,975 38,348 38,859 38,229 40,104 199
ENTERGY LOUISIANA, INC. MIANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS Results of Overations Net Income 2004 Compared to 2003 Net income decreased $18.7 million primarily due to lower net revenue, partially offset by lower other operation and maintenance expenses. 2003 Compared to 2002 Net income increased slightly primarily due to higher net revenue and lower interest charges, almost entirely offset by higher other operation and maintenance expenses, higher, depreciation and amortization expenses, and higher taxes other than income taxes. Net Revenue 2004 Compared to 2003 Net revenue, which is Entergy Louisiana's measure of gross margin, consists of operating revenues net of:
- 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an analysis of the change in net revenue comparing 2004 to 2003.
(In Millions) 2003 net revenue $973.7 Price applied to unbilled-sales (31.9) Deferred fuel cost revisions (29.4) Rate refund provisions (12.2) Volume/weather 17.0 Summer capacity charges 11.8 Other 2.3 2004 net revenue $931.3 The price applied to the unbilled sales variance is due to a decrease in the fuel price included in unbilled sales in 2004 caused primarily by the effect of nuclear plant outages in 2003 on average fuel costs. The deferred fuel cost revisions variance resulted from a revised unbilled sales pricing estimate made in the first quarter of 2003 to more closely align the fuel component of that pricing with expected recoverable fuel costs. Rate refund provisions caused a decrease in net revenue due to additional provisions recorded in 2004 compared to 2003 for potential rate actions and refunds. The volume/weather variance is due to a total increase of 620 GWh in weather-adjusted usage in all sectors, partially offset by the effect of milder weather on billed sales in the residential and commercial sectors. The summer capacity charges variance is due to the amortization in 2003 of deferred capacity charges for the summer of 2001 compared to the absence of the amortization in 2004. The amortization of these capacity charges began in August 2002 and ended in July 2003. 200
Entergy Louisiana, Inc. Managements Financial Discussion and Analysis Gross operatingrevenues, fuel andpurchasedpowerexpenses, and other regulatorycredits Gross operating revenues increased primarily due to:
- an increase of $98.0 million in fuel cost recovery revenues due to higher fuel rates; and
- an increase due to volume/weather, as discussed above.
The increase was partially offset by the following:
- a decrease of $31.9 million in the price applied to unbilled sales, as discussed above;
- a decrease of $12.2 million in rate refund provisions, as discussed above; and
- a decrease of $5.2 million in gross wholesale revenue due to decreased sales to affiliated systems.
Fuel and purchased power expenses increased primarily due to:
- an increase in the recovery from customers of deferred fuel costs; and
- an increase in the market price of natural gas.
Other regulatory credits increased primarily due to:
- the deferral in 2004 of $14.3 million of capacity charges related to generation resource planning as allowed by the LPSC;
- the amortization in 2003 of $11.8 million of deferred capacity charges, as discussed above; and
- the deferral in 2004 of $11.4 million related to Entergy's voluntary severance program, in accordance with a proposed stipulation with the LPSC staff.
2003 Compared to 2002 Net revenue, which is Entergy Louisiana's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2003 to 2002. (In Millions) 2002 net revenue $922.9 Deferred fuel cost revisions 59.1 Asset retirement obligation 8.2 Volume (16.2)
-Vidalia settlement (9.2)
Other 8.9 2003 net revenue $973.7 The deferred fuel cost revisions variance resulted from a revised unbilled sales pricing estimate made in December 2002 and a further revision made in the first quarter of 2003 to more closely align the fuel component of that pricing with expected recoverable fuel costs. The asset retirement obligation variance was due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," adopted in January 2003. See "Critical Accounting Estimates" for more details on SFAS 143. The increase was offset by decommissioning expense and had no effect on net income. The volume variance was due to a decrease in electricity usage in the service territory. Billed usage decreased 1,868 GWh in the industrial sector including the loss of a large industrial customer to cogeneration. 201
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis See "Liquiditv and Capital Resources" below for more details regarding the September 2002 settlement related to the Vidalia contract. Gross operatingrevenues, fuel and purchasedpower expenses, and other regulatorycharges (credits) Gross operating revenues increased primarily due to:
- an increase of $277.2 million in fuel cost recovery revenues due to higher fuel rates; and
- an increase of $94.7 million in gross wholesale revenue due to increased sales to affiliated systems.
Fuel and purchased power expenses increased primarily due to an increase in the market prices of natural gas and purchased power. Other regulatory credits increased primarily due to:
- an increase of $8.2 million due to the change in accounting for asset retirement obligations in compliance with SFAS 143, adopted in January 2003. This increase has no effect on net income; and
- an increase of $5.9 million due to the deferral of capacity charges in the third quarter of 2003 as allowed by the LPSC related to generation resource planning.
OtherIncome Statement Variances 2004 Compared to 2003 Other operation and maintenance expenses decreased primarily due to voluntary severance program accruals of $19.7 million in 2003, partially offset by an increase of $9.1 million in customer service support costs. 2003 Compared to 2002 Other operation and maintenance expenses increased primarily due to:
- voluntary severance program accruals of $19.7 million; and
- an increase of $13.4 million in benefit costs.
Decommissioning expenses increased $10.1 million primarily due to the implementation of SFAS 143, "Accounting for Asset Retirement Obligations," adopted in January 2003. See "Critical Accounting Estimates" for more details on SFAS 143. The increase in decommissioning expense was offset by regulatory credits and interest and dividend income and had no effect on net income.. Taxes other than income taxes increased primarily due to the franchise tax adjustments of $10.8 million recorded in 2002 as a result of a favorable court decision that allowed Entergy Louisiana to receive a refund for certain franchise taxes previously expensed and paid under protest. Depreciation and amortization expenses increased primarily due to anincrease in plant in service. Interest charges decreased primarily due to decreased interest on long-term debt of $25.5 million due to the redemption of $150 million of First Mortgage Bonds in June 2003 and the redemption of $187 million of First Mortgage Bonds from April through December of 2002, partially offset by the issuance of $150 million of First Mortgage Bonds in March 2002. ' - i, . Income Taxes The effective income tax rates for 2004, 2003, and 2002 were 38.4%, 40.0%, and 36.9%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal 202
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis statutory rate of 35.0% to the effective income tax rate. Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet. Liquidity and Capital Resources Cash Flow Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows: 2004 2003 2002 (In Thousands) Cash and cash equivalents at beginning of period $8,787 $311,800 $42,408 Cash flow provided by (used in): Operating activities 424,718 413,939 1,035,777 Investing activities (243,231) (268,372) (212,333) Financing activities (44,225) (448,580) (554,052) Net increase (decrease) in cash and cash equivalents 137,262 (303,013) 269,392 Cash and cash equivalents at end of period $146,049 $8,787 $311,800 Operating Activities Cash flow from operations increased $10.8 million in 2004 primarily due to the increased collection of deferred fuel costs and the receipt of an income tax payment through Entergy's inter-company tax allocation process. The increase was almost entirely offset by money pool activity. In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $505 million deduction for Entergy Louisiana on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004 Entergy Louisiana realized $100 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. As of December 31, 2004, Entergy Louisiana has a net operating loss (NOL) carryforward for tax purposes of $195.7 million, principally resulting from the change in tax accounting method related to cost of goods sold. If the tax accounting method change is sustained, Entergy Louisiana expects to utilize the NOL carryforward through 2005. Cash flow from operations decreased $621.8 million in 2003 as a result of Entergy Louisiana changing its method of accounting for tax purposes related to its wholesale electric power contracts, including the contract to purchase power from the Vidalia project (the contract is discussed in Note 8 to the domestic utility companies and System Energy financial statements). The new tax accounting method provided a cumulative cash flow benefit of approximately $790 million through 2004, which is expected to reverse in the years 2005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. In a settlement approved by the LPSC, Entergy Louisiana will keep a portion of the benefit in exchange for crediting customer rates. The credit will be $11 million annually through at least 2010. See Part I, Item I for additional details concerning the settlement. Entergy Louisiana reduced its indebtedness and preferred stock with a portion of the cash from the tax benefit. In accordance with the terms of the settlement, Entergy Louisiana requested SEC approval to return up to
$350 million of common equity capital to Entergy Corporation in order to maintain Entergy Louisiana's capital structure. In December 2002, Entergy Louisiana repurchased $120 million of common stock from Entergy Corporation and, at the time of settlement, paid a dividend of $122.6 million pursuant to the SEC approval. The provisions of the settlement provide that the LPSC shall not recognize or use Entergy Louisiana's use of this cash in 203
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis setting any of Entergy Louisiana's rates. Therefore; to the extent. Entergy Louisiana's use of the proceeds would ordinarily have reduced its rate base, no change in rate base shall be' reflected for ratemaking purposes. The SEC approval for additional return of equity capital is now expired. Entergy Louisiana's receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years: 2004 2003 2002 2001 (In Thousands)
$40,549 ($41,317) $18,854 $3,812 Money pool activity used $81.9 million of Entergy Louisiana's operating cash flow in 2004, provided $60.2 million in 2003, and used $15.0 million in 2002: See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool.
Investing Activities
'The decrease of $25.1 million in net cash used by investing activities in 2004 was primarilyidue to decreased spending on customer service projects, partially offset by increases in spending on transmission projects and fossil plant projects.
The increase of $56.0 million in net cash used by investing activities in 2003 was primarily due to increased spending on customer service, transmission, and nuclear projects. Financing Activities The decrease of $404.4 million in net cash used by.financing activities in 2004 was primarily due to:
- the net issuance of $98.0 million of long-term debt in 2004 compared to the retirement of $261.0 million in 2003;i
- a principal payment of $14.8 million in 2004 for the Waterford Lease Obligation compared to a principal paymentof$35.4millionin2003; and . i
- a decrease of $29.0 million in common stock dividends paid.,
The decrease of $105.5 million in net cash used by financing activities in 2003 was primarily due to:
- a decrease of $125.9 million in common stock dividends paid; and
- the repurchase of $120 million of common stock from Entergy Corporation in 2002.
The decrease in net cash used in 2003 was partially offset by the following:
- the retirement inr2003 of $150 million of 8.5% 'Series First Mortgage Bonds compared to the net retirement of $134.6 million of First Mortgage Bonds in 2002; and
- principal payments of $35.4 million in 2003 fdr the Waterford 3 Lease Obligation compared to principal payments of $15.9 million in 2002'.
See Note 5 to the domestic utility companies and System Energy financial statements for details of lobig-term debt. Uses of Capital Entergy Louisiana requires capital resources for:
- construction and other capital investments;;, - ,
- debt and preferred stock maturities;
- working capital purposes, including the financing of fuel and purchased power costs; and
- dividend and interest payments. -
204
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis Following are the amounts of Entergy Louisiana's planned construction and other capital investments, existing debt and lease obligations, and other purchase obligations: 2005 2006-2007 2008-2009 After 2009 Total (In Millions) Planned construction and capital investment (1) $455 $472 N/A N/A $927 Long-term debt $55 $- $7 $924 $986 Operating leases $10 $11 $6 $2 $29 Purchase obligations (2) $639 $1,120 $980 $4,691 $7,430 Nuclear fuel lease obligations (3) $23 $9 N/A N/A $32 (1) Includes approximately $130 to 160 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. (2) Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purphase goods or services. For Entergy Louisiana almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the domestic utility companies and System Energy financial statements. (3) It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt., If such additional financing cannot be arranged, however, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations. In addition to these contractual obligations, Entergy Louisiana expects to contribute $2.6 million to its pension plans and $8.5 -million to other postretirement plans in 2005. The planned capital investment estimate for Entergy Louisiana reflects capital required to support existing business and customer growth. The estimated capital expenditures are subject to periodic review and modification and 'may vary based on' the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, business restructuring, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the domestic utility companies and System Energy financial statements.
- In January 2004, Entergy Louisiana signed a definitive agreement to acquire the 718 MW Perryville power plant for $170 million. The agreement has subsequently been amended to allow the current plant owner to retain the interconnection facilities associated with the plant, resulting in a decrease in the acquisition price to $162 million. As a result of the amended terms, the FERC issued an order in October 2004 disclaiming jurisdiction over the acquisition. This order currently is subject to rehearing by the FERC. The plant is owned by a subsidiary of Cleco Corporation, which subsidiary submitted a bid in response to Entergy's Fall 2002 request for proposals for supply-side resources. The signing of the agreement followed a voluntary Chapter 11 bankruptcy filing by the plant's owner., "Entergy expects that Entergy Louisiana will own 100 percent of the Perryville plant, and that Entergy Louisiana will sell 75 percent of the output to Entergy Gulf States under a long-term cost-of-service power purchase agreement. In addition, Entergy Louisiana and Entergy Gulf States executed an interim power purchase agreement with the plant's owner through the date of the acquisition's closing (as long as that occurs by December 2005) for 100 percent of the output of the Perryville power plant. In April 2004, the'bankruptcy court approved Entergy Louisiana's agreement to acquire the plant. In March 2004, Entergy Gulf States and Entergy Louisiana filed with the LPSC for its approval of the acquisition and long-term cost-of-service power purchase agreement.
Entergy is seeking approval from the LPSC of cost recovery for the acquisition, giving consideration to the need for the power and the prudence of Entergy Louisiana and Entergy Gulf States in engaging in the transaction. Hearings are scheduled for March 2005. Assuming regulatory approval by the LPSC, Entergy Louisiana expects the Perryville acquisition to close in mid-2005. As a wholly-owned subsidiary, Entergy Louisiana dividends its earnings to Entergy Corporation at a percentage determined monthly. In addition, all of Entergy Louisiana's retained earnings are currently available for distribution. 205
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis Sources of Capital - Entergy Louisiana's sources to meet its capital requirements include:
- internally generated funds;
- cash on hand;
- debt or preferred stock issuances; and
- bank financing under new and existing facilities.
Entergy Louisiana issued $285 million of first mortgage bonds in 2004 as follows: Issue Date Description Maturity Amount (In Thousands) March 2004 5.50% Series April 2019 $100,000 October 2004 6.40% Series October 2034 70,000 October 2004 5.09% Series November 2014 115,000
$285,000 Entergy Louisiana retired $187.2 million of long-term debt in 2004 as follows:
Retirement Date Description Mlaturity Amount (In Thousands) November 2004 6.50% Series March 2008 $115,000 November 2004 9.00% Series September 2045 72,165
$187,165 l Entergy Louisiana may refinance or redeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred stock issuances by Entergy Louisiana require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs. In July 2004, Entergy Louisiana renewed its 364-day credit facility and Entergy New Orleans entered into a separate credit facility with the same lender. Both facilities will expire in April 2005, Entergy Louisiana can borrow up to $15 million and Entergy New Orleans can borrow up to $14 million under their respective credit facilities, but at no time can the total amount borrowed under these facilities by the two companies combined exceed $15 million. As of December 31, 2004, no bQrrowings were outstanding under these facilities. Borrowings and securities issuances by Entergy Louisiana are limited to amounts authorized by the SEC. The current short-term borrowing limitation; including borrowings under the money pool, is $225 million. Under its SEC Orders and without, firther SEC authorization; Entergy Louisiana cannot incur additional indebtedness or issue other securities unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the: exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy Louisiana, as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note, 4 to the, domestic utility companies and System Energy financial statements for further discussion of Entergy Louisiana's short-term borrowing limits. , . 206
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis Significant Factors and Known Trends Utility Restructuring In November 2001, the LPSC decided not to move forward with retail open access for any customers at this time. The LPSC instead directed its staff to hold collaborative group meetings concerning open access from time to time, and to have the LPSC staff monitor developments in neighboring states and to report to the LPSC regarding the progress of retail access developments in those states. In September 2004, in response to a study funded by certain industrial customers that evaluated a limited industrial-only retail choice program, the LPSC asked the LPSC staff to solicit comments and obtain information from utilities, customers, and other interested parties concerning the potential costs and benefits of a limited choice program, the impact of such a program on other customers, as well as issues such as stranded costs and transmission service. Comments from interested parties were filed with the LPSC on January 14, 2005. The LPSC has not established a procedural framework for consideration of the comments. At this time, it is not certain what further action, if any, the LPSC might take in response to the information it received. At FERC, the pace of restructuring at the wholesale level has begun but has been delayed. It is too early to predict the ultimate effects of changes in United States energy markets. Restructuring, issues are complex and are continually affected by events at the national, regional, state, and local levels. However, these changes may result, in the long-term, in fundamental changes in the way traditional integrated utilities-and holding company systems, like the Entergy system, conduct their business. Some of these changes maybe positive for Entergy,-while others may not. State Rate Regulation The rates that Entergy Louisiana charges for its services are an important item influencing its financial position, results of operations, and liquidity. Entergy Louisiana is closely regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement with the LPSC that would resolve, among other dockets, dockets established to consider issues concerning power purchases for both Entergy Gulf States and Entergy Louisiana for the summers of 2001, 2002, 2003, and 2004. The proposed settlement currently includes an offer to refund $14 million to Entergy Louisiana's customers. The LPSC has solicited comments on -the proposed settlement from the parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005. In January 2004, Entergy Louisiana made a rate filing with the LPSC requesting a base rate increase of approximately $167 million. In that filing, Entergy Louisiana noted that approximately $73 million of the -base rate increase was attributable to the acquisition of a generating station and certain power purchase agreements that, based on current natural gas prices, would produce fuel and. purchased power savings for customers that substantially mitigate the impact of the requested base rate increase. The filing also requested an allowed ROE of 11.4%. Entergy Louisiana's previously authorized ROE mid-point currently in effect is 10.5%. Hearings concluded in December 2004.' Based on evidence submitted at the hearing, the LPSC staff is recommending approximately a $7 million base rate increase. The LPSC staff proposed the implementation of a formula rate plan that includes a provision for the recovery 'of incremental capacity costs, including those related to the proposed Perryville acquisition, without filing a traditional base rate proceeding. A decision by the LPSC is expected in mid-to late-March 2005 on these issues. In addition to rate proceedings, Entergy Louisiana's fuel costs recovered from customers are subject to regulatory scrutiny. This regulatory risk represents Entergy Louisiana's largest potential exposure to price changes in the commodity markets. Entergy Louisiana's retail rate matters and proceedings, including fuel cost recovery-related issues, are discussed in Note 2 to the domestic utility companies and System Energy financial statements. 207
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis System Agreement Proceedings The domestic utility companies historically have engaged in the coordinated planning, construction, and operation of generating and transmission facilities under the terms of an agreement called the System Agreement that has been approved by the FERC. Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise- questions of imprudence by the domestic utility companies in their execution of the System Agreement, and seek support for local regulatory authority over System Agreement issues. In February 2004' a FERC ALU issued an Initial Decision in the LPSC-initiated proceeding at the FERC. The Initial Decision decided some issues in favor of the relief sought by the LPSC, and decided some issues against the 'relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALUs Initial Decision. Entergy's exceptions to the ALUs Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the' System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be'difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method. If the FERC grants the relief requested by the LPSC in the proceeding, 'the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies'.whose costs currently are projected to; exceed that average. If the FERC adopts the AL's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of EntergySystem average total production cost. The ALUs Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be- accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost.
! j , ,,,, ' , : ' .'
An assessment of:the potential effects of the ALJ's Initial Decision requires assumptions iegarding the future total; production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and; Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy 'Arkansas" total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent: years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu during the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. ¢ Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALrs Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009: 208
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis Average Annual Range of Annual Payments Payments or (Receipts) or (Receipts) for 2005-2009 Period (In Millions) (In Millions) Entergy Arkansas $154 to $281 $215 Entergy Gulf States ($130) to ($15) ($63) Entergy Louisiana ($199) to ($98) ($141) Entergy Mississippi ($16) to $8 $1 Entergy New Orleans ($17) to ($5) ($12)
. Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings'should result in similar rate changes for retail customers. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy Louisiana does not believe that the ultimate resolution of these proceedings will have a material 'effect on its financial condition or results of operation. I In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC AL's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the AL's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production' cost-related portions of the Initial Decision; and states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate.
In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the AL's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations. - In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic, utility "companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority: In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March '2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Louisiana, as well as the named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court issued 'an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity. 209
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis The LPSC instituted a companion ex-parte System Agreement investigation to litigate several of the System Agreement issues that the LPSC is litigating before the FERC in the previously discussed System Agreement proceeding. This companion proceeding will require the LPSC to interpret various provisions of the System Agreement, including those relating to minimum-run and must-run units, the propriety of the methods used for billing and dispatch on the Entergy System, and the use of a rolling, twelve-month average of system peaks for allocating certain costs. In addition, by this companion proceeding the LPSC is questioning; whether Entergy Louisiana and Entergy Gulf States were prudent for not seeking changes to the System Agreement previously, so as to lower costs imposed upon their ratepayers and to increase costs imposed upon ratepayers of other domestic utility companies. The LPSC staff has filed testimony suggesting that the remedy for the alleged imprudence of Entergy Louisiana and Entergy Gulf States should be a reduction in allowed rate of return on common equity of 100 basis points. The domestic utility companies have challenged the propriety of the LPSC's litigating System Agreement issues. Nevertheless, on January 16, 2002 the LPSC affirmed a decision of its ALI upholding the LPSC staffs right to litigate System Agreement issues at the LPSC, rather than before the FERC. The procedural schedule is suspended at this time and an evidentiary hearing is not scheduled. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting FERC rate schedules that are part of the System Agreement, and from subsequently enforcing that interpretation. The LPSC interpreted a System Agreement rate schedule in the unrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed. In 2003, the U.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the decisions of the LPSC and the Louisiana Supreme Court. Transmission In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs. In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the, Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations. Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed.to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably, serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences. In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance, on two important issues: (1) whether the fuanctions.performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergys open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the petition and, obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer 210
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis Entergy's OASIS; and (d) perform an enhanced planning function (integratingthe plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their, individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005. In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in' that proceeding was held in August 2004. Additionally, Entergy Louisiaha and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion of the proposal currently scheduled for August 2005. Interconnection Orders The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GenCos had previously paid to the Entergy companies for facilities necessary to connect their generation facilities to Entergy's transmission system. The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by, the GenCos, including $3 million for Entergy Louisiana. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy. In addition, Entergy Louisiana was recently directed, effective as of March 2001, to provide transmission credits, with interest, associated with a specific generator that asserted to the FERC that it retained in its contract for interconnection a right to execute the latest form of Entergy's standard interconnection agreement in lieu of its existing contract, which thereby would apply FERC's most recent interconnection cost allocation policies to that generator. Following an ALls Initial Decision and an order affirming such decision by FERC, approximately $15 million in expenses and tax obligations previously paid by the generator have been ordered refunded in the form of transmission credits, to be utilized over time and applied to Entergy transmission, service bills incurred after March 2001. Entergy Louisiana has sought rehearing of the FERC's order. To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy. intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators. , . Available Flowgate Capacity Proceeding On December 17, 2004, the FERC issued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised in a FERC audit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the. Generator Operating Limits methodology. The FERC order 211
Entergy Louisiana, Inc. Managemenfts Financial Discussion and Analysis indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC program, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory. Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy. Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the AFC proceeding is currently scheduled to commence in August 2005. Industrial and Commercial Customers Entergy Louisiana's large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Louisiana's industrial customer base. Entergy Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles., Despite these actions, Entergy Louisiana lost a large industrial customer to cogeneration in late 2002. The customer accounted for approximately 2% of its net revenue in 2001. Entergy Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial energy demand, from both existing and new customers. Entergy Louisiana does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Louisiana's marketing efforts in retaining industrial customers. Market and Credit Risks Entergy Louisiana has certain market and credit risks inherent in its business operations. Market risks represent the' risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Interest Rate and Equity Price Risk - Decommissioning Trust Funds Entergy Louisiana's nuclear decommissioning trust funds expose it to fluctuations in equity prices and interest rates. Tfie'NRC requires Entergy Louisiana to maintain trusts to fund the costs of decommissioning Waterford 3. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the Waterford 3 trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 12 to the domestic utility companies and System Energy financial statements. Nuclear Matters Entergy Louisiana owns and operates, through an affiliate, the Waterford 3 nuclear power plant. Entergy Louisiana is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed 212
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. In August 2001, the NRC issued a bulletin requesting all pressurized water reactor owners and operators to report on the structural integrity of their reactor vessel head penetration nozzles to justify continued operations past December 31, 2001. These types of reactors are susceptible to stress corrosion cracking of the reactor vessel head nozzles. Waterford is a pressurized water reactor. To date, there has been no primary side stress corrosion cracking identified in the Waterford reactor vessel head. Inspections of the Waterford reactor vessel head will continue during planned refueling outages. Environmental Risks Entergy Louisiana's facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated. Litigation Risks The state of Louisiana has proven to be an unusually litigious environment. Judges and juries in Louisiana have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy Louisiana uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment poses a business risk. Critical Accountiniz Estimates The preparation of Entergy Louisiana's financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy Louisiana's financial position or results of operations. Nuclear Decommissioning Costs Regulations require Entergy Louisiana to decommission the Waterford 3 nuclear power plant after the facility is taken out of service, and money is collected and deposited in trust funds during the facility's operating life in order to provide for this obligation. Entergy Louisiana conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facility. The following key assumptions have a significant effect on these estimates:
- Cost Escalation Factors - Entergy Louisiana's decommissioning studies include an assumption that decommissioning costs will escalate over present cost levels by an annual factor averaging approximately 4.4%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11%.
- Timing - The date of the plant's retirement must be estimated and an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore" status for later decommissioning, as permitted by applicable regulations. While the effect of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can possibly decrease the present value of these obligations.
- Spent Fuel Disposal - Federal regulations require the DOE to provide a permanent repository for the storage of spent nuclear fuel, and legislation has been passed by Congress to develop this repository at 213
Entergy Louisiana, Inc. Management's Financial Discussion and Arialysis Yucca Mountain, Nevada. Until this site is available, however, nuclear plant operators must provide for interim spent fuel storage 'on the nuclear plant'site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these-facilities can have a significant effect (as much as 16% of estimated decommissioning costs). Entergy Louisiana's decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors. Technoloev and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. Entergy Louisiana's decommissioning cost studies assume current technologies and regulations. Entergy Louisiana collects substantially all 'of the projected costs of decommissioning Waterford 3 through rates charged' to customers. The amounts collected through rates, which'are based upon decommissioning cost studies, are deposited in decommissioning trust fuinds. These collections plus earnings on the trust fund investments are estimated to be sufficient to fuind the future decommissioning costs. If decommissioning cost study estimates are changed and approved by regulators, collections from customers would also change. SFAS 143 Entergy 'Louisiana implemented' SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs comprise substantially all of Entergy Louisiana's asset retirement obligations, and the measurement and recording of Entergy Louisiaii's" decommissioning obligations changed significantly with the implementation of SFAS 143. The most significant differences in the measurement of these obligations are outlined below:
* 'Recordinn of full obligation - SFAS 143 requires that the fair value of an'asset retirement obligation be recorded when it is incurred. This caused'the recorded decommissioning obligation of Entergy Louisiana to increase significantly,' as Entergi Louisiana had previously only recorded this obligation ag thie related costs were collected from customers, and as earnings were recorded on the related trust funds.
- Fair valtie approacl - SFAS 143 requires that these obligations be measured using a fair value'approach.
Among other things, this entails the assumption'that the costs'will be incurred by a third party and will therefore include appropriate profit margins and risk piemiuims. Entergy Louisiana!s decommissioning studies had been based on Entergy Louisiana performing the work, and did not include any such margins or premiums. I
- Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted risk-free rate.
The net effect of implementing SFAS 143 for Entergy Louisiana was recorded as a regulatory asset, with no resulting impact on Entergy' Louiiana's net income." Entergy Louisiana' recorded this regulatory asset because its existing rate mechanism is based on the original br historical cbst standard that allows Entergy Louisiana to recover all ultimate costs of decommissioning existing assets from current and future customers. Upon implementation of SFAS 143 in 2003, assets and liabilities increased by $305 million as a result of recording the asset retirement obligation at its fair value of $305 million as determined under SFAS 143, increasing total utility plant by $99 millioi4'reducing accumulated depreciation by $82 million, and recording the related regulatory asset of $124 million. Unbilled Revenue ' - As discussed in Note I to the domestic utility companies and System Energy financial statements, Entergy Louisiana records an estimate of the revenues earned' for energy delivered since the latest'customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. Thee difference between the estimate of the unbilled receivable' at the beginning of the period and the end' of the period is the amount' of unbilled revenue recognized during the period. The'estimate recorded is 214
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month, including fuel price. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period and fuel price fluctuations, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regarding price such as the fuel cost recovery mechanism. Pension and Other Postretirement Benefits' Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 10 to the domestic -utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate. Assumptions Key actuarial assumptions utilized in determining these costs include:
- Discount rates used in determining the future benefit obligations;
- Projected health care cost trend rates;
- Expected long-term rate of return on plan assets; and
- Rate of increase in future compensation levels.
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and worse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported' costs; for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions'. In selecting an assumed discount rate to calculate benefit obligations, Enttrgy reviews market yields on high-quality corporate debt and matches these rates with' Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 6.75% in 2002 to 6.25% in 2003 'and to 6% 'in 2004.' 'Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rate assumption used in calculating the December 31,' 2004 accumulated postretirement beneifit obligation to a 10% increase in health care costs 'in 2005 graddally'decreasing each successive year, until it reaches a 4.5% annual increase in health care costs in 2011 and beyond: In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities, and 4% other investments. The target allocation for Entergy's other postretirement'benefit assets is 5,1% equity securities and 49% fixed income securities. Based on recent market trends, Entergy reduced its expected long-term rate of return on plan assets used io calculate benefit obligations from'8.75% f6r 2002'and 2003 to 8.5% in'2004. The assumed rate of increase in future compensation levels used to calculate benefit obligations was 3.25% in 2002, 2003; and 2004.
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Entergy Louisiana, Inc. Management's Financial Discussion and Analysis Cost Sensitivity The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (dollars in thousands): Change in Impact on 2004 Impact on Projected Actuarial Assumption Assumption Pension Cost, Benefit Obligation Increase/(Decrease) Discount ratei (0.25%) $1,061 $12,385 Rate of return on plan assets (0.25%) $786 Rate of increase in compensation 0.25%- $523 $3,018 The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (dollars in thousands): -, Impact on Accumulated Change in Impact on 2004 Postretirement Benefit Actuarial Assumption Assumption Postretirement Benefit Cost Obligation Increase/(Decrease) Health care cost trend 0.25% $416 $2,407 Discount rate (0.25%) $234 $3,033 Each fluctuation above assumes that the other components of the calculation are held constant. Accounting Mechanisms. In accordance with SFAS No. 87, "Employers' Accounting for Pensions," Entergy utilizes a number, of accounting mechanisms that reduce the volatility of reported pension costs. Differences between, actuarial assumptions and actual plan results are deferred and are amortized into cost only when the accumulated differences exceed 10%, of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.,,, Additionally, Entergy accounts for the impact of asset performance on pension expense oyer a twenty<- quarter phase-in period through a. "market-related" value of assets calculation, Since the market-related yalue of assets recognzes investment gains or losses over a twenty-quarter period, the future value of assets will, be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87. Costs and Funding Total pension cost for Entergy Louisiana in 2004 was $3.3 million. Entergy Louisiana anticipates 2005 pension cost to increase, to $6.8 million due to decrease in the discount rate (from 6.25% to. 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. Entergy Louisiana contributed $3.9 million to its pension plan in 2004 and anticipates making $2.6 million in contributions in 2005. The decrease in pension funding requirements is due to the Pension Funding Equity Act relief passed in April 2004, partially offset by declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002. Entergy Louisiana's accumulated benefit obligation at December 31, 2004, and 2002 exceeded plan assets. As a result, Entergy Louisiana was required to recognize an additional minimum liability as prescribed by SFAS 87 in those years. At December 31, 2003, Entergy Louisiana's accumulated benefit obligation was less than plan assets, therefore there was no additional minimum pension liability required to be recognized. At December 31, 2004, Entergy Louisiana recorded an additional pension minimum liability of $38.9 million; an offsetting intangible 216
Entergy Louisiana, Inc. Management's Financial Discussion and Analysis asset of $4.8 million, and a regulatory asset of $34.1 million. Net income for 2004, 2003, and 2002 was not impacted by the additional minimum pension liability. Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2004 were $12.3 million, including $2.8 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Louisiana expects 2005 postretirement health care and life insurance benefit costs to approximate $12.7 million, including $3.2 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the decrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate used to calculate benefit obligations. 217
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders Entergy Louisiana, Inc.: We have audited the accompanying balance sheets of Entergy Louisiana, Inc. as of December 31, 2004 and 2003, and the related statements of income, retained earnings, and cash flows (pages 219 through 224 and applicable items in pages 284 through 348) for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Louisiana, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 5 and Note 8 to the notes to respective financial statements, in 2003 Entergy Louisiana, Inc. adopted the provisions of Statement of Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, and Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting. DELOITTE & TOUCHE LLP New Orleans, Louisiana March 8, 2005 218
ENTERGY LOUISIANA, INC. INCOME STATEMENTS For the Years Ended December 31, 2004 2003 2002 (In Thousands) OPERATING REVENUES Domestic electric $2,226,986 $2,165,570 $1,815,352 OPERATING EXPENSES Operation and Maintenance: Fuel, fuel-related expenses, and gas purchased for resale 671,549 525,645 436,568 Purchased power 667,893 668,337 438,627 Nuclear refueling outage expenses 13,633 11,130 11,502 Other operation and maintenance 367,824 376,770 340,803 Decommissioning 21,958 20,569 10,422 Taxes other than income taxes 68,999 70,084 60,698 Depreciation and amortization 197,380 192,972 182,871 Other regulatory charges (credits) - net (43,765) (2,860) 17,219 TOTAL 1,965,471 1,863,347 1,498,710 OPERATING INCOME 261,515 302,223 316,642 OTHER INCOME Allowance for equity funds used during construction 7,494 6,900 5,195 Interest and dividend income 8,209 8,820 7,668 Miscellaneous - net (929) (3,100) (3,244) TOTAL 14,774 12,620 9,619 INTEREST AND OTHER CHARGES Interest on long-term debt 70,210 73,227 98,242 Other interest - net 3,931 3,529 2,425 Allowance for borrowed funds used during construction (4,822) (5,475) (3,880) TOTAL 69,319 71,281 96,787 INCOME BEFORE INCOME TAXES 206,970 243,562 229,474 Income taxes 79,475 97,408 84,765 NET INCOME 127,495 146,154 144,709 Preferred dividend requirements and other 6,714 6,714 6,714 EARNINGS APPLICABLE TO COMMON STOCK $120,781 $139,440 $137,995 See Notes to Respective Financial Statements. 219
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ENTERGY LOUISIANA, INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2004 2003 2002 (In Thousands) OPERATING ACTIVITIES Net Income $127,495 $146,154 $144,709 Adjustments to reconcile net income to net cash flow provided by operating activities: Reserve for regulatory adjustments 14,076 1,858 Other regulatory charges (credits) - net (43,765) (2,160) 17,219 Depreciation, amortization, and decommissioning 219,338 213,541 193,293 Deferred income taxes and investment tax credits 75,078 859,157 39,849 Changes in working capital: Receivables (36,185) (4,418) (68,936) Accounts payable (36,862) 49,028 7,370 Taxes accrued 89,079 (804,805) 779,590 Interest accrued (1,791) (10,324) (3,971) Deferred fuel costs 21,955 (56,211) (41,891) Other working capital accounts 20,693 10,395 (118,718) Provision for estimated losses and reserves 6,119 12,194 5,818 Changes in other regulatory assets (14,456) 59,169 (23,879) Other (16,056) (59,639) 105,324 Net cash flow provided by operating activities 424,718 413,939 1,035,777 INVESTING ACTIVITIES Construction expenditures (240,283) (257,754) (209,826) Allowance for equity funds used during construction 7,494 6,900 5,195 Nuclear fuel purchases (41,525) (50,473) Proceeds from the sale/leaseback of nuclear fuel 41,525 50,473 Decommissioning trust contributions and realized change in trust assets (12,615) (17,506) (13,854) Changes in other investments - net 2,173 (12) 6,152 Net cash flow used in investing activities (243,231) (268,372) (212,333) FINANCING ACTIVITIES Proceeds from the issuance of long-term debt 282,745 144,679 Retirement of long-term debt (203,756) (296,366) (300,617) Repurchase of common stock (120,000) Dividends paid. Common stock (116,500) (145,500) (271,400) Preferred stock (6,714) (6,714) (6,714)
.(44,225) (448,580) (554,052)
Net cash flow used In financing activities Net increase (decrease) in cash and cash equivalents 137,262 (303,013) 269,392 Cash and cash equivalents at beginning of period 8,787 311,800 42,408 Cash and cash equivalents at end of period $146,049 $8,787 $311,800 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid/(received) during the period for Interest - net of amount capitalized $73,170 $84,089 $99,998 Income taxes ($70,650) $35,128 ($781,540) See Notes to Respective Financial Statements. 221
ENTERGY LOUISIANA, INC.
- BALANCE SHEETS ASSETS December 31, 2004 2003 (In Thousands)
CURRENT ASSETS Cash and cash equivalents: Cash $3,875 $8,787 Temporary cash investments - at cost, which approximates market
- 142,174 __ _ _ _
Total cash and cash equivalents. I 146,049 8,787 Accounts receivable: Customer 88,154 93,393 Allowance for doubtful accounts (3,135) (4,487) Associated companies 43,121 9,074 Other 13,070 12,334 Accrued unbilled revenues 143,453 138,164 Total accounts receivable 284,663 248,478 Deferred fuel costs 8,654 30,609 Accumulated deferred income taxes 12,712 Materials and supplies - at average cost 77,665 74,349, Deferred nuclear refueling outage costs 5,605 19,226 Prepayments and other 6,861 67,623 TOTAL 542,209 449,072 OTHER PROPERTY AND INVESTMENTS Investment in affiliates - at equity - 14,230 14,230 Decommissioning trust funds 172,083 151,996 Non-utility property - at cost (less accumulated depreciation) 21,176 21,307 Other 4 2,177 TOTAL 207,493 189,710 UTILITY PLANT Electric 5,985,889 5,836,914 Property under capital lease 250,964 250,102 Construction work in progress 188,848 172,405 , Nuclear fuel under capital lease 31,655 65,066 TOTAL UTILITY PLANT 6,457,356 6,324,487 Less - accumulated depreciation and amortization 2,799,936 2,686,778 UTILITY PLANT - NET 3,657,420 3,637,709 1 . . . DEFERRED DEBITS AND OTHER ASSETS Regulatory assets: SFAS 109 regulatory asset - net 132,686 156,111 Other regulatory assets 302,456 217,689 Long-tern receivables 10,736 1,511 Other !i 25,994 22,737 TOTAL 471,872 398,048 TOTAL ASSETS $4,878,994 $4,674,5~ 9 See Notes to Respective Financial Statements. 222
ENTERGY LOUISIANA, INC. BALANCE SHEETS LIABILITIES AND SHAREHOLDERS' EQUITY December 31, 2004 2003 (In Thousands) CURRENT LIABILITIES Currently maturing long-term debt $55,000 $14,809 Accounts payable: Associated companies 57,681 101,191 Other 128,523 121,875 - Customer deposits 66,963 61,215 Accumulated deferred income taxes 566 Taxes accrued 7,268 18,438 20,229 Interest accrued Obligations under capital leases 22,753 35,506 Other 10,428 5,110 TOTAL 367,054 360,501 NON-CURRENT LIABILITIES Accumulated deferred income taxes and taxes accrued 1,805,410 1,728,156 Accumulated deferred investment tax credits 96,130 101,258 Obligations under capital leases 8,903 29,560 Other regulatory liabilities 51,260 39,026 Decommissioning liabilities 347,255 325,298 Accumulated provisions 92,653 86,534 Long-term debt 930,695 887,687 Other 106,815 47,981 TOTAL 3,439,121 3,245,500 SHAREHOLDERS' EQUITY Preferred stock without sinking fund 100,500 100,500 Common stock, no par value, authorized 250,000,000 shares; issued 165,173,180 shares in 2004 and 2003 1,088,900 1,088,900 Capital stock expense and other (1,718) (1,718) Retained earnings 5,137 856 Less - treasury stock, at cost (18,202,573 shares in 2004 and 2003) 120,000 120,000 TOTAL 1,072,819 1,068,538 Commitments and Contingencies TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $4,878,994 $4,674,539 See Notes to Respective Financial Statements. 223
ENTERGY LOUISIANA, INC. STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 2004 2003 2002 (In Thousands) Retained Earnings, January I $856 $6,916 $140,321 Add: Net income 127,495 146,154 144,709 Deduct: Dividends declared: Preferred stock 6,714 6,714 6,714 Common stock 116,500 145,500 271,400 Total 123,214 152,214 278,114 Retained Earnings, December 31 .$5,137 $856 $6,916 See Notes to Respective Financial Statements. 224
ENTERGY LOUISIANA, INC. SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 2004 2003 2002 2001 2000 (In Thousands) Operating revenues $2,226,986 $2,165,570 $1,815,352 $1,901,913 $2,062,437 Net Income $127,495 $146,154 $144,709 $132,550 $162,679 Total assets $4,878,994 $4,674,539 $4,753,704 $4,149,701 $4,289,409 Long-term obligations (1) $939,598 $917,247 $919,319 $1,197,473 $1,411,345 (1) Included long-term debt (excluding currently maturing debt), preferred stock with sinking fund (for the year 2000 only), and noncurrent capital lease obligations. 2004 2003 2002 2001 2000 (Dollars In Millions) Electric Operating Revenues: Residential $770 $739 $638 $658 $717 Commercial 501 473 403 429 441 Industrial 779 723 637 760 767
. jq Governmental 38 41 36 39 39 Total retail 2,088 1,976 1,714 1,886 1,964 Sales for resale:
Associated companies 96 102 8 25 21 Non-associated companies 13 12 11 23 40 Other 30 76 82 (32) 38 Total $2,227 $2,166 $1,815 $1,902 $2,063 Billed Electric Energy Sales (GWh): Residential 8,842 8,795 8,780 8,255 8,648 Commercial 5,762 5,622 5,538 -5,369 5,367 Industrial 13,140 12,870 14,738 14,402 15,184 Governmental 439 491 510 498 481 Total retail 28,183 27,778 29,566 28,524 29,680 Sales for resale: . 1 Associated companies 1,129 1,344 146 381 228 Non-associated companies - 122 132 139 334 554 Total 29,434 29,254 29,851 29,239 -30,462i 225
ENTERGY MISSISSIPPI, INC . . MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS Results of Operations Net Income
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2004 Compared to 2003 .i Net' income increased $6.4 milfion pimariy d ie to highr'At revenue, partially offset by higher other operation and maintefianc6'bxpefses 'ahd higher taxes other than iico6fiitaxes. 2003 Compared to 2002 . ,(' idib , . ni F. TT2 ei ViJ'i Net income increased $14.7 million primarily due to highfer net revenue, partially offset by higher other operation and maintenance expenses and depreciation and amortization expenses, and lower interest income. Net Revenue 2004 Compared to 2003 .- Ks. Net revenue, which is Entergy Mississippi's measure of gross margin, consists of operating revenues net of. 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2004 to 2003. . ' .' i ( In Millions) --' 2003 net revenue"- $426.6 .. Volume/weather 6.4 . iA . - Net wholesale revenue . 5.0 Other ... -- 5.5 2004 net revenue $443.5
. ii,!. ;_ix lt .i s I ..t1s if Ui The volume/weather variance resulted from an increase of 247 GWh in weather-adjusted usage, partially offset by the effect of milder weather on billed sales. C The net wholesale revenue variance resulted from an increase in energy available for resale sales, partially offset by a decrease in the average price of energy supplied for affTliated sales.
Gross operatingrevenues, fuel andpurchasedpower expenses, and other regulatory charges (credits) Gross operating revenues increased primarily due to an increase of $174.0 million in fuel cost recovery revenues due to higher fuel rates and an increase of $26;3 nmillion in gross wholesale revenue. The increase was partially offset by a decrease of $37.6 million in Grand Gulf revenueasa result of the cessation of the Grand Gulf Accelerated Tariff in July 2003. Fuel and purchased power expenses increased primarily due to the over-recovery of fuel and purchased power costs as a result of higher fuel rates. Entergy Mississippi's fuel rates include an energy cost recovery rider to recover projected energy costs. Actual fuel and purchased power costs were lower than those projected in the computation of the energy cost factors for the third quarter of 2004 which contributed to the over-recovery of fuel and purchased power costs. The MPSC has allowed Entergy Mississippi to refund these over-recoveries in the second and third quarters of 2005. The energy cost recovery rider is discussed in more detail in Note 2 to the domestic and System Energy financial statements. 226
Entergy Mississippi, Inc. Management's Financial Discussion and Analysis Other regulatory charges (credits) have no material effedf on net income due to recovery and/or refund of such expenses. Other regulatory credits increased primarily due to the under-recovery through the Grand Gulf rider of Grand Gulf capacity charges. 2003 Compared to 2002
.... ~~~~~~ .~. .v i..r > i Jimi:.pi&fN4.j.i- <s,> . .i';tL';
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~ill*iJ,,,ij .ik!'i-.:: . is)- Lji: js.,vi Net revenue, which is Entergy Mississippi's measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2003 to 2002.
- ,;.' E L . :.'. iA. . ii in ;., ai tJ 8. (InlMillions) :;
i hi-~a~i 2002 net revenue - ;j; r>tti' $380.2 - .. ii; s Base rates ;X')ti /48.3 i,; Other (1.9) 2003 net revenue $426.6
- t.
The increase in base rates was effective January 2003 as approved by the MPSC. Gross operatingrevenue, fuel andpurchase^dpowerexpeA ss, and6Kherregutatorycharges credits) Gross operating eivenues increased primarily due to an increase in base rates effective January 2003 and an increase of $29.7 million in fuef cost recovery revenues due to quarterly changes in the fuel factor resulting from the increases in market prices of natural gas and purchased power. This increase was partially offset by a decrease of
$35.9 million in gross' wholesale reveilue as a result of decreasedgen6iation and purchasesthat resulted inless' energy available for resale sales.
Fuel and fuel-related expenses decreased primarily due to the decreased recovery of fuel and purchased power costs and decreasedgeiieration, partially offset by an increase in the market price of purchased power. i Other regulatory' charges increased primarily due to ov-reeioV6ry of capacity charges'-related to the Grand Gulf rate rider and the cessation of the Grand Gulf Accelerated Recovery Tariff that was suspended in July 2003. Other Income Statement Variances 2004 Compared to 2003 jij a C~v tL ; JlL-ilL' 1fl .. b; j I Other operation and maintenance expenses increased primarily due to: -A.o
- an increase of $6.6 million in customer service support ccsts; and i .. . . .,i ,. ,...i,.
- an increase of $3.7 million in benefit costs.
The increase was partially offset by the absence of the voluntary' tvfihe frorgraff accfrials of $7.1 million that occurred in 2003. Taxes other than income taxes increased primarily due to a higher assessment of ad valorem and franchise taxes compared to the same period in 2003. 2003 Compared to 2002 Other operation and maintenance expenses increased' primarily due to:
- voluntary severance program accruals of $7.1 million; and " '"
- anincreage of $4.4 million in benefit costs. h , i ; . , e -
227
Entergy Mississippi, Inc. Management's Financial Discussion and Analysis The increases were partially offset by a decrease of $4.0 million in plant maintenance expense due to outage costs at a fossil plant in 2002. Depreciation and amortization expense increased due to an increase in plant in service. Interest and dividend income decreased as result of carrying charges associated with under-recovery of fuel and purchased power costs during 2002. Income Taxes The effective income tax rates for 2004, 2003, and 2002 were 33.5%, 33.9%, and 25.4%, respectively. See Note 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate. Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet. Liquidity and Capital Resources Cash Flow Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows: 2004 2003 2002 (In Thousands) Cash and cash equivalents at beginning of period $63,838 $147,721 $54,048 Cash flow provided by (used in): Operating activities 258,179 253,288 156,868 Investing activities (151,505) (264,495) (35,122) Financing activities (90,116) (72,676) 71,927 Net increase (decrease) in cash and cash equivalents 16,558 (83,883) 93,673
$7.2 Cash and cash equivalents at end of period $80,396 $63,838 $147,721
. i .1 i . ;, ; ., .
Operating Activities Cash flow from operations increased by $4.9 million in 2004 primarily due to money pool activity and an increase in recovery of deferred fuel and purchased power costs, partially offset by an $12 million income tax payment in 2004 compared to a $78 million income tax refund in 2003 and an increase in the account receivable balance as a result of the timing of customer collections.. Cash flow from operations increased by $96.4 million in 2003 primarily due to a $78 million income tax refund and increased net income, partially offset by money pool activity. Entergy Mississippi's receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years:. 2004 2003 2002 2001 (In Thousands)
$21,584 $22,076 $8,702 $11,505 Money pool activity provided $0.5 million of Entergy Mississippi's operating cash flows in 2004, used $13.4 million of its operating cash flows in 2003, and provided $2.8 million of its operating cash flows in 2002.
228
Entergy Mississippi, Inc. Management's Financial Discussion and AMalysis See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool. Investing Activities Net cash used in investing activities decreased $113.0 million in 2004 primarily due to:
- cash used in 2003 for other regulatory investments of $72.6 million as a result of under-recovered fuel and purchased power costs;
- a decrease of $25.6 million in capital expenditures in 2004 due to decreased spending on customer care projects and less transmission upgrade work requested by merchant generators; and -'
- the maturity in 2004 of $7.5 million of other temporary investments that had been made in 2003, which provided cash in 2004.
Net cash used in investing activities increased $129.4 in 2003 primarily due to cash used for other regulatory investments of $72.6 million as a result of under-recovered fuel and purchased power costs and other temporary cash investments of $18.6 million that provided cash in 2002 upon maturity. In May 2003, Entergy Mississippi filed and the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Under the MPSC's order, Entergy Mississippi deferred until 2004 the collection of fuel under-recoveries for the first and second quarters of 2003 that would have been collected in the third and fourth quarters of 2003, -respectively. The deferred amount of-$77.6 million plus carrying charges was collected over a twelve-month period that began in January 2004. Financing Activities Net cash used in financing activities increased $17.4 million in 2004 primarily due to an increase of $15.1 million in dividends paid. Net cash used in financing activities increased $144.6 million in 2003 primarily due to a decrease in net issuances of long-term debt. See Note 5 to the domestic utility companies and System Energy financial statements for details on long-term debt. Uses of Capital Entergy Mississippi requires capital resources for:
- construction and other capital investments;
- debt and preferred stock maturities;
- working capital purposes, including the financing of fuel and purchased power costs; and
- dividend and interest payments.
Following are the amounts of Entergy Mississippi's planned construction and other capital investments, and existing debt obligations: 2005 2006-2007 2008-2009 Afteri 2009 Total (In Millions) Planned construction and capital investment (1) $147 $381- N/A N/A $528 Long-term debt - - $100 $595 $695 Operating leases $7 $10 $6 $11 $34 Purchase obligations (2) $190 $361 $336 $2,059 $2,946 229
Entergy Mississippi, Inc. Managements Financial Discussion and Analysis (1) Includes approximately $120 to 140 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems, and to support normal customer growth. (2) Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Mississippi almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the domestic utility companies and System Energy financial statements. In addition to these contractual obligations, Entergy Mississippi expects to contribute $3.4 million to its pension plans and $4.2 million to other postretirement plans in 2005 The planned capital investment estimate for Entergy Mississippi reflects capital required to support existing business, customer growth, and the anticipated acquisition of additional generation supply resources. The estimated capital expenditures are subject to periodic review and modification and may, vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the domestic utility companies and System Energy financial statements. As a wholly-owned subsidiary, Entergy Mississippi dividends its earnings to Entergy Corporation at a percentage determined monthly. Entergy Mississippi's long-term-debt indentures, restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock. As of December 31, 2004, Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $68.5 million. Sources of Capital-Entergy Mississippi's sources to meet its capital requirements include: s r - ' H , H 3 .
- internally generated funds;
- cash on hand;
--
- debt or preferred stock issuances; and
- bank financing under new or existing facilities.
The following table lists First Mortgage Bonds issued by Entergy Mississippi in 2004: Issue Date Description Maturity Amount (In Thousands) April 2004 6.25% Series April 2034 $100,000 April 2004 4.65% Series May 2011 80,000
$180,000 The following table lists First Mortgage Bonds retired by Entergy Mississippi in 2004-Retirement Date Description Maturity Amount (In Thousands)
May 2004 6.20% Series May 2004 $75,000 May 2004 6.45% Series April 2008 80,000 May 2004 7.70% Series July 2023 60,000
$215,000 230
Entergy Mississippi, Inc. Management's Financial Discussion and Analysis In September 2004, Entergy Mississippi arranged the issuance of $16 million of Mississippi Business Finance Corporation 4.60% Series Pollution Control Revenue Refunding Bonds (Entergy Mississippi, Inc. Project) Series 2004 due April 2022. The proceeds from this issuance were used to redeem prior to maturity, $7.9 million of 7.0% Series Washington County Bonds due April 2022 and $8.1 million of 7.0% Series Warren County, Mississippi Bonds due April 2022. Entergy Mississippi may refinance or redeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable. All debt and common and preferred stock issuances by Entergy Mississippi require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy Mississippi has sufficient capacity under these tests to meet its foreseeable capital needs. Entergy Mississippi has a 364-day credit facility available expiring May 2005 in the amount of $25 million of which none was drawn at December 31, 2004. Borrowings and securities issuances by Entergy Mississippi are limited to amounts authorized by the SEC. The current short-term borrowing limitation, including borrowings under the money pool, is $160 million. Under its SEC Orders and without further SEC authorization, Entergy Mississippi cannot incur additional indebtedness or issue other securities unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy Mississippi, as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy Mississippi's short-term borrowing limits. Significant Factors and Known Trends Utility Restrueturing The'MPSC has recommended not pursuing open access at this time. At FERC, the pace of restructuring at the wholesale level has begun but has been delayed. It is too early to predict the ultimate effects of changes in U.S. energy markets. Restructuring issues are complex and are continually affected by events at the national, regional, state, and local levels. However, these changes may result, in the long-term, in fundamental changes in the way traditional integrated utilities and holding company systems, like the Entergy system, conduct their business. Some of these changes may be positive for Entergy, while others may not be. State and Local Rate Regulation The rates that Entergy Mississippi charges for electricity significantly influence its financial position, results of operations, and liquidity. Entergy Mississippi is closely regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the MPSC, is primarily responsible for approval of the rates charged to customers. As discussed in Note 2 to the domestic utility companies and System Energy financial statements, Entergy Mississippi made its annual formula rate plan filing with the MPSC in March 2004 based on a 2003 test year. In April 2004, the MPSC approved a joint stipulation entered into between the Mississippi Public Utilities Staff and Entergy Mississippi that provides for no change in rates based on an adjusted return on common equity' mid-point of 10.77%, establishing an allowed annual regulatory earnings range of 9.3% to 12.2%. In December 2002, the MPSC issued a final order approving a joint stipulation entered into by Entergy Mississippi and the Mississippi Public Utilities Staff in October 2002. The final order resulted in a $48.2 million rate increase effective January 2003. Entergy Mississippi's fuel costs recovered from customers are subject to regulatory scrutiny. Entergy Mississippi's retail rate matters and proceedings, including fuel cost recovery-related issues are discussed more thoroughly in Note 2 to the domestic utility companies and System Energy financial statements. 231
Entergy Mississippi, Inc. Managemenfs Financial Discussion and Analysis System Agreement Proceedings The domestic utility companies historically have engaged in the coordinated planning, construction, and operation of generating and transmission facilities under the terms of an agreement called the System Agreement that has been approved by the FERC. Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies in their execution of the System Agreement, and seek support for local regulatory authority over System Agreement issues. Regarding the proceeding at the LPSC, Entergy believes that state and local regulators are preempted by federal law from reviewing and deciding System Agreement issues for themselves. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting FERC rate schedules that are part of the System Agreement, and from subsequently enforcing that interpretation. The LPSC interpreted a System Agreement rate schedule in the unrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed the LPSCs decision. In 2003, the U.S. Supreme Court ruled in Entergy Louisiana's favor and reversed the decisions of the LPSC and the Louisiana Supreme Court. In February 2004, a FERC ALJ issued an Initial Decision in the LPSC-initiated proceeding at the FERC. The Initial Decision decided some issues in favor of the relief sought by the LPSC, and decided some issues against the relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the AL's Initial Decision. Entergy's exceptions to the AL's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization, which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method. If the FERC grants the relief requested by the LPSC in the proceeding, the relief may result, in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average. If the FERC adopts the ALJ's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The AL's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost. An assessment of the potential effects of the ALUs Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu during the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 232
Entergy Mississippi, Inc. Management's Financial Discussion and Analysis 2004. Based upon analyses considering the effect on future production costs if the FERC adopts the ALJ's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009: Average Annual Range of Annual Payments Payments or (Receipts) or (Receipts) for 2005-2009 Period' (In Millions) (In Millions) Entergy Arkansas $154to$281 $215 Entergy Gulf States ($130) to ($15) ($63) Entergy Louisiana ($199) to ($98) ($141) Entergy Mississippi ($16) to $8 $1 Entergy New Orleans ($17) to ($5) ($12) Management believes that.any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. Although the outcome and timing of the FERC,; APSC, and other proceedings cannot be predicted at this time, Entergy Mississippi does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation. In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC AL's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the AL's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; and states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate. In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, or show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the ALUs Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies'; overall production costs. Procedural schedules have not been established in these APSC investigations. In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, 'exceeds the City Council's jurisdiction 'and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy, seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Louisiana, as 233
Entergy Mississippi, Inc. Managemenfs Financial Discussion and Analysis well as the named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption. In February 2005, the state court!issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity. Transmission In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs. In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy, region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's; transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations. Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' -needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences. In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the 'petition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005. In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various. parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing has not been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the 234
Entergy Mississippi, Inc. Management's Financial Discussion and Analysis transmission pricing aspects of the ICT proposal is scheduled for May 2005, with a separate hearing on the WPP portion of the proposal currently scheduled for August 2005. Interconnection Orders The domestic utility companies (except Entergy New Orleans) are currently defendants to several complaints and rehearing requests before the FERC in which independent generation entities (GenCos) are seeking a refund of monies that the GdnCos had previously paid to the Entergy companies 'for facilities necessary to connect their generation facilities to Entergy's transmission system. 'The FERC has issued initial orders in response to two of the complaints and in certain other dockets ordering Entergy to refund approximately $100 million in expenses and tax obligations previously paid by the GenCos, including $27 million for Entergy Mississippi. The refunds will be in the form of transmission credits that will be utilized over time as the GenCos take transmission service from Entergy. To the extent the Entergy companies are ordered to provide such refunds, these costs will qualify for inclusion in the Entergy companies' rates. The recovery of these costs is not automatic, however, especially at the retail level, where the majority of the cost recovery would occur. Entergy intends to pursue all regulatory and legal avenues available to it in order to have these orders reversed and have the affected interconnection agreements reinstated as agreed to originally by the generators. ' Available Flowgate Capacity Proceeding On December 17, 2004, the FERC issued an order initihting a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff, and establishing a refund effective date. In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised 'in a FERC audit report finding errors and problems with the predecessor methodology used by Enteigy for evaluating short-term' transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC program, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and'(iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory.' Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program: Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy. Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the AFC proceeding is currently scheduled to commence in August 2005.' Market and Credit Risks Entergy Mississippi has certain market and credit risks inherent in its business operations. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. 235
Entergy Mississippi, Inc. Management's Financial Discussion and Analysis Critical Accounting Estimates . The preparation of Entergy Mississippi's financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential, for future changes in the assumptions and measurements could produce estimates that would have a material impact on the presentation of Entergy Mississippi's financial position or results of operations. Unbilled Revenue As discussed in Note I to the domestic utility companies and System Energy financial statements, Entergy Mississippi records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regarding price such as the fuel cost recovery mechanism. Pension and Other Postretirement Benefits Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 10 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate. Assumptions Key actuarial assumptions utilized in determining these costs include:;
- Discount rates used in determining the future benefit obligations;.
- Projected health care cost trend rates;
- Expected long-term rate of return on plan assets; and
- Rate of increase in future compensation levels.
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and worse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions. In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy's projected streamii of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to 'calculate benefit obligations from 6.75% in 2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent, cost 'trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to a 10% 236
Entergy Mississippi, Inc. Managemenfs Financial Discussion and Analysis increase in health care costs in 2005 gradually decreasing each successive year, until it reaches a 4.5% annual increase in health care costs in 2011 and beyond. In determining its expected long-term rate of return on plan assets, Entergy reviews past, long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed incomre securities, and 4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities and 49% fixed income securities. Based on recent market trends, Entergy reduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 8.75% for 2002 and 2003 to 8.5% in 2004. The assumed rate of increase in future compensation levels used to calculate benefit obligations was 3.25% in 2002,.2003, and 2004. Cost Sensitivity The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (dollars in thousands): - Change in Impact on 2004 Impact on Projected Actuarial Assumption Assumption Pension Cost Benefit Obligation Increase/(Decrease) Discount rate (0.25%) $598 $6,213 Rate of return on plan assets (0.25%) $420 Rate of increase in compensation 0.25% $271 $1,463 The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (dollars in thousands): Impact on Accumulated Change in Impact on 2004 Postretirement Benefit Actuarial Assumption Assumption Postretirement Benefit Cost Obligation Increase/(Decrease) Health care cost trend 0.25% $174 $1,161 Discount rate (0.25%) $110 $1,519 Each fluctuation above assumes that the other components of the calculation are held constant. Accounting Mechanisms In accordance with SFAS No. 87, "Employers' Accounting for Pensions," Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into cost only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. Additionally, Entergy accounts for the impact of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87. 237
Entergy Mississippi, Inc. Managements Financial Discussion and Analysis Costs and Funding . l . . , Total pension cost for Entergy Mississippi in 2004 was $2.1 million. Entergy anticipates 2005 pension cost to increase to $4.4 million due to decrease in the discount rate (from, 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit, obligations, Entergy Mississippi contributed $1.8 million to its pension plan in 2004, and anticipates making $3.4 million incontributions in 2005, The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, partially offset by the Pension Funding Equity Act relief passed in April 2004. Entergy Mississippi's accumulated benefit obligation at December 31, 2004, 2003, and 2002 exceeded plan assets. As a result, Entergy Mississippi was required to recognize an additional minimum liability as prescribed by SFAS 87. At December 31, 2004, Entergy Mississippi increased its additional minimum liability to $23.5 million from $7.3 million at December 31, 2003. Entergy Mississippi increased its intangible asset for the unrecognized prior service cost to $3.3 million at December 31, 2004 from $0.9 million at December 31, 2003. Entergy Mississippi also increased the regulatory asset to $20.2 million at December 31, 2004 from $6.4 million at December 31, 2003. Net income for 2004, 2003, and 2002 was not impacted. Total postretirement health care and iife insurance benefit costs for Entergy Mississippi in 2004 were $3.8 million, including $1.7 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Mississippi expects 2005 postretirement health care and life insurance benefit costs to approximate $4.2 million, including $1.9 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life insurance benefit costs is due to the decrease in the discount rate (from 6 .25% to 6.00%) and an increase in the health care cost trend rate used to calculate benefit obligations.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders Entergy Mississippi, Inc.: We have audited the accompanying balance sheets of Entergy Mississippi, Inc. as of December 31, 2004 and 2003, and the related statements of income, retained earnings, and cash flows (pages 240 through 244 and applicable items in pages 284 through 348) for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Mississippi, Inc., as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's -assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting. DELOITTE & TOUCHE LLP New Orleans, Louisiana March 8, 2005 239
ENTERGY MISSISSIPPI, INC. INCOME STATEMENTS . -, ; ; f - For the Years Ended December 31, 2004 2003 20022 (In Thousands)
- OPERATING REVENUES ! I ., . I, ,, 1 ,
Domestic electric $1,1213,629. . 1,035,360 , $991,095 OPERATING EXPENSES I -, Operation and Maintenance: !. X I Fuel, fuel-related expenses, and gas purchased for resale 335,271 155,168 318,350 Purchased power 436,013 .449,971 315,963 Other operation and maintenance 178,007 174,192 170,052 Taxes other than income taxes 53,443 47,734 47,093 Depreciation and amortization 65,452 62,984 55,409 Other regulatory charges (credits) - net (1,171) 3,664 (23,432) TOTAL 1,067,01o 893,713 884,32a OPERATING INCOME 146,614 141,647 106,766 OTHER INCOME Allowance for equity funds used during construction 4,402 ' 4,576 1 3,844'- Interest and dividend income : 2,550 : 1,030.
. , 4,213 Miscellaneous - net (1,508) (2,242) . . (2,572)
TOTAL 5,444 3,364 5,485 I I' I* , ; INTEREST AND OTHER CHARGES
" I . . C .
Interest on long-term debt :41,681 i 43,879- !42,580 Other interest - net 2,956 3,585 l : 2,884 '- . . ,I -1 : Allowance for borrowed funds used during construction (3,116) . (3,942) (3,'467) :. ' 7. ;1. 4 -[ ' TOTAL 41,521 43,522 ;41,9970 : : ':;. fi. - , 1 3 10.,4.9 ;. , ! i .1 : (1 1 1 INCOME BEFORE INCOME TAXES . 11,537 101,499 '70,254
, "; I m , .'
Income taxes 37,040 34,431 17,846 NET INCOME 73,497 67,058k 52,408 . . . I . Preferred dividend requirements and other 3,369 3,369 3,369 i
. ,¢ I . ;.
EARNINGS APPLICABLE TO COMMON STOCK $70,128 $63,689 $49,039 See Notes to Respective Financial Statements. 240
ENTERGY MISSISSIPPI, INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2004 2003 2002 (In Thousands) OPERATING ACTIVITIES Net income $73,497 $67,058 $52,408 Adjustments to reconcile net income to net cash flow provided by - - operating activities: Other regulatory charges (credits) - net (1,171) 3,664 (23,438) Depreciation and amortization 65,452 62,984
- 55,409 Deferred income taxes and investment tax credits 61,829 34,836 (7,940)
Changes in working capital: Receivables (14,894) (23,179) * (2,000) Fuel inventory 940 575 (828) Accounts payable 432 1,244 16,736 Taxes accrued (27,759) 74,487 ; (2,670) Interest accrued (1,285) (5,922) 2,027 Deferred fuel costs 111,871 21,669 67,981 Other working capital accounts 2,684 11,255 (22,897) Provision for estimated losses and reserves 2,789 (1,i37) 386 Changes in other regulatory assets 9,401 (9,061) (6,028) Other (25,607) 14,815
- 27,722 Net cash flow provided by operating activities 258,179 253,288 156,868 INVESTING ACTIVITIES Construction expenditures (163,413) (188,995) (157,532)
Allowance for equity funds used during construction 4,402 4,576 3,844 Changes in other temporary investments - net 7,506 (7,506) 18,566 Other regulatory investments (72;570) Net cash flow used in investing activities (151,505) (264,495) (135,122) FINANCING ACTIVITIES Proceeds from the issuance of long-temri debt 178,510 292,393 167,596 Retirement of long-term debt (218,457) (330,000) (65,000) Dividends paid. Common stock (46,800) (31,700) (27,300) Preferred stock (3,369) (3,369) (3,369) Net cash flow provided by (used in) financing activities (90,116) (72,676) 71,927 Net increase (decrease) in cash and cash equivalents 16,558 (83,.883) 93,673 Cash and cash equivalents at beginning of period 63,838 147,721 54,048 Cash and cash equivalents at end of period $80,396 $63,838 $147,721 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid/(received) during the period for Interest - net of amount capitalized $43,824 S51,126 S40,572 Income'taxes S11,995 ($78,091) -$28,440 241
ENTERGY MISSISSIPPI, INC. BALANCE SHEETS ASSETS December 31, 2004 2003 (In Thousands)
. . ,* 1,
- I -
CURRENT ASSETS Cash and cash equivalents: Cash $4,716 .,$6,381 Temporary cash investment - at cost, which approximates market . I- .. 75,680 . 57,457 Total cash and cash equivalents 80,396 63,838 Other temporary investments - 7,506 Accounts receivable: Customer 68,821 f 59,729 Allowance for doubtful accounts (1,126) (1,375) Associated companies 22,616 25,935-Other 12,133 6,400 Accrued unbilled revenues 34,348 31,209 Total accounts receivable 136,792 121,898 Deferred fuel costs' 89,078 Accumulated deferred income taxes 27,924 - Fuel inventory - at average cost 4,137 5,077 Materials and supplies - at average cost 18,414 , 17,682 Prepayments and other 15,413 9,583 TOTAL 283,076 314,662 OTHER PROPERTY AND INVESTMENTS Investment in affiliates - at equity _ 5,531t 5,531 Non-utility property - at cost (less accumulated depreciation) 6,465 6,466 TOTAL 1 . .- 1996 1,997 I ,-. I j . ",! UTILITY PLANT Electric 2,385,465 2,24X,852 Property under capital lease 95 136 Construction work in progress 89,921. 108,829 V, TOTAL UTILITY PLANT 2,475,481 2,352,817 Less - accumulated depreciation and amortization .I 870,188. 837,492 . . UTILITY PLANT - NET 1,605,293 1,515,325 DEFERRED DEBITS AND OTHER ASSETS ; I,.,,. . , Regulatory assets: SPAS 109 regulatory asset - net 17,628 28,964 Other regulatory assets 82,674 -- I; 58,287 Long-term receivable 4,510 Other 31,009 23,117 TOTAL 135,821 110,368' TOTAL ASSETS $2,036,186 S1,952,352 See Notes to Respective Financial Statements. 242
ENTERGY MISSISSIPPI, INC. BALANCE SHEETS LIABILITIES AND SHAREHOLDERS' EQUITY December 31, 2004 2003 (in Thousands) CURRENT LIABILITIES Currently maturing long-term debt $75,000 Accounts payable: Associated companies 65,806 62,705 Other 25,543 28,212 Customer deposits 37,333 33,861 Taxes accrued 40,106 39,041: Accumulated deferred income taxes 7,120 Interest accrued 12,487 13,772 Deferred fuel costs 22,793 Obligations under capital leases 43 41 Other 8,341 2,567 TOTAL 212,452 262,319
- NON-CURRENT LIABILITIES Accumulated deferred income taxes and taxes accrued 438,321 385,395 Accumulated deferred investment tax credits 13,687 15,092
- 52 95 Obligations under capital leases Accumulated provisions 12,718 9,929 Long-term debt 695,073 654,956 Other 76,071 60,082 TOTAL 1,235,922 1,125,549 Commitments and Contingencies SHAREHOLDERS' EQUITY Preferred stock without sinking fund 50,381 50,381 Common stock, no par value, authorized 15,000,000 shares; issued and outstanding 8,666,357 shares in 2004 and 2003 199,326 199,326 Capital stock expense and other (59) (59)
Retained earnings 338,164 314,836 TOTAL 587,812 564,484 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $2,036,186 $1,952,352 See Notes to Respective Financial Statements. 243
ENTERGY MISSISSIPPI, INC. STATEMENTS OF RETAINED EARNINGS
. : 11 I - .
,; I* .1 ' ' ' r For the Years Ended December 31, 2004 2003 2002 (In Thousands)
Retained Earnings, January 1 $314,836;.. - $282,847 $261,108 Add: Net income 73,497 67,058 52,408 Deduct: Dividends declared: Preferred stock 3,369 3,369 3,369 Common stock 46,800 31,700 27,300 Total 50,169 35,069 30,669 Retained Earnings, December 31 $338,164 $314,836 $282,847 See Notes to Respective Financial Statements.
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ENTERGY MISSISSIPPI, INC. SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 2004 2003 2002 2001 2000 (In Thousands) Operating revenues $1,213,629 $1,035,360 $991,095 $1,093,741 $937,371 Net Income $73,497 $67,058 $52,408 $39,620 $38,973 Total assets $2,036,186 $1,952,352 $1,832,372 $1,683,026 $1,683,939 Long-term obligations (I) $695,125 $655,051 $510,240 $589,937 $584,678 (1) Included long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations.
- i 2004 2003 2002 2001 2000 (Dollars In Millions)
Electric Operating Revenues: Residential $467 $410 $375 $391 $341 Commercial 397 342 310 328 275 Industrial 204 174 165 ' 191 161 Governmental 38 32 29 31 26 Total retail . 1406 958 879 941 803 Sales for resale: 21 Associated companies 39 21 63 111 83 Non-associated companies 30 21 15 21 27 Other 39 35 34 22 25 Total $1,214 $1,035 $991 $1,095 $938 Billed Electric Energy Sales (GWh): Residential 5,085 5,092 5,092 4,867 4,976 Commercial 4,518 4,476 4,445 4,322 4,307 Industrial 2,977 2,939 2,910 3,051 3,188 Governmental 398 384 382 381 376 Total retail 12,978 12,891 12,829 12,621 .. 12,847 Sales for resale: Associated companies 305 112 1,123 1,728 1,276 Non-associated companies . 393 331 197 *289 313 Total 13,676 13,334 14,149 14,638 ; 14,436 245
ENTERGY NEW ORLEANS, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS Results of Operations Net Income (Loss) 2004 Compared to 2003 Net income increased $20.2 million primarily due to higher net revenue. 2003 Compared to 2002 - Entergy New ~Orleans had net income of $7.9 million in 2003 compared to a net loss in 2002. The increase was due to higher net revenue and lower interest - expense,. partially offset by higher other operation and maintenance expenses and depreciation and amortization expenses. Net Revenue 2004 Compared to 2003 Net revenue, which is Entergy New Orleans' measure of gross margin, consists of operating revenues net of: 1) fuel, fuel-related, and purchased power expenses and 2) other regulatory credits. Following is an'analysis of the change in net revenue comparing 2004 to 2003. (In Millions)
- 2003 net revenue $208.3 Base rates 10.6 Volume/weather 8.3 2004 deferrals 7.5 Price applied to unbilled electric sales 3.7 Other 0.6 2004 net revenue $239.0 The increase in base rates was effective June 2003. The rate increase is discussed in Note 2 to the domestic utility companies and System Energy financial statements.
The volume/weather variance is primarily due to increased billed electric-usage of:'162 GWh in the industrial service sector. The increase was partially offset by milder weather in the residential and commercial sectors. The 2004 deferrals variance is due to the deferral of voluntary severance plan and fossil plant maintenance expenses in accordance with a stipulation approved by the City Council in August 2004. The stipulation allows for the recovery of these costs through amortization of a regulatory asset. The voluntary severance plan and fossil plant maintenance expenses are being amortized over a five-year period that became effective January 2004 and January 2003, respectively. The formula rate plan is discussed in Note 2 to the domestic utility companies and System Energy financial statements. The price applied to unbilled electric sales variance is due to an increase in the fuel price applied to unbilled sales. 246
Entergy New Orleans, Inc. Managements Financial Discussion and Analysis Gross operatingrevenues, fuel andpurchasedpower expenses, andother regulatory credits Gross operating revenues increased primarily due to an increase in gross wholesale revenue as a result of an increase of $32.4 million in sales to affiliates and an increase of $28.7 million in fuel revenues due to higher fuel rates, in addition to the net revenue items mentioned above. Fuel and purchased power expenses increased primarily due to an increase in electricity generated and power purchased coupled with an increase in the' market prices of natural gas and purchased power. Other regulatory credits increased primarily due to a stipulation approved by the City Council in August 2004, as discussed above. 2003 CoMpared to 2002 Net revenue, which is Entergy New Orleans' measure of gross margin, consists, of operating revenues net of: 1) fuel, fuei-related, and purchased power expenses and 2) othei regulatory'credits. Following is an analysis of the change in net revenue comparing 2003 to 2002. (In Millions) 2002 net revenue ' $183.7 Base rates 15.9 Rate refund provisions ' ' ' 9.1 Other (0.4) 2003 net revenue $208.3 The increase in base rates was effective June 2003. The rate increase is discussed in Note 2 to the domestic utility companies and System Energy financial statements. Rate refund provisions increased net revenue due to -larger accruals for potential rate actions and refunds in 2002. Gross operatingrevenues andfuel andpurchasedpower expenses Gross operating revenues increased primarily due to an increase of $78.4 million in sales to affiliates. The increase was also attributable to a base rate increase and an increase in the market price of natural gas.
-Fuel and purchased power expenses increased primarily due to an increase in the market price of natural gas.
Other Income Statement Variances 2004 Compared to 2003 Other operation and maintenance expenses decreased slightly primarily due to the $4.7 million voluntary severance program accruals in 2003. The decrease was offset by increases in customer service support costs and maintenance and outage costs at fossil plants. The increase in miscellaneous income is primarily due to an asbestos insurance settlement in April 2004. Interest on long-term debt decreased primarily due to long-term debt refinancing in the third quarter of 2003. 247
Entergy New Orleans, Inc. Management's Financial Discussion and Analysis 2003 Compared to 2002 Other operation and maintenance expenses increased primarily due to the following:
- voluntary severance program accruals of $4.7 million;
- an increase of $2.7 million in benefit costs;
- an increase of $2.2 million in billing, customer inquiry, and collection costs; and
- an increase of $2.0 milliork in' fossil plant maintenance 6utage costs.
Depreciation and amortization expenses increased due to an increase in plant in service., Miscellaneous income decreased primarily due to a gain on the sale of property at a non-operating plant site in 2002. Other interest decreased primarily due to interest accrued in 2002 for potential rate actions and refunds and a true-up of those accruals in May 2003. Income Taxes The effective income tax rates for 2004, 2003, and 2002 were 37.5%, 42.8%, and 64.7%, respectively. See Note 3 to the domestic utility companies and System Energy financialstatements for a reconciliation of the federal statutory rate of 35% to the effective income tax rate. Tax reserves not expected to reverse within the next year are reflected as non-current taxes accrued on the balance sheet. Liquidity and Capital Resources Cash Flow Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows: 2004 2003 2002 (In Thousands), Cash and cash equivalents at beginning of period $4,669 $66,247 $38,184 Cash flow provided by (used in): Operating activities 63,577 7,194 72,143 Investing activities (49,280) (64,806) (41,647) Financing activities (11,012) (3,966) (2,433) Net increase (decrease) in cash and cash equivalents 3,285 (61,578) 28,063 Cash and cash equivalents at end of period $7,954 $4,669- $66,247' Operating Activities Cash flow from operations increased $56.4 million in 2004 primarily due to increased net income and the timing of collections of receivables. Cash flow from operations decreased $64.9 million in 2003 primarily due to decreased fuel cost recoveries and the timing of collection of receivables due to an increase in retail customer receivable days outstanding. 248
Entergy New Orleans, Inc. Managemenfs Financial Discussion and Analysis Entergy New Orleans' receivables from the money pool were as follows as of December 31 for each of the following years: 2004 2003 2002 2001 (In Thousands)
$1,413 $1,783 $3,500 $9,208 Money pool activity provided $0.4 million of Entergy New Orleans' operating cash flow in 2004, provided
$1.7 million in 2003, and provided $5.7 million in 2002. See Note 4 to the domestic utility companies and System Energy financial statements for a description of the money pool. Investing Activities Net cash used in investing activities decreased $15.5 million in 2004 primarily due to capital expenditures related to a turbine inspection project at a fossil plant in 2003 and decreased customer service spending. Net cash used in investing activities increased $23.2 million in 2003 compared to 2002 primarily due to the maturity of $14.9 million of other temporary investments in 2002 and increased construction expenditures due to increased customer service spending. Financing Activities Net cash used in financing activities increased $7.0 million in 2004 primarily due to the costs and expenses related to refinancing $75 million of long-term debt in 2004 and an increase of $2.2 million in common stock dividends paid. Net cash used in financing activities increased $1.5 million in 2003 primarily due to additional common stock dividends paid of $2.2 million. In July 2003, Entergy New Orleans issued $30 million of 3.875% Series First Mortgage Bonds due August 2008 and $70 million of 5.25% Series First Mortgage Bonds due August 2013. The proceeds from these issuances were used to redeem, prior to maturity, $30 million of 7% Series First Mortgage Bonds due July 2008, $40 million of 8% Series bonds due March 2006, and $30 million of 6.65% Series First Mortgage Bonds due March 2004. The issuances and redemptions are not shown on the cash flow statement because the proceeds from the issuances were placed in a trust for use in the redemptions and never held as cash by Entergy New Orleans. See Note 5 to the domestic utility companies and System Energy financial statements for details on long-term debt. Uses of Capital Entergy New Orleans requires capital resources for:
- construction and other capital investments;
- debt and preferred stock maturities;
- working capital purposes, including the financing of fuel and purchased power costs; and
- dividend and interest payments.
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Entergy New Orleans, Inc. Managements Financial Discussion and Analysis Following are the amounts of Entergy New Orleans! planned construction and other capital investments and existing debt obligations: 2005 2006-2007 2008-2009 After 2009 Total (In Millions) Planned construction and capital investment (I) $47 $96 N/A N/A $143 Long-term debt $30 $- $30 $170 $230 Purchase obligations (2) $182 $346 $200 $1,215 $1,943 (1) Consists almost entirely of maintenance capital, which is planned spending on routine Icapital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. (2) Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy New Orleans almost all of the total consists of unconditional fuel'and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which 'is discussed ity Note 8 to' the' domestic utility companies and System Energy financial statements. In addition to these contractual obligations, Entergy New Orleans expects to contribute $ 1'5.7 million to its pension plans and $4.4 million to other postretirement plans in 2005. The planned capital investment estimate for Entergy New Orleans reflects capital required' to support existing business. The estimated capital expenditures are subject to periodic review and modification and may vary based on the'ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 and to the domestic utility companies and System Energy financial statements. As a wholly-owned subsidiary, Entergy' New'Orleans'dividends its earnings to Entergy Corporation at a percentage determined monthly. In addition, all of Entergy New Orleans' retained earnings are currently available for distribution. Sources'of Capital Entergy New Orleans' sources to meet its capital requirements include:
- internally generated funds;
- cash on hand;
- debt or~preferred stock issuances; and
- bank financing under new or existing facilities.
Entergy New Orleans issued $75 million of First Mortgage Bonds in 2004 as follows: Issue Date Description - Maturity Amount (In Thousands) August 2004 5.60% Series September 2024 $35,000 August 2004 5.65% Series September 2029 40,000
$75,000 250
Entergy New Orleans, Inc. Management's Financial Discussion and Analysis Proceeds from the issuances in August 2004 were used to retire or redeem the following First Mortgage Bonds: Retirement Date Description Maturity Amount (In Thousands) September 2004 7.55% Series September 2023 $30,000 September 2004 8.00% Series March 2023 45,000
$75,000 In July 2004, Entergy New Orleans entered into a credit facility and Entergy Louisiana renewed its credit facility with the same lender. Both facilities will expire in April 2005. Entergy New Orleans can borrow up to $14 million and Entergy Louisiana can borrow up to $15 million under their respective credit facilities, but at no time can the total amount borrowed by the two companies combined exceed $15 million. As of December 31, 2004, no borrowings were outstanding under the facilities.
Entergy New Orleans may refinance or redeem debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable. All debt and common and preferred stock issuances by Entergy New Orleans require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy New Orleans has sufficient capacity under these tests to meet its foreseeable capital needs. Short-term borrowings by Entergy New Orleans, including borrowings under the money pool, are limited to an amount authorized by the SEC, $100 million. Under restrictions contained in its articles of incorporation, Entergy New Orleans could incur approximately $40 millioniof new unsecured debt as of December 31, 2004. Under its SEC Order and without further SEC authorization, Entergy New Orleans cannot incur additional short-term indebtedness unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of Entergy New Orleans (other than preferred stock), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utility companies and System Energy financial statements for further discussion of Entergy New Orleans' short-term borrowing limits. Significant Factors and Known Trends State and Local Rate Regulatory Risks The rates that Entergy New Orleans charges for electricity and natural gas significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is closely regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers. In May 2003, the City Council approved a resolution allowing for a total increase of $30.2 million in electric and gas base rates effective June 1, 2003. In April 2004, Entergy New Orleans made filings with the City Council as required by the earnings review process prescribed by the Gas and Electric Formula Rate Plans approved by the City Council in 2003. The filings sought an increase in Entergy New Orleans' electric revenues of
$1.2 million and an increase in Entergy New Orleans' gas revenues of $32,000. The Council Advisors and intervenors reviewed the filings, and filed their recommendations in July 2004. In August 2004, in accordance with the City Council's requirements for the formula rate plans, Entergy New Orleans made a filing with the City Council reflecting the parties' concurrence that no change in Entergy New Orleans' electric or gas rates is warranted. Later in August 2004, the City Council approved an unopposed settlement among Entergy New 'Orleans, the Council Advisors, and the intervenors in connection with the Gas and Electric Formula Rate Plans. In accordance with the resolution approving the settlement agreement, Entergy New Orleans' gas and electric base rates remain unchanged from levels set in May 2003. The resolution ordered Entergy New Orleans to defer $3.9 251
Entergy New Orleans, Inc. Managemenfts Financial Discussion and Analysis million relating to voluntary severance plan costs allocated to its electric operations and $ 1.0 million allocated to its gas operations, which amounts were accrued on its books in 2003, and to record on its books regulatory assets in those amounts to be amortized over five years effective January 2004. Entergy New Orleans also was ordered to defer $6.0 million of fossil plant maintenance expense incurred in 2003 and to record on its books a regulatory asset in that amount to be amortized over a five-year period effective January 2003. Entergy New Orleans will file its formula rate plan for the year ended December 31, 2004 by May 1, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in effect based on the December 31, 2004 test year shall continue. In May 2003, the City Council approved implementation of, a generation. performance-based rate calculation in the electric fuel adjustment clause under which Entergy New Orleans receives 10% of calculated fuel and purchased power cost savings in excess of $20 million, based on a defined benchmark, subject to a 1325% return on equity limitation for electric operations as provided for in the, electric formula rate plan. Entergy New Orleans bears 10% of any "negative" fuel and purchased power cost savings. In October 2004, Entergy New Orleans' annual evaluation report was submitted for the period June 2003 through May 2004. Additional savings associated with the first year generation performance-based rate calculation was $71 million of which Entergy New Orleans' share was $5.1 million. In April 1999, a group of ratepayers filed a complaint against Entergy New Orleans, Entergy Corporation, Entergy Services, and Entergy Power in state court in Orleans Parish purportedly on behalf of all Entergy New Orleans ratepayers. The plaintiffs seek treble damages for alleged injuries arising from the defendants' alleged violations of Louisiana's antitrust laws in connection with certain costs passed on to ratepayers in Entergy New Orleans' fuel adjustment filings with the City Council In particular, plaintiffs allege that. Entergy New Orleans improperly included certain costs in the calculation of fuel charges and that Entergy New' Orleans imprudently purchased high-cost fuel from other Entergy affiliates. Plaintiffs allege that Entergy New Orleans and the other defendant Entergy-companies conspired to make, these purchases to the detriment of Entergy New Orleans' ratepayers and to the benefit of Entergy's shareholders, in violation of Louisiana's antitrust laws. Plaintiffs also seek to recover interest and attorneys' fees. Entergy filed exceptions to the plaintiffs' allegations; asserting, among other things, that jurisdiction over these issues rests with the City Council and FERC. In March 2004, the plaintiffs supplemented and amended their petition. If necessary, at the appropriate time, Entergy will also raise its defenses to.the antitrust claims. The suit in state court has been stayed by stipulation of the parties pending a decision by the City Council in the proceeding discussed in the next paragraph. Plaintiffs also filed this complaint with the City Council in order to initiate a review by the City Council of the plaintiffs' allegations and to force restitution to ratepayers of all costs they allege were improperly 'and imprudently included in the fuel adjustment filings. Testimony was filed on behalf of the plaintiffs in this proceeding asserting, among other things,, that Entergy New Orleans and other defendants have engaged in fuel procurement and power purchasing practices and included costs in Entergy New Orleans' fuel adjustment that could have resulted in New Orleans customers being overcharged by more than $100 million over a period of.years. Hearings were held in February and March 2002. In February 2004, the City Council approved a resolution that resulted in a refund to customers of $11.3 million, including interest, during the months of June through September 2004. The resolution concludes, among other things, that the record does, not support an allegation that Entergy Ne6.Orleans' actions or inactions, either alone 'or in concert with Entergy or' any of its affiliates, constituted a misrepresentation or a suppression of the truth made in order to obtain an unjust advantage of Entergy New Orleans, or to -cause loss, inconvenience, or harm t6 its ratepayers. The plaintiffs have appealed the City Council resolution to the state court in Orleans Parish. Oral argument on the plaintiffs' appeal was conducted in February 2005. In addition to rate proceedings, Entergy New Orleans' fuel costs recovered from customers are subject to regulatory scrutiny. Entergy New Orleans' retail and wholesale rate matters and proceedings, including fuel cost recovery- related issues, are discussed more thoroughly in Note 2 to the domestic utility companies and System Energy financial statements.; 252
Entergy New Orleans, Inc. Management's Financial Discussion and Analysis System Agreement Proceedings The domestic utility companies historically have engaged in the coordinated planning, construction, and operation of generating and transmission facilities under the terms of an agreement called the System Agreement that has been approved by the FERC. Litigation involving the System Agreement is being pursued by the LPSC at both the FERC and before itself. These proceedings include challenges to the allocation of costs as defined by the System Agreement, raise questions of imprudence by the domestic utility companies in their execution of the System Agreement, and seek support for local regulatory authority over System Agreement issues. Regarding the proceeding at the LPSC, Entergy believes that state and local regulators are preempted by federal law from reviewing and deciding System Agreement issues for themselves. An unrelated case between the LPSC and Entergy Louisiana raised the question of whether a state regulator is preempted by federal law from reviewing and interpreting FERC rate schedules that are part of the System Agreement, and from subsequently enforcing that interpretation. The LPSC interpreted a System Agreement rate schedule in the unrelated case, and then sought to enforce its interpretation. The Louisiana Supreme Court affirmed the LPSC's decision. In 2003, the U.S. Supreme Court, ruled in Entergy Louisiana's favor and reversed the decisions of the LPSC and the Louisiana Supreme Court. In February 2004, a FERC ALJ issued an Initial Decision in the LPSC-initiated proceeding at the FERC. The Initial Decision decided some issues in favor of the relief sought by the LPSC, and decided some issues against the relief sought by the LPSC. Several parties, including Entergy, the LPSC, the APSC, the MPSC, the City Council, and the FERC Staff, filed briefs on exceptions in response to the ALUs Initial Decision. Entergy's exceptions to the AL's Initial Decision include: the practical effect of the Initial Decision is full production cost equalization; which was rejected in the Initial Decision and previously has been rejected by the FERC; resource planning for the Entergy System would be impeded if the Initial Decision were adopted; the remedy in the Initial Decision is inconsistent with the history, structure, and precedent regarding the System Agreement; the Initial Decision's remedy ignores the historical pattern of production cost disparities on the Entergy System and would result in substantial, sudden transfers of costs between groups of Entergy customers; the numerical standards proposed in the Initial Decision are arbitrary and are so complex that they will be difficult to implement; the. Initial Decision improperly rejected Entergy's resource planning remedy; the Initial Decision erroneously determined that the full costs of the Vidalia project should be included in Entergy Louisiana's production costs for purposes of calculating relative production costs; and the Initial Decision erroneously adopted a new method of calculating reserve sharing costs rather than the current method. If the FERC grants the relief requested by the LPSC in the proceeding, the relief may result in a material increase in the total production costs the FERC allocates to companies whose costs currently are projected to be less than the Entergy System average, and a material decrease in the total production costs the FERC allocates to companies whose costs currently are projected to exceed that average. If the FERC adopts the AL's Initial Decision, the amount of production costs that would be reallocated among the domestic utility companies would be determined through consideration of each domestic utility company's relative total production cost expressed as a percentage of Entergy System average total production cost. The AL's Initial Decision would reallocate production costs of the domestic utility companies whose percent of Entergy System average production cost are outside an upper or lower bandwidth. This would be accomplished by, payments from domestic utility companies whose production costs are below Entergy System average production cost to domestic utility companies whose production costs are above Entergy System average production cost. : An assessment of the potential effects of the AL's Initial Decision requires assumptions regarding the future total production cost of each domestic utility company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana and Entergy Gulf States are more dependent upon gas-fired generation than Entergy Arkansas, Entergy Mississippi, or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas' total production costs are below the average production costs of the domestic utility companies. Considerable uncertainty exists regarding future gas prices. Annual average Henry Hub gas prices have varied significantly over recent years, ranging from $1.72/mmBtu to $5.85/mmBtu for the 1995-2004 period, and averaging $3.43/mmBtu during the ten-year period 1995-2004 and $4.58/mmBtu during the five-year period 2000-2004. Recent market conditions have resulted in gas prices that have averaged $5.85/mmBtu for the twelve months ended December 253
Entergy New Orleans, Inc. Management's Financial Discussion and Analysis 2004. Based upon analyses considering the effect on future production costs if the FERC adopts. the AL's Initial Decision, the following potential annual production cost reallocations among the domestic utility companies could result assuming annual average gas prices range from $6.39/mmBtu in 2005 declining to $4.97/mmBtu by 2009: Average Annual Range of Annual Payments Payments or (Receipts) or (Receipts) for 2005-2009 Period (In Millions), (In Millions) Entergy Arkansas $154 to $281 $215 Entergy Gulf States ($130) to ($15) ($63) Entergy Louisiana ($199) to ($98) ($141) Entergy Mississippi ($16) to $8 $1 Entergy New Orleans ($17) to ($5) ($12) Management believes that any changes in the allocation of production costs resulting from a FERC decision and related retail proceedings should result in similar rate changes for retail customers. Although the outcome and timing of the FERC, APSC, and other proceedings cannot be predicted at this time, Entergy New Orleans does not believe that the ultimate resolution of these proceedings will have a material effect on its financial condition or results of operation. In February 2004, the APSC issued an "Order of Investigation," in which it discusses the negative effect that implementation of the FERC AL's Initial Decision would have on Entergy Arkansas' customers. The APSC order establishes an investigation into whether Entergy Arkansas' continued participation in the System Agreement is in the best interest of its customers, and whether there are steps that Entergy Arkansas or the APSC can take "to protect [Entergy Arkansas' customers] from future attempts by Louisiana, or any other Entergy retail regulator, to shift its' high costs to Arkansas." Entergy Arkansas filed testimony in response to the APSC's Order of Investigation. The testimony emphasizes that the AL's Initial Decision is not a final order by the FERC; briefly discusses some of the aspects of the Initial Decision that are included in Entergy's exceptions filed with the FERC; emphasizes that Entergy will seek to reverse the production cost-related portions of the Initial Decision; and states that Entergy Arkansas believes that it is premature, before the FERC makes a decision, for Entergy Arkansas to determine whether its continued participation in the System Agreement is appropriate. In April 2004, the APSC commenced the investigation into Entergy Louisiana's Vidalia purchased power contract and requested historical documents, records, and information from Entergy Arkansas, which Entergy Arkansas has provided to the APSC. Also in April 2004, the APSC issued an order directing Entergy Arkansas to show cause why Entergy Arkansas should not have to indemnify and hold its customers harmless from any adverse financial effects related to Entergy Louisiana's pending acquisition of the Perryville power plant, of show that the Perryville unit will produce economic benefits for Entergy Arkansas' customers. Entergy Arkansas filed a response in May 2004 stating that Entergy will seek to reverse the production cost-related portions of the AL's Initial Decision in the System Agreement proceeding at the FERC, that the Perryville acquisition is part of Entergy's request for proposal generation planning process, that Entergy Arkansas is not in a position to indemnify its retail customers from actions taken by the FERC, and that the Perryville acquisition is expected to reduce the domestic utility companies' overall production costs. Procedural schedules have not been established in these APSC investigations. In April 2004, the City Council issued a resolution directing Entergy New Orleans and Entergy Louisiana to notify the City Council and obtain prior approval for any action that would materially modify, amend, or terminate the System Agreement for one or more of the domestic utility companies. Entergy New Orleans and Entergy Louisiana appealed to state court the City Council's resolution on the basis that the imposition of this requirement with respect to the System Agreement, a FERC-approved tariff, exceeds the City Council's jurisdiction and authority. In July 2004, the City Council answered the appeal and filed a third party demand and counterclaim against Entergy, the domestic utility companies, Entergy Services, and System Energy; seeking a declaratory judgment that Entergy and its subsidiaries cannot terminate the System Agreement until obligations owed under a March 2003 rate case settlement are satisfied. In August 2004, Entergy New Orleans and Entergy Louisiana, as 254
Entergy New Orleans, Inc. Management's Financial Discussion and Analysis well' as the named third party defendants, filed pleadings objecting to the City Council's third party demand and counterclaim on various grounds, including federal preemption.; In February 2005, the state court issued an oral decision dismissing the City Council's claims for lack of subject matter jurisdiction and prematurity. Transmission In 2000, FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations) by December 15, 2001. Delays in implementing the FERC order have occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators continue to work to resolve various issues related to the establishment of such RTOs. In April 2004, Entergy filed a proposal with the FERC to commit voluntarily to retain an independent entity (Independent Coordinator of Transmission or ICT) to oversee the granting of transmission or interconnection service on- Entergy's transmission system, to implement a transmission pricing structure that ensures that Entergy's retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs, and to have the ICT serve as the security coordinator for the Entergy region. Assuming applicable regulatory support and approvals can be obtained, Entergy proposed to contract with the ICT to oversee the granting of transmission service on the Entergy system as well as the implementation of the proposed weekly procurement process (WPP). The proposal was structured to not transfer control of Entergy's transmission system to the ICT, but rather to vest with the ICT broad oversight authority over transmission planning and operations. Entergy also proposed to have the ICT administer a transmission expansion pricing protocol that will increase the efficiency of transmission pricing on the Entergy system and that will be' designed to protect Entergy's native load customers from bearing the cost of transmission upgrades not required to reliably serve these customers' needs. Entergy intends for the ICT to determine whether transmission upgrades associated with new requests for service should be funded directly by the party requesting such service or by a broader group of transmission customers, including Entergy's native load customers. This determination would be made in accordance with protocols approved by the FERC, and any party contesting such determination, including Entergy, would be required to seek review at the FERC. Several technical conferences regarding the ICT proposal, or various components thereof, were held in 2004. Entergy has also responded to discovery requests that resulted from these conferences. In January 2005, Entergy filed a petition for declaratory order with the FERC requesting that the FERC provide guidance on two important issues: (1) whether the functions performed by the ICT will cause it to become a "public utility" under the Federal Power Act or the "transmission provider" under Entergy's open access transmission tariff; and (2) whether Entergy's transmission pricing proposal, as administered by the ICT, satisfies the FERC's transmission pricing policy. The petition also indicates that, subject to the outcome of the petition and obtaining support of Entergy's retail regulators, Entergy would be willing to have the ICT perform the following additional functions: (a) grant or deny requests for transmission service; (b) calculate available flowgate capacity; (c) administer Entergy's OASIS; and (d) perform an enhanced planning function (integrating the plans of Entergy and other potential transmission owners to identify regional synergies.) Comments and interventions on the petition were filed by market participants and retail regulators on February' 4, 2005. In their individual comments, the APSC, LPSC, and City Council supported Entergy's position that the ICT would not become 'a "public utility" or "transmission provider" and that the transmission pricing proposal satisfies the FERC's transmission pricing policy. Certain other parties urged the FERC to reject the petition for declaratory order or, in the alternative, that the FERC assert jurisdiction over the ICT and determine that Entergy's proposed pricing policy is inconsistent with FERC's current pricing policy. FERC action on the petition is expected during the first half of 2005. In March 2004, the APSC initiated a proceeding to review Entergy's proposal and compare the benefits of such a proposal to the alternative of Entergy joining the Southwest Power Pool RTO. The APSC sought comments from all interested parties on this issue. Various parties, including the APSC General Staff, filed comments opposing the ICT proposal. A public hearing'has n6t been scheduled by the APSC at this time, although Entergy Arkansas has responded to various APSC data requests. In May 2004, Entergy Mississippi filed a petition for review with the MPSC requesting MPSC support for the ICT proposal. A hearing in that proceeding was held in August 2004. Additionally, Entergy Louisiana and Entergy Gulf States have filed an application with the LPSC requesting that the LPSC find that the ICT proposal is a prudent and appropriate course of action. A hearing on the 255
Entergy New Orleans, Inc. Managemenes Financial Discussion and Analysis transmission pricing aspects of the ICT proposal is Scheduled for May 2005, with a separate hearing on the WPP portion of the proposal currently scheduled for August 2005. Available Flowgate Capacity Proceeding On December 17, 2004, the FERC issued an order initiating a hearing and investigation concerning the justness and reasonableness of the Available Flowgate Capacity (AFC) methodology, the methodology, used to evaluate short-term transmission service requests under the domestic utility companies' open access transmission tariff,, and establishing a refund effective date. -In its order, the FERC indicated that although it "appreciates that Entergy is attempting to explore ways to improve transmission access on its system," it believed that an investigation was warranted to gather more evidence in light of the concerns raised by certain transmission customers and certain issues raised in a FERC audit report finding errors and problems with the predecessor methodology used by Entergy for evaluating short-term transmission requests, the Generator Operating Limits methodology. The FERC order indicates that the investigation will include an examination of (i) Entergy's implementation of the AFC program, (ii) whether Entergy's implementation has complied with prior FERC orders and open access transmission tariff provisions addressing the AFC program, and (iii) whether Entergy's provision of access to short-term transmission on its transmission system was just, reasonable, and not unduly discriminatory. Entergy has submitted an Emergency Interim Request for Rehearing requesting the FERC to defer the hearing process and instead proceed initially with an independent audit of the AFC program and the expansion of the current process involving other market participants to address a broader range of issues. Entergy believes that this type of approach is a more efficient and effective mechanism for evaluating the AFC program. Following the completion of the independent audit and process involving other market participants, the FERC could determine whether other procedural steps are necessary. The FERC has not yet ruled on the Emergency Interim Request for Rehearing submitted by Entergy. Entergy believes that it has complied with the provisions of its open access transmission tariff, including the provisions addressing the implementation of the AFC methodology; however, the ultimate scope of this proceeding cannot be predicted at this time. A hearing in the AFC proceeding is currently scheduled to commence in August 2005. Market and Credit Risks Entergy New Orleans has certain market and credit risks inherent in its business. Market risks represent the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. Credit risk is risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Environmental Risks Entergy New Orleans' facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous solid wastes, and other environmental matters. Management believes that Entergy New Orleans is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental, regulations are subject to change, future compliance costs cannot be precisely estimated. Litigation Risks Te territory in which Entergy New Orleans operates has proven to be an unusually litigious environment. Judges and juries in-New Orleans have demonstrated a, willingness to grant large verdicts, including punitive damages,. to plaintiffs in personal injury, property damager and business tort cases. Entergy New Orleans uses legal and appropriate means to contest litigation threatened or filed against it, but the litigation environment poses a significant business risk. - . l 256
Entergy New Orleans, Inc. Managementfs Financial Discussion and Analysis Critical Accounting Estimates The preparation of Entergy New Orleans' financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements could produce estimates that would have a material impact on the presentation of Entergy New Orleans' financial position or results of operations. Unbilled Revenue As discussed in Note I to the domestic utility companies and System Energy financial statements, Entergy New Orleans records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the.unbilled period and the billed price to customers in that month, including fuel price. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period and fuel price fluctuations, in addition to changes in certain components of the calculation including changes to estimates such as line loss, which affects the estimate of unbilled customer usage, and assumptions regarding price such as the fuel cost recovery mechanism. Pension and Other Postretirement Benefits Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 10 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate. Assumptions Key actuarial assumptions utilized in determining these costs include:
- Discount rates used in determining the future benefit obligations;
- Projected health care cost trend rates;
- Expected long-term rate of return on plan assets; and
- Rate of increase in future compensation levels.
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and worse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions. In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 6.75% in 2002 to 6.25% in 2003 and to 6% in 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy increased its health care cost trend rate assumption used in calculating the December 31, 2004 accumulated postretirement benefit obligation to a 10% 257
Entergy New Orleans, Inc. Managements Financial Discussion and Analysis increase in health care costs in 2005 gradually decreasing each successive year, until it reaches a 4.5% annual increase in health care costs in 2011 and beyond. In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities, 31% fixed income securities, and 4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities and 49% fixed income securities. Based on recent market trends, Entergy reduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 8.75% for 2002 and 2003 to 8.5% in 2004. The assumed rate of increase in future compensation levels used to calculate benefit obligations was 3.25% in 2002, 2003, and 2004. Cost Sensitivity The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (dollars in thousands): Change in Impact on 2004 Impact on Projected Actuarial Assumption Assumption Pension Cost Benefit Obligation Increase/(Decrease) Discount rate (0.25%) $227 $2,694 Rate of return on plan assets (0.25%) $73 Rate of increase in compensation 0.25% $113 $718 The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (dollars in thousands):
-Impact on Accumulated Change in Impact on 2004 Postretirement Benefit Actuarial Assumption' Assumption Postretirement Benefit Cost Obligation Increase/(Decrease)
Health care cost trend 0.25% $157 $973 Discount rate (0.25%) $50 $1,279 Each fluctuation above assumes that the other components of the calculation are held constant. Accounting Mechanisms In accordance with SFAS No. 87, "Employers' Accounting for Pensions," Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into cost only when the accumulated, differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. Additionally, Entergy accounts for the, impact of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted as previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87. 258
Entergy New Orleans, Inc. Management's Financial Discussion and Analysis Costs and Funding Total pension cost for Entergy New Orleans in 2004 was $4.6 million. Entergy New Orleans anticipates 2005 pension cost to decrease to $4.2 million. Entergy New Orleans contributed $2.1 million to its pension plan in 2004, and anticipates making $15.7 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, partially offset by the Pension Funding Equity Act relief passed in April 2004. Entergy New'Orleans' accumulated benefit obligation 'at December 31, 2004, 2003 and 2002 exceeded plan assets. As a result, Entergy New Orleans was'required to recognize an additional minimum liability as prescribed by SFAS 87. At December 31, 2004 Entergy New Orleans increased its additional minimum liability to $16.9 million from $13.1 million at December 31, 2003. Entergy New Orleans decreased its intangible asset for the unrecognized prior service cost to $1.7 million at December 31, 2004 from $2.8 million at December 31, 2003. Entergy New Orleans increased the regulatory asset to $15.2 million at December 31, 2004 from $10.3 million at December 31, 2003. Net income for 2004, 2003, and 2002 were not impacted. Total post retirement health care and life insurance benefit costs for Entergy New Orleans in 2004 were $4.3 million, including $1.3 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy New Orleans expects 2005 postretirement health care and life insurance benefit costs to approximate $4.2 million, including $1.4 million in savings due to the estimated effect of future Medicare Part D subsidies. 259
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIR1S To the Board of Directors and Shareholders Entergy New Orleans, Inc.: We have audited the accompanying balance sheets of Entergy New Orleans, Inc. as of December 31, 2004 and 2003, and the related statements of operations, retained earnings, and cash flows (pages 261 through 266 and applicable items in pages 284 through 348) for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the, audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy New Orleans, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting. DELOITTE & TOUCHE LLP New Orleans, Louisiana March 8, 2005 260
ENTERGY NEW ORLEANS, INC STATEMENTS OF OPERATIONS For the Years Ended December 31, 2004 2003 2002 (In Thousands) OPERATING REVENUES Domestic electric $588,457 $527,660 $424,527 Natural gas 147,411 126,356 83,347 TOTAL 735,868 654,016 507,874 OPERATING EXPENSES Operation and Maintenance: Fuel, fuel-related expenses, and gas purchased for resale 245,301 214,735 163,323 Purchased power 256,190 231,787 158,191 Other operation and maintenance 107,874 108,217 98,511 Taxes other than income taxes 43,577 42,198 40,099 Depreciation and amortization 29,657 30,004 27,699 Other regulatory charges (credits) - net (4,670) (8436 2,701 TOTAL 677,929 626,098 490,524 OPERATING INCOME 57,939 27,918 17,350 OTHER INCOME Allowance for equity funds used during construction 1,378 2,085 1,835 Interest and dividend income 720 825 689 Miscellaneous - net 270 1,453) 584 TOTAL 2,368 1,457 3,108 INTEREST AND OTHER CHARGES Interest on long-term debt 15,357 17,436 18,011 Other interest - net , 1,253 350 4,939 Allowance for borrowed funds used during construction (1,243) (2,145) (1,840) TOTAL 15,367 15,641 21,110 INCOME (LOSS) BEFORE INCOME TAXES 44,940 13,734 (652) Income taxes 16,868 5,875 (422) NET INCOME (LOSS) 28,072 7,859 (230) Preferred dividend requirements and other 965 965 965 EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $27,107 $6,894 ($1,195) See Notes to Respective Financial Statements.
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ENTERGY NEW ORLEANS, INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2004 2003 2002 (In Thousands) OPERATING ACTIVITIES
$28,072 $7,859 ($230)
Net Income (loss) Adjustments to reconcile net income to net cash flow provided by operating activities: Other regulatory charges (credits) - net (4,670) (843) 2,701 Depreciation arid amortization 29,657 30,004 27,699 Deferred income taxes and investment tax credits 39,782 15,401 6,729 Changes in working capital: Receivables 9,162 (41,308) 10,540 1,399 * (2,296) (203) Fuel inventory (3,014) 17,81-7 18,070 Accounts payable Taxes accrued (13,056) 1,372 5,603 (1,455) (276). (544) Interest accrued Deferred fuel costs (5,279) -(12,162) 4,686 Other working capital accounts 2,121 (7,553) (4,971) Provision for estimated losses and reserves (1,305) . (1,634) (3,348) Changes in other regulatory assets (5,380) (9,473) (3,061) (126457) 10,286 8,472 Other Net cash flow provided by operating activities 63,577 7,194 72,143 INVESTING ACTIVITIES Construction expenditures (51,264) (66,285) (58,341) Allowance for equity funds used during construction 1,378 2,085 1,835 Changes in other temporary investments - net 606 (606) 14,859 Net cash flow used In investing activities (49,280) (64,806) (41,647) t FINANCING ACTIVITIES Proceeds from the issuance of long-term debt 72,640 24,332 Retirement of long-term debt (77,487) (25,000) Dividends paid: Common stock (5,200) (3,001) (800) (965) (965) (965) Preferred stock Net cash flow used In financing activities (11,012) (3,966) ! (2,433) Net Increase (decrease) In cash and cash equivalents 3,285 (61,578) 28,063 Cash and cash equivalents at beginning of period 4,669 66,247 38,184 Cash and cash equivalents at end of period $7,954 S4,669 $66,247 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paidl(received) during the period for: Interest - net of amount capitalized $16,172 $17,427 $19,961 Income taxes ($5,736) ($13,530) ($37,929) See Notes to Respective Financial Statements.
ENTERGY NEW ORLEANS, INC. BALANCE SHEETS ASSETS December 31, 2004 2003 (In Thousands) CURRENT ASSETS Cash and cash equivalents: Cash $2,998 $28. Temporary cash investments - at cost, which approximates market 4,956 4,641 Total cash and cash equivalents 7,954 4,669. Other temporary investments 606 Accounts receivable: Customer I 47,356 44,663 Allowance for doubtful accounts (3,492) (3,104) Associated companies 12,223 24,697 Other I 7,329 10,057' Accrued unbilled revenues 24,848 21,113 Total accounts receivable 88,264 97,426_ .1 I Deferred fuel 2,559 Accumulated deferred income taxes - 460 Fuel inventory - at average cost .4,181 5,580 Materials and supplies - at average cost -- - 9,150 - 8,660 - - Prepayments and other 3,467 8,050 TOTAL, 115,575 125,451
.3 .
OTHER PROPERTY AND INVESTMENTS Investment in affiliates - at equity - 3,259 I- 3,259 UTILITY PLANT Electric 699,072 666,122 Natural gas 183,728 167,011 Construction work in progress 33,273 45,061 TOTAL UTILITY PLANT 916,073 878,194 Less - accumulated depreciation and amortization 435,519 420,745 UTILITY PLANT - NET 480,554 457,449 -. - - DEFERRED DEBITS AND OTHER ASSETS Regulatory assets:
- Other regulatory assets 40,354 27,222 Long term receivables I . 2,492, Other 20,540 16,246 TOTAL 63,386 43,468-TOTAL ASSETS $662,774 $629,627 See Notes to Respective Financial Statements.
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ENTERGY NEW ORLEANS, INC.
- BALANCE SHEETS -
LIABILITIES AND SHAREHOLDERS' EQUITY December 31, 2004 2003 (In Thousands) CURRENT LIABILITIES Currently maturing long-term debt $30,000 Accounts payable: Associated companies 30,563 35,008 Other 44,149 42,718 Customer deposits 17,187 15,575 Taxes accrued 2,592 Accumulated deferred income taxes 1,906 Interest accrued 4,757 6,212 Deferred fuel costs 2,720 Energy Efficiency Program provision 6,611 6,356 Other 3,477 2,088 TOTAL 141,242 110,677 NON-CURRENT LIABILITIES Accumulated deferred income taxes and taxes accrued 47,062 39,486 Accumulated deferred investment tax credits 3,997 4,441 SFAS 109 regulatory liability - net 46,406 40,543 Other regulatory liabilities 954 Accumulated provisions 9,323 10,628 Pension liability 36,845 30,585 Long-term debt 199,902 229,217 Other 3,755 10,761 TOTAL 347,290 366,615 Commitments and Contingencies SHAREHOLDERS' EQUITY Preferred stock without sinking fund 19,780 19,780 Common stock, $4 par value, authorized 10,000,000 shares; issued and outstanding 8,435,900 shares in 2004 and 2003 33,744 33,744 Paid-in capital 36,294 36,294 Retained earnings 84,424 62,517 TOTAL 174,242 152,335 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $662,774 $629,627 See Notes to Respective Financial Statements.
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ENTERGY NEW ORLEANS, INC.' STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 2004 2003 2002 (In Thousands) Retained Earnings, January 1 $62,517 $58,624 $60,619 Add: Net income (loss) 28,072 7,859 (230) Deduct: Dividends declared: Preferred stock 965 965 965 Common stock 5,200 I 3,001 800 Total 6,165 3,966 1,765 Retained Earnings, December 31 $84,424 $62,517 $58,624 See Notes to Respective Financial Statements. 266
ENTERGY NEW ORLEANS, INC. SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 2004 2003 2002 2001 2000 (In Thousands) Operating revenues $735,868 $654,016 $507,874 $630,850 $640,290 Net Income (loss) $28,072 $7,859 ($230) ($2,195) $16,518 Total assets $662,774 $629,627 $584,705 $566,037 $559,231 Long-term obligations (1) $199,902 $229,217 $229,191 $299,097 $199,031 (1) Includes long-term debt (excluding currently maturing debt). 2004 2003 2002 2001 . 2000 (Dollars In Millions) Electric Operating Revenues: Residential $184 $178 $170 $190 $188 Commercial 171 162 154 186 171 Industrial 34 27 25 32 25 Governmental 70 68 66 81 73 Total retail 459 435 415 489 457 Sales for resale: Associated companies 118 85 7 10 32 Non-associated companies 2 2 2 3 9 Other 9 6 1 1 17 Total $588 $528 $425 $503 $515 Billed Electric Energy Sales, (GWh): Residential 2,139 2,133 2,158 1,981 2,178 Commercial 2,316 2,262 2,255 2,185 2,260 Industrial 575 413 409 414 384 Governmental 1,025 1,036 1,053 1,017 1,058 Total retail 6,055. 5,844 5,875 5,597 5,880 Sales for resale: Associated companies 1,514 1,312 144 115 570 Non-associated companies 25 28 32 59 141 Total 7,594 7,184 6,051 5,771 6,591
=
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SYSTEM ENERGY RESOURCES, INC, MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS System Energy's principal asset consists of a 90% ownership and leasehold interest in Grand Gulf. The capacity and energy from its 90% interest is sold under the Unit Power Sales Agreement to its only four customers, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy's operating revenues are derived from the allocation of the capacity, energy, and related costs associated wiih its 90% interest in Grand Gulf I pursuant to the Unit Power Sales-Agreement. Payments under the Unit Power Sales Agreement are System Energy's only source of operating revenues. Results of Operations Net Income 2004 Compared to 2003: Net income remained relatively unchanged, decreasing $0.06 million in 2004. 2003 Compared to 2002 Net income increased $2.7 million in 2003 primarily due to lower interest charges primarily resulting from lower interest expense associated with the, Grand Gulf sale-leaseback. This increase was partially offset by a decrease in rate base in 2003 resulting in lower operating income. The decrease in rate base was due to the normal depreciation of Grand Gulf. 1' Income Taxes The effective income tax rates for 2004, 2003, and 2002, were 42.4%, 41.7%, and 42.4%, respectively. See Nbte 3 to the domestic utility companies and System Energy financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate. Tax reserves not expected:to reverse within the~ ext year are reflected as non-current taxes accrued on the balance sheet. Liquidity and Capital Resources Cash Flow Cash flows for the years ended December 31, 2004, 2003, and 2002 were as follows: 2004 2003 2002 (In Thousands) Cash and cash equivalents at beginning of period - $52,536 $113,159 $49,579 Cash flow provided by (used in): Operating activities 332,928 100,817 225,639 Investing activities (45,053) (45,065) (28,873) Financing activities (124,056) (116,375) (133,186) Net increase (decrease) in cash and cash equivalents 163,819 (60,623) 63,580 Cash and cash equivalents at end of period $216,355 $52,536 $113,159 268
System Energy Resources, Inc. Management's Financial Discussion and Analysis Operating Activities Cash flow from operations increased by $232'I million in 2004 primarily due to income tax refunds of $70.6 million in 2004 compared to income tax payments of $230.9 million in 2003. The increase was partially offset by money pool activity, as discussed below. In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity, which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $430 million deduction for System Energy on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003. In 2004 System Energy realized $144 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will, likely be challenged by the IRS on audit. Cash flow from operations decreased by $124.8 million in 2003 primarily due to the following:
- an increase in federal income taxes paid of $74.0 million in 2003 compared to 2002;
- the cessation of the Entergy Mississippi GGART. System Energy collected $21.7 million in 2003 and
$40.8 million in 2002 from Entergy Mississippi in conjunction with the GGART, which provided for the acceleration of Entergy Mississippi's Grand Gulf purchased power obligation. The MPSC authorized cessation of the GGART effective July 1, 2003. See' Note 2 to the domestic utility companies and System Energy financial statements for further discussion of the GGART; and
- money pool activity, as discussed below.
System Energy's receivables from the money pool were as follows as of December 31 for each of the following years: 2004 2003 2002 2001 (In Thousands)
$61,592 $19,064 $7,046 $13,853 Money pool activity used $42.5 million of System Energy's operating cash flows in 2004, used $12.0 million in 2003, and provided $6.8 million in 2002. See Note 4 to the domestic utility companies' and System Energy financial statements for a description of the money pool. '
Investing Activities Net cash used for investing activities was practically unchanged in 2004 compared to 2003 primarily because an increase in construction expenditures caused by a reclassification of inventory items to capital was significantly offset by the maturity of $6.5 million of other temporary investments that had been made in 2003, which provided cash in 2004. The increase of $16.2 million in net cash used in investing activities in 2003 was primarily due to the following:
- the maturity in 2002 of $22.4 million of other temporary investments that had been made in 2001, which provided cash in 2002;
- an increase in decommissioning trust contributions and realized change in trust assets of $8.2 million in 2003 compared to 2002; and
- other temporary investments of $6.5 million made in 2003.
Partially offsetting the increases in net cash used in investing activities was a decrease in construction expenditures of $22.1 million in 2003 compared to 2002 primarily due to the power uprate project in 2002. 269
System Energy Resources, Inc. Management's Financial Discussion and Analysis Financing Activities The increase of $7.7, million in net cash used in financing activities in 2004 was. primarily 'due to $5.5 million in costs related to Systemr Energy refunding bonds associated with its Grand Gulf Lease Obligation in May 2004 and the retirement of $ 7.6 million of long-term debt 2004. The increase was partially offset, by a decrease of $5.0 million in the January 2004 principal payment made on the Grand Gulf sale-leaseback compared to the January 2003 principal payment. - - i i . . !': i'E-1E}Mi 1r The decrease of $16.8 million in net cash used in financing activities in 2003 was primarily due to a decrease of $19.5 million in the January 2003 principal payment made qn the Grand Gulf sale-leaseback compared to the January 2002 principal payment. , , ' ; See Note 5 to the domestic utility companies and System Energy financial statements for details of long. term debt. Uses of Capital . System Energy requires capital resources for:,
- construction and other capital investments; -;
- debt maturities; ,
working capital purposes, including the financing of fuel costs; and'
- dividend and interest payments.
Following are the amounts of System Energy's planned construction and other capital investments, existing debt and lease obligations, and other purchase obligations: ' v 2005 2006-2007 2008-2009 After 2009 Total!! (In Millions) Planned construction and -; capital investment $38 $81 N/A N/A $119 Long-term debt $29 $125 $62 $659 $875 Nuclear fuel lease obligations (1) $28 $38 N/A N/A $66 (1) It is expected that additional financing .under the leases will, be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations. System Energy expects to contribute $9.3 million to pension plans and $1.7 million to other postretirement plans in 2005. The planned capital investment estimate for System Energy reflects capital required to support the existing business of System Energy. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the domestic utility companies and System Energy financial statements. As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly. Currently, all of System Energy's retained earnings are available for distribution. Sources of Capital System Energy's sources to meet its capital requirements include:
- internally generated funds;
- cash on hand; debt issuances;, and - -' - -
- bank financing under new or existing facilities. ' -
270
System Energy Resources, Inc. Management's Financial Discussion and Analysis System Energy had three-year letters of credit in place that were scheduled to expire in March 2003 securing certain of its obligations related to the sale-leaseback of a portion of Grand Gulf. System Energy replaced the letters of credit before their expiration with new three-year letters of credit totaling approximately $198 million that were backed by cash collateral. In December 2003, System Energy replaced the cash-backed letters of credit with syndicated bank letters of credit. In December 2004 System Energy amended these letters of credit and they now expire in May 2009. System Energy may refinance or redeem debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable. - All debt and common stock issuances by System Energy require prior regulatory approvl. Debt issuances are also subject to issuance tests set forth in bond indentures and other agreements. System Energy has sufficient capacity under these tests to meet its foreseeable capital needs. Borrowings and securities issuances by System Energy are'limited to amounts authorized by the SEC. The current short-term borrowing limitation, including borrowings under the money pool, is $140 million. Under its SEC Orders and without further SEC authorization, System Energy cannot incur additional short-term indebtedness unless (a) it and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of System Energy, as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. See Note 4 to the domestic utilitycompanies and System Energy financial statements for further discussion of System Energy's short-term borrowing limits. Significant Factors and Known Trends Market Risks Interest Rate and Equity Price Risk - Decommissioning Trust Funds System Energy's nuclear decommissioning trust funds expose it to fluctuations in equity prices and interest rates. The NRC requires System Energy to maintain trusts to fund the costs of decommissioning Grand Gulf. The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. Management believes that its exposure to market fluctuations will not affect results of operations for the Grand Gulf trust funds because of the application of regulatory accounting principles. The decommissioning trust funds are discussed more thoroughly in Notes 1, 8, and 12 to the domestic utility companies and System Energy financial statements. Nuclear Matters System Energy owns and operates, through an affiliate, Grand Gulf. System Energy is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, limitations on the amounts and types of insurance commercially available for losses in connection - with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, 'including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of Grand Gulf, System Energy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ' Litigation Risks The states in which System Energy's customers operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to'grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. System Energy uses legal and appropriate means' to contest litigation threatened or filed against it, but the litigation environment poses a significant business risk. 271
System Energy Resources, Inc. Management's Financial Discussion and Analysis Environmental Risks Systemn Energy's facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes' that System Energy is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated. Critical Accounting Estimates The preparation of System Energy's' financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is, the potential for future changes in the assumptions and' measurements could produce-estimates that would have a material impact on the presentation of System Energy's financial position or results of operations. Nuclear Decommissioning Costs i Regulations require that Grand Gulf be decommissioned after the facility is taken out of service, and funds are collected and deposited in trust funds during the facility's operating life in order to provide for this obligation. System Energy conducts periodic decommissioning cost studies (typically updated every three to five years) to estimate the costs that will be incurred to decommission the facility. See Note 8 to the dothestic utility companies and System Energy financial statements for details regarding System Energy's most recent study and the obligations recorded by System Energy related to decommissioning. The following key assumptions have a significant effect on these estimates:
- Cost Escalation Factors - System Energy's decommissioning studies include an assumption that decommissioning costs will escalate over present cost levels by an annual factor averaging approximately 5.5%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11%.
- Timing - The date of the plant's retirement must be estimated and an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore" status for later decommissioning, as permitted by applicable regulations. System Energy's decommissioning studies for Grand Gulf assume immediate decommissioning upon expiration of the original plant license. While the impact of these assumptions cannot be determined with precision, assuming either license extension or use of a "safestore" status can possibly decrease the present value of these obligations. -
Spent Fuel Disposal - Federal regulations require the DOE to provide a permanent repository for the storage of spent nuclear fuel, and legislation has been passed by Congress to develop this repository at Yucca Mountain, Nevada. However, until this site is available, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facifities can have a significant impact (as much as 16% of estimated decommissioning costs). System Energy's decommissioning studies include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
- Technology and Regulation - To date, there is limited practical experience in the United States with actual' decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant impact on cost estimates. The impact of these potential changes is not presently determinable. System Energy's decommissioning cost studies assume current technuologies and regulations.
272
System Energy Resources, Inc. Managements Financial Discussion and Analysis System Energy collects the costs of decommissioning Grand Gulf through rates charged to its customers. The amounts collected through rates, which are based upon decommissioning cost studies, are deposited in decommissioning trust funds. These collections plus earnings on the trust fund investments are estimated to be sufficient to fund the future decommissioning costs. The obligation recorded by System Energy for decommissioning costs is reported in the line item entitled "Decommissioning." Prior to the implementation of SFAS 143, the amount recorded for this obligation was comprised of collections from customers and earnings on the trust funds. SFAS 143 System Energy implemented SFAS 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003. Nuclear decommissioning costs are System Energy's only asset retirement obligations, and the measurement and recording of System Energy's decommissioning obligations outlined above changed significantly with the implementation of SFAS 143. The most significant differences in the measurement of these obligations are outlined below: -
- Recording of full obligation - SFAS 143 requires that the fair value of an asset retirement obligation be recorded when it is incurred. This caused the recorded decommissioning obligation of System Energy to increase significantly, as System Energy had previously only recorded this obligation as the related costs were collected from customers, and as earnings were recorded on the related trust funds.
- Fair value approach - SFAS 143 requires that these obligations be measured using a fair value approach.
Among other things, this entails the assumptionthat the costs will be incurred by a third party and will; therefore include appropriate profit margins and risk premiums. System Energy's decommissioning studies to date have been based on System Energy performing the work, and have not included any such margins or premiums. Inclusion of these items increases cost estimates.
- Discount rate - SFAS 143 requires that these obligations be discounted using a credit-adjusted risk-free rate.
The net effect of implementing this standard for System Energy was recorded as a regulatory asset, with no resulting impact on System Energy's net income. System Energy recorded this regulatory asset because its existing rate mechanism is based on a cost standard that allows System Energy to recover all ultimate costs of decommissioning from its customers. Upon implementation, assets and liabilities increased by $138 million in 2003 as a result of recording the asset retirement obligation at its fair value of $292 million as determined under SFAS 143, reversing the previously recorded decommissioning liability of $154 million, increasing utility plant by $82 million, increasing accumulated depreciation by $36 million, and recording the related regulatory asset of $92 million. Pension and Other Postretirement Benefits Entergy sponsors defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 10 to the domestic utility companies and System Energy financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate. Assumptions Key actuarial assumptions utilized in determining these costs include:
- Discount rates used in determining the future benefit obligations;
- Projected health care cost trend rates; 273
System Energy Resources, Inc. Management's Financial Discussion and Analysis
- Expected long-term rate of return on plan assets; and
- Rate of increase in future compensation levels.
Entergy reviews these assumptions on an annual basis and adjusts them as necessary. The falling interest rate environment and worse-than-expected performance of the financial equity markets over the past several years have impacted Entergy's funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions. In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy's projected stream of benefit payments. Based on recent market trends, Entergy reduced its discount rate used to calculate benefit obligations from 6.75% in 2002 to 6.25% in 2003 and td 6% ih 2004. Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend ratesi Based on this review, Entergy increased its health care cost trend rate assumption used in calculating the December' 31, 2004 accumulated postretirement' benefit obligation to a 10% increase in health care costs in 2005 gradually decreasing each successive year, until it reaches a 4.5% annual increase in health care costs in 2011 and beyond. In determining its expected long-term rate of return on plan assets, Entergy reviews past long-term performance, asset allocations, and long-term inflation- assumptions. Entergy targets an asset allocation for its pension plan assets of roughly 65% equity securities,'31% fixed income securities, and 4% other investments. The target allocation for Entergy's other postretirement benefit assets is 51% equity securities and 49% fixed income securities. Based on: recent market trends, Entergy reduced its expected long-term rate of return on plan assets used to calculate benefit obligations from 8.75% for 2002 and 2003 to 8.5% in 2004. The assumed rate of increase in future compensation levels used to calculate benefit obligations was 3.25% in 2002, 2003, and 2004. Cost Sensitivity i The following chart reflects the sensitivity of pension cost to changes in certain actuarial assumptions (dollars in thousands): Change in Impact on 2004 Impact on Projected Actuarial Assumption' Assumption Pension Cost Benefit Obligation Increase/(Decrease) ' Discount rate (0.25%) ' $433 $4,249 Rate of return on plan assets (0.25%) -$130 Rate of increase in compensation 0.25% ' $204 ' $1,421 The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (dollars in thousands): Impact on Accumulated Change in 'Impact on 2004 Postretirement Benefit Actuarial Assumption Assumption Postretirement Benefit Cost Obligation Increase/(Decrease) Health care cost trend 0.25% $154 $756 Discount rate (0.25%) $111 $866 Each fluctuation above assumes that the other components of the calculation are held constant. Accounting Mechanisms In accordance with SFAS No. 87, "Employers' Accounting for Pensions," Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial 274
System Energy Resources, Inc. Management's Financial Discussion and Analysis assumptions and actual plan results are deferred and are amortized into cost only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. Additionally, Entergy accounts for the impact of asset performance on pension expense over a twenty-quarter phase-in period through a "market-related" value of assets calculation. Since the market-related value of assets recognizes investment gains or losses over a twenty-quarter period, the future value of assets will be impacted as- previously deferred gains or losses are recognized. As a result, the losses that the pension plan assets experienced in 2002 may have an adverse impact on pension 'cost in future years depending on whether the actuarial losses at each measurement date exceed the 10% corridor in accordance with SFAS 87. Costs and Funding Total pension cost for System Energy in 2004 was $4.6 million. System Energy anticipates 2005 pension cost to increase to $4.8 million due to decrease in the discount rate (from 6.25% to 6.00%) and the expected rate of return (from 8.75% to 8.5%) used to calculate benefit obligations. System Energy contributed $3.7 million to its pension plan in 2004, and anticipates making $9.2 million in contributions in 2005. The rise in pension funding requirements is due to declining interest rates and the phased-in effect of asset underperformance from 2000 to 2002, offset by the Pension Funding Equity Act relief passed in April 2004. System Energy's accumulated benefit obligation at December 31, 2004, 2003, and 2002 exceeded plan assets. As a result, System Energy was required to recognize an additional minimum liability as prescribed by SFAS 87. At December 31, 2004 System Energy increased its additional minimum liability to $7.7 million from $7.4 million at December 31, 2003. System Energy decreased its intangible asset to $0.2 million at December 31, 2004 from $0.4 million at December 31, 2003. System Energy increased its regulatory asset to $15.2 million at December 31, 2004, from $7.0 million at December 31, 2003. Net income for 2004, 2003, and 2002 was not impacted. Total postretirement health care and life insurance benefit costs for System Energy in 2004 were $1.5 million, including $0.8 million in savings due to the estimated effect of future Medicare Part D subsidies. System Energy expects 2005 postretirement health care and life insurance benefit costs to approximate $1.7 million, including $1 million in savings due to the estimated effect of future Medicare Part D subsidies. The increase in postretirement health care and life inisurance benefit costs is due to the decrease in the discount rate (from 6.25% to 6.00%) and an increase in the health care cost trend rate used to calculate benefit obligations. 275
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholder System Energy Resources, Inc.: We have audited the accompanying balance sheets of System Energy Resources, Inc. as of December 31, 2004 and 2003, and the related statements of income, retained earnings, and cash 'flows (pages 277 through 282 and applicable items in pages 284 through 348) for'each of the three years in the period ended Decembei-31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. " We conducted our audits in accordance with auditing standards of the Public Company Accounting' Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and'significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of' System Energy Resources, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. ' As discussed in Note 8 to the notes to respective financial statements, in 2003 System Energy Resburces,jInc. adopted the provisions of Statement of Financial Accounting Standards No. 143, Accountingfor Asset Retirement Obligations. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December, 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the'Comimittee' of Sponsoring Organizations of the Treadway Commission and our' report dated March 8, 2005' expressed 'an unqualified opinion on management's assessment' of the effectiveness of the Company's internal' control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting. DELOITTE & TOUCHE LLP New Orleans, Louisiana March 8, 2005 276
SYSTEM ENERGY RESOURCES, INC. INCOME STATEMENTS For the Years Ended December 31, 2004 2003 2002 (In Thousands) OPERATING REVENUES Domestic electric $545,381 $583,820 $602,486 OPERATING EXPENSES Operation and Maintenance: Fuel, fuel-related expenses, and gas purchased for resale 38,337 43,132 36,456 Nuclear refueling outage expenses 12,655 12,695 10,723 Other operation and maintenance 96,809 105,333 98,264 Decommissioning 23,434 21,799 16,055 Taxes other than income taxes 24,364 25,521 25,992 Depreciation and amortization 127,081 109,528 112,093 Other regulatory charges (credits) - net (10,433) 27,400 53,769 TOTAL 312,247 345,408 353,352 OPERATING INCOME 233,134 238,412 249,134 OTHER INCOME Allowance for equity funds used during construction 1,544 1,140 2,449 Interest and dividend income 6,870 7,556 2,857 Miscellaneous - net 841 (1,194) 826 TOTAL 9,255 7,502 6,132 INTEREST AND OTHER CHARGES Interest on long-term debt 58,561 62,802 73,891 Other interest - net 367 1,818 2,748 Allowance for borrowed funds used during construction (500) (554) (902) TOTAL 58,428 64,066 75,737 INCOME BEFORE INCOME TAXES 183,961 181,848 179,529 Income taxes 78,013 75,845 76,177 NET INCOME $105,948 $106,003 $103,352 See Notes to Respective Financial Statements, 277
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SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2004 2003 2002 (In Thousands) OPERATING ACTIVITIES Net Income S105,948 $106,003 $103,352 Adjustments to reconcile net income to net cash flow provided by operating activities: Other regulatory charges (credits) - net (10,433) 27,400 53,769 Depreciation, amortization, and decommissioning 150,515 131,327 128,148 Deferred income taxes and investment tax credits (178,535) (35,207) (38,246) Changes in working capital: Receivables (41,067) (8,025) 5,719 Accounts payable (5,324) (1,232) 14,767 Taxes accrued 328,617 (123,317) (43,112) Interest accrued 13,375 (12,904) (4,568) Other working capital accounts 2,763 1,463 (6,108) Provision for estimated losses and reserves (1,404) 2,914 163 Changes in other regulatory assets 31,453 26,307 52,448 Other (62,980) (13,912) (40,693) Net cash flow provided by operating activities 332,928 100,817 225,639 INVESTING ACTIVITIES Construction expenditures (32,303) (18,195) (40,306) Allowance for equity funds used during construction 1,544 1,140 2,449 Nuclear fuel purchases (45,497) (43,140) Proceeds from sale/leaseback of nuclear fuel 45,677 43,140 Decommissioning trust contributions and realized change in trust assets (20,956) (21,528) (13,370) Changes in other temporary investments - net 6,482 (6,482) 22,354 Net cash flow used In Investing activities (45,053) (45,065) (28,873) FINANCING ACTIVITIES Proceeds from the issuance of long-term debt 69,505 Retirement of long-term debt (13,973) (11,375) (100,891) Other financing activities (5,483) Dividends paid; Common stock (104,600) (105,000) (10l,S00) Net cash flow used In financing activities (124,056) (116,375) (133,186) Net Increase (decrease) In cash and cash equivalents 163,819 (60,623) 63,580 Cash and cash equivalents at beginning of period 52,536 113,159 49,579 Cash and cash equivalents at end of period S216,355 $52,536 S113,159 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid/(received) during the period for: Interest - net of amount capitalized $40,000 $73,636 $77,190 Income taxes ($70,595) $230,919 $156,957 See Notes to Respective Financial Statements. 279
SYSTEM ENERGY RESOURCES, INC. BALANCE SHEETS ASSETS December 31, 2004 2003 (In Thousands), . CURRENT ASSETS Cash and cash equivalents: Cash $399 $2,918 Temporary cash investments - at cost, which approximates market 215,956 49,618 Total cash and cash equivalents 216,355 52,536 Other temporary investments 6,482 Accounts receivable: Associated companies 111,588 72,477 Other 3,733 1,777 Total accounts receivable 115,321 74,254 Materials and supplies - at average cost 53,427 63,047 Deferred nuclear refueling outage costs. 9,510 2,979 Prepayments and other - . - - 1,007 1,031 . TOTAL 395,620 200,329 OTHER PROPERTY AND INVESTMENTS Decommissioning trust funds a, 205,083 . 172,916 8 UTILITY PLANT Electric 3,232,314;
- 3,205,895 Property under capital lease 469,993 466,521 Construction work in progress 28,743 31,344 Nuclear fuel under capital lease 65,572 - 47,242 TOTAL UTILITY PLANT 3,796,622, I 3,751,002 Less - accumulated depreciation and amortization 1,780,450 - - i ,672,658-UTILITY, PLANT - NET 2,016,172 2,078,344 DEFERRED DEBITS AND OTHER ASSETS I 1:iRegulatory assets: . . I
- . SFAS 109 regulatory asset - net ; 96,047 * - 115,633 Other regulatory assets 296,305 301,233
*I Other Ii 19,578& 12,269 H.I . .
TOTAL 411,930 429,135 TOTAL ASSETS S3,028,805 $2,880,724 See Notes to Respective Financial Statements. 280
SYSTEM ENERGY RESOURCES, INC.
.L L
.. BALANCE AN. ISAEH SHEETSES ,. .
LIABILITIES AND SHAREHOLDiR'S EQUITY December 31, 2004 2003 (In Thousands) CURRENT LIABILITIES Currently maturing long-term debt $25,266 $6,348 Accounts payable: Associated companies 3,880 Other 21,051 30,255 Taxes accrued 46,468 55,585 Accumulated deferred income taxes 3,477 942 Interest accrued 42,998 29,623 Obligations under capital leases 27,716 31,266 Other 1,621 1,971 TOTAL - 172,477 :' 155,990 NON-CURRENT LIABILITIES Accumulated deferred income taxes and taxes accrued 421,466 290,964 Accumulated deferred investment tax credits 75,612 79,088 Obligations under capital leases 37,855 15,976 Other regulatory liabilities 210,863 213,093 Decommissioning 335,893 312,459 Accumulated provisions 2,378 3,782 Long-term debt 849,593 882,401 Other 28,084 33,735 TOTAL 1,961,744 1,831,498 Commitments and Contingencies SHAREHOLDER'S EQUITY Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2004 and 2003 789,350 789,350 Retained earnings 105,234 103,886 TOTAL 894,584 893,236 TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY $3,028,805 $2,880,724 See Notes to Respective Financial Statements. 281
SYSTEM ENERGY RESOURCES, INC. STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 2004 2003 2002 (In Thousands) Retained Earnings, January I $103,886 $102,883 $101,331 Add: Net income 105,948 106,003 103,352 Deduct: Dividends declared 104,600 . 105,000 101,800 Retained Earnings, December 31 $105,234 $103,886 $102,883 See Notes to Respective Financial Statements.
'. 1 ' ,,
," A<;
I ; 282
SYSTEM ENERGY RESOURCES, INC. SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 2004 2003 2002" ' 2001 2000 (Dollars In Thousands) Operating revenues $545,381 $583,820 $602,486 $535,027 $620,032 Net Income $105,948 $106,003 $103,352 $116,355 $82,372 Total assets $3,028,805 $2,880,724 $2,915,898 $2,964,041 $3,369,048 Long-term obligations (1) $887,448 $898,377 $942,701 $865,439 $1,122,178 Electric energy sales (GWh) 9,212 9,812 9,053 8,921 7,567 (1) Included long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. 283
ENTERGY ARKANSAS, ENTERGY GULF STATES, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND SYSTEM ENERGY RESOURCES NOTES TO RESPECTIVE FINANCIAL STATEMENTS NOTE 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy) The accompanying separate financial statements of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (the "domestic utility companies") and System Energy are included in this document and result from these companies having registered securities with the SEC. These companies maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications, with no effect on net income or shareholders' equity. Use of Estimates in the Preparation of Financial Statements The preparation of the domestic utility companies' and System Energy's financial statements, in conformity with generally accepted accounting principles, requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used. Revenues and Fuel Costs Entergy Arkansas, Entergy Louisiana, and Entergy Mississippi generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, and Mississippi, respectively. Entergy Gulf States generates, transmits, and distributes electric power primarily to retail customers in Texas and Louisiana. Entergy Gulf States also distributes gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and gas to retail customers in the City of New Orleans, except for Algiers, where Entergy Louisiana is the electric power supplier. Entergy recognizes revenue from electric power and gas sales when it delivers power or gas to its customers. To the extent that deliveries have occurred but a bill has not been issued, the domestic utility companies accrue an estimate of the revenues for energy delivered since the latest billings. Entergy calculates the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and prices in effect in the domestic utility companies' various jurisdictions. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are so recorded and reversed. The domestic utility companies' rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Because the fuel adjustment clause mechanism allows monthly adjustments to recover fuel costs, Entergy Louisiana, Entergy New Orleans, and the Louisiana portion of Entergy Gulf States include a component of fuel cost recovery in their unbilled revenue calculations. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. Entergy Mississippi's fuel factor includes an energy cost rider that is adjusted quarterly. As discussed in Note 2 to the domestic utility companies and System Energy financial statements, the MPSC approved Entergy Mississippi's deferral of the refund of fuel over-recoveries for the third quarter of 2004 that would have been refunded in the first quarter of 2005. The deferred amount plus carrying charges will be refunded in the second and third quarters of 2005. In the case of Entergy Arkansas and the Texas portion of Entergy Gulf States, their fuel under-recoveries are treated as regulatory investments in the cash flow 284
Domestic utility companies and System Energy Notes to Respective Financial Statements statements because those companies are allowed by their regulatory jurisdictions to recover the fuel cost regulatory asset over longer than a twelve-month period, and the companies earn a carrying charge on the under-recovered balances. System Energy's operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy's common equity funds allocable to its net investment in Grand Gulf, plus System Energy's effective interest cost for its debt allocable to its investment in Grand Gulf. Properti, Plant, and Equipment Property, plant, and equipment is stated at original cost. The original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the domestic utility companies' and System Energy's plant is subject to mortgage liens. Electric plant includes the portions of Grand Gulf and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions. Net property, plant, and equipment by company and functional category, as of December 31, 2004 and 2003, is shown below: Entergy Entergy Entergy Entergy Entergy System 2004 - Arkansas Gulf States Louisiana Mississippi New Orleans Energv
* (In Millions)
Production
- Nuclear $951 $1,627 $1,543 $1,866 Other 269 529 197 221 12 Transmission 646 708 385 406 29 8 Distribution 1,283 1,339 1,000 713 337 Other 216 247 269 175 70 16 Construction work in progress 226 332 189 90 33 29 Nuclear fuel (leased and owned) 106 71 32 66 Asset retirement obligation 24 42 31 Property, plant, and equipment - net $3,721 $4,853 $3,657 $1,605 $481 $2,016 Entergy Entergy Entergy Entergy Entergy System 2003 -
Arkansas Gulf States Louisiana Mississippi New Orleans Energy (In Millions) Production Nuclear $940 $1,638 $1,593 $- $1,941 Other 326 583 205 228 17 Transmission 636 647 369 380 26 9 Distribution 1,184 1,197 923 ,632 294 Other . 214 238 266 166 75 17 Construction work in progress 239 326 172 1.09 45 31 Nuclear fuel (leased and owned) 110 64 65 47 Asset retirement obligation 45 32 45 33 Property, plant, and equipment - net $3,694 $4,725 $3,638 $1,515 $457 $2,078 285
Domestic utility companies and System Energy Notes to Respective Financial Statements Depreciation is computed on the straight-line basis at rates based on the estimated service lives of the various classes of property, Depreciation rates on average depreciable, property are shown below: Entergy Entergy Entergy Entergy Entergy System Arkansas Gulf States Louisiana Mississippi New Orleans Energy 2004 3.2% 2.1% 2.9% 2.5% 2.8% 2.9% 2003 3.2% 2.2% 3.0% 2.5% 3.1% 2.8% 2002 3.2% 2.4% 3.0% 2.5% 3.1% 2.8% Non-utility property - at cost (less accumulated depreciation) for Entergy Gulf States is reported net of accumulated depreciation of $125.1 million and $122.7 million as of December 31, 2004 and 2003, respectively. Jointly-Owned Generatin2 Stations Certain Entergy subsidiaries jointly own electric generating facilities with third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2004, the subsidiaries' investment and accumulated depreciation in each of these generating stations were as follows: Total Megawatt Accumulated Generating Stations Fuel-Type Capability (1) Ownership Investment Depreciation (In Millions) Entergy Arkansas - Independence Unit 1 Coal 815 31.50% $117 $73 Common Facilities Coal 15.75% $31 $18 White Bluff Units 1 and 2 Coal 1,635 57.00% $428 $264 Entergy Gulf States - Roy S. Nelson Unit 6 Coal 550 60.90% $403 $241 Big Cajun 2 Unit 3 Coal 575 42.00% $233 $128 Entergy Mississippi - Independence Units I and 2 and Coal 1,630 25.00% $232 $116 Common Facilities System Energy - Grand Gulf Unit 1 Nuclear 1,270 90.00%(2) $3,702 $1,780 (1) "Total Megawatt Capability" is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. (2) Includes an 11.5% leasehold interest held by System Energy. System Energy's Grand Gulf lease obligations are discussed in Note 9 to the domestic utility companies and System Energy financial statements. Nuclear Refueling Outage Costs The domestic utility companies and System Energy record nuclear refueling outage costs in accordance with regulatory treatment and the matching principle. These refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line. Except for the River Bend plant, the costs are deferred during the outage and amortized over the period to the next outage. In accordance with the regulatory treatment of the River Bend plant, the costs are accrued in advance and included in the cost of service used to establish retail rates. Entergy Gulf States relieves the accrued liability when it incurs costs during the next River Bend outage. 286
Domestic utility companies and System Energy Notes to Respective Financial Statements Allowance for Funds Used During Construction (AFUDC) AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both the plant balance and earnings, it is realized in cash through depreciation provisions included in rates. Income Taxes Entergy Corporation and the majority of its subsidiaries file a U.S. consolidated federal income tax return. Income taxes are allocated to the subsidiaries in proportion to their contribution to consolidated taxable income. SEC regulations require that no Entergy subsidiary pay more taxes than it would have paid if a separate income tax return had been filed. In accordance with SFAS 109, "Accounting for Income Taxes," deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities, and for certain credits available for carryforward. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the law or rate was enacted. Investment tax credits are deferred and amortized based upon the average useful life of the related property, in accordance with ratemaking treatment. Application of SFAS 71 The domestic utility companies and System Energy currently account for the effects of regulation pursuant to SFAS 71, "Accounting for the Effects of Certain Types of Regulation." This statement applies to the financial statements of a rate-regulated enterprise that meet three criteria. The enterprise must have rates that (i) are approved by a body empowered to set rates that bind customers (its regulator); (ii) are cost-based; and (iii) can be charged to and collected from customers. These criteria may also be applied to separable portions of a utility's business, such as the generation or transmission functions, or to specific classes of customers. If an enterprise meets these criteria, it capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. A significant majority of Entergy's regulatory assets, net of related regulatory and deferred tax liabilities, earn a return on investment during their recovery periods. SFAS 71 requires that rate-regulated enterprises assess the probability of recovering their regulatory assets at each balance sheet date. When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity's balance sheet. SFAS 101, "Accounting for the Discontinuation of Application of FASB Statement No. 71," specifies how an enterprise that ceases to meet the criteria for application of SFAS 71 for all or part of its operations should report that event in its financial statements. In general, SFAS 101 requires that the enterprise report the discontinuation of the application of SFAS 71 by eliminating from its balance sheet all regulatory assets and liabilities related to the applicable segment. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs and therefore no longer qualifies for SFAS 71 accounting, it is possible that an impairment may exist that could require further write-offs of plant assets. EITF 97-4: "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101" specifies that SFAS 71 should be discontinued at a date no later than when the effects of a transition to competition plan for all or a portion of the entity subject to such plan are reasonably determinable. Additionally, EITF 97-4 promulgates that regulatory assets to be recovered through cash flows derived from another portion of the entity that continues to apply SFAS 71 should not be written off; rather, they should be considered regulatory assets of the segment that will continue to apply SFAS 71. 287
Domestic utility companies and System Energy Notes to Respective Financial Statements See Note 2 to the domestic utility companies and System, Energy financial statements for discussion of transition to competition activity in the retail regulatory jurisdictions served by the domestic utility companies. Only Texas currently has an enacted retail open access law, but Entergy believes that significant issues remain to be addressed by regulators, and the enacted law does not provide sufficient detail to reasonably determine the impact on Entergy Gulf States' regulated operations. Cash and Cash Equivalents Entergy considers all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at date of purchase to be cash equivalents. Investments with original maturities of more than three months are classified as other temporary investments on the balance sheet. Investments Entergy applies the provisions of SFAS 115, "Accounting for Investments for Certain Debt and Equity Securities," in accounting for investments in decommissioning trust funds. As a result, Entergy records the decommissioning trust funds at their fair value on the consolidated balance sheet. Because of the ability of the domestic utility companies and System Energy to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, Entergy Arkansas, Entergy Gulf States (for the regulated portion of River Bend), Entergy Louisiana, and System Energy have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the nonregulated portion of River Bend, Entergy Gulf States has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. See Note 12 to the domestic utility companies and System Energy financial statements foif details onrithe decommissioning trust funds. Derivatives and Hedging - SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," requires that all derivatives be recognized in the balance sheet, either as assets or liabilities, at fair value, unless they meet the normal purchases normal sales criteria. The changes in the fair value of recognized derivatives are recorded, each period in current earnings or other comprehensive. income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction,. Contracts for commodities that will be delivered in quantities expected to be used or sold in the-ordinary course of business, including certain purchases and sales of power and fuel, are not classified as derivatives. These contracts are exempted under the normal purchase, normal sales criteria of SFAS 133. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.
- For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship, between the hedging instrument and the hedged item must be documented to include the, risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The ineffective portions of all hedges are recognized in current-period earnings.
Fair Values The estimated fair values of the domestic utility companies' and System Energy's financial instruments and derivatives are determined using bid prices and market quotes. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that the domestic utility companies and System Energy could realize in a current market exchange. Gains or losses realized on 288
Domestic utility companies and System Energy Notes to Respective Financial Statements financial instrumerits held by regulated businesses may be reflected in future rates and therefore do not accrue to the benefit or detriment of stockholders. The domestic utility companies and System Energy consider the carrying amounts of most of their financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. Additional information regarding financial instruments and their fair values is included in Notes 5 and 6 to the domestic utility companies and System Energy financial statements. Impairment of Long-Lived Assets The domestic utility companies and System Energy periodically review their long-lived assets whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets. River Bend AFUDC The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Gulf States Utilities on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized over the estimated remaining economic life of River Bend. Transition to Competition Liabilities In conjunction with electric utility industry restructuring activity in Texas, regulatory mechanisms were established to mitigate potential stranded costs. Texas restructuring legislation allowed depreciation on transmission and distribution assets to be directed toward generation assets. The liability recorded as a result of this mechanism is classified as "transition to competition" deferred credits on the balance sheet for Entergy Gulf States. Reacquired Debt The premiums and, costs associated with reacquired debt of the domestic utility companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States) are being amortized over the life of the related new issuances, in accordance with ratemaking treatment. Entergy Gulf States' Deregulated Operations Entergy Gulf States does not apply regulatory accounting principles to its wholesale jurisdiction, Louisiana retail deregulated portion of River Bend, and the 30% interest in River Bend formerly owned by Cajun. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 16%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Gulf States to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing such incremental revenue above 4.6 cents per kWh between ratepayers and shareholders. 289
Domestic utility companies and System Energy Notes to Respective Financial Statements The results of these deregulated operations before interest charges for the years ended December 31, 2004, 2003, and 2002 are as follows: 2004' 2003 2002 (In Thousands) Operating revenues $280,279 $273,150 - $209,752 Operating expenses Fuel, operation, and maintenance 197,275 177,385 158,927 Depreciation and accretion 30,653 47,566 40,092 Total operating expense - 227,928. 224,951 199,019 Operating income 52,351 48,199 10,733 Income tax expense 20,414 17,722 4,503 Net income from deregulated utility operations $31,937 $30,477 $6,230 The net investment associated with these deregulated operations as of December 31, 2004 and 2003 was approximately $830 and $838 million, respectively. New Accounting Pronouncements During 2004, Entergy adopted the provisions of FSP 106-2, "Accounting and Disclosure Requirements Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003," which is discussed further in Note 10 to the domestic utility companies and System Energy financial statements. SFAS 151, "Inventory Costs - an amendment of ARB No. 43, Chapter 4" and SFAS 153, "Exchanges of Nonmonetary Assets", were also issued during the fourth quarter of 2004 and are effective for Entergy in 2006 and 2005, respectively. Entergy does not expect the impact of the adoption of these standards to be material. During 2003, Entergy adopted the provisions of the following accounting standards:! SFAS 143, "Accounting for Asset Retirement Obligations," which is discussed further in Note 8 to the domestic' utility companies and System Energy financial statements; FIN 46, Consolidation of Variable Interest Entities," which is discussed further in Note 5 to the domestic utility companies and System Energy financial statements; and SEAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS 150, which became effective July 1, 2003, requires mandatorily redeemable financial instruments to be classified and treated as liabilities in the presentation of financial 'position and results "of operations. The only effect of implementing SFAS 150 for Entergy is the inclusion of long-term debt and preferred stock with sinkinig fund under the liabilities caption in Entergy's balance sheet. Entergy's results of operations and cash flows were not affected by this standard. During 2003, Entergy also adopted the provisions of the following accounting standards: SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" and related interpretations by the Derivatives Implementation Group, 'and 'FIN 45, "Guarantor's Accounting and'Disclosure Requirements for Guarantees Including Indirect Guarantees of Indebtedness of Others". The adoption of these standards did not have a material effect on Entergy's financial statements. ' 290
Domestic utility companies and System Energy Notes to Respective Financial Statements NOTE 2. RATE AND REGULATORY MATTERS Electric Industry Restructuring and the Continued Application of SFAS 71 Although Arkansas and Texas enacted retail open access laws, the retail open access law in Arkansas has now been repealed. Retail open access in Entergy Gulf States' service territory in Texas has been delayed. Entergy believes that significant issues remain to be addressed by Texas regulators, and the enacted law does not provide sufficient detail to allow Entergy Gulf States to reasonably determine the impact on Entergy Gulf States' regulated operations. Entergy therefore continues to apply regulatory accounting principles to the retail operations of all of the domestic utility companies. Following is a summary of the status of retail open access in the domestic utility companies' retail service territories. Arkansas (Dntergy Arkansas) In April 1999, the Arkansas legislature enacted Act 1556, the Arkansas Electric Consumer Choice Act, providing for competition in the electric utility industry through retail open access. In December 2001, the APSC recommended to the Arkansas General Assembly that legislation be enacted during the 2003 legislative session to either repeal Act 1556 or further delay retail open access until at least 2010. In February 2003, the Arkansas legislature voted to repeal Act 1556 and the repeal was signed into law by the governor. Texas (Entergy Gulf States) i As ordered by the PUCT, in January 2003, Entergy Gulf States filed its proposal for an interim solution (retail open access without a FERC-approved RTO), which among other elements, included:
- the recommendation that retail open access in Entergy Gulf States' Texas service territory, including corporate unbundling, occur by January 1, 2004, or else be delayed until at least January 1, 2007. If retail open access is delayed past January 1, 2004, Entergy Gulf States requested authorization to separate into two bundled utilities, one subject to the retail jurisdiction of the PUCT and one subject to the retail jurisdiction of the LPSC.
- the recommendation that Entergy's transmission organization, possibly with the oversight of another entity, will continue to serve as the transmission authority for purposes of retail open access in Entergy Gulf States' service territory.
- the recommendation that the decision points be identified that would require prior to January 1, 2004, the PUCT's determination, based upon objective criteria, whether to proceed with further efforts toward retail open access in Entergy Gulf States' Texas service territory.
After considering the proposal, in an April 2003 order the PUCT set forth a sequence of proceedings and activities designed to initiate an interim solution. These proceedings and activities included initiating a proceeding to certify an independent organization to administer market protocols and ensure nondiscriminatory access to transmission and distribution systems. In July 2004 the PUCT denied Entergy's application to certify Entergy's transmission organization as an independent organization under Texas law. In its order, the PUCT also ordered: the cessation of efforts to develop an interim solution for retail open access in Entergy Gulf States' Texas service territory, termination of the pilot project in that territory, and a delay in retail open access in that territory until either a FERC-approved RTO is in place or some other independent transmission entity is certified under Texas law. Several parties have appealed the termination of the pilot program aspect of the order, claiming the issue was not properly a part of the proceeding. 291
Domestic utility companies and System Energy Notes to Respective Financial Statements In February 2005, bills were submitted in the Texas Legislature that would clarify that Entergy Gulf States is no longer subject to a rate freeze and specify that retail open access will not commence in Entergy Gulf States' Texas service territory until the PUCT certifies a power region. Louisiana (Entergy Gulf States and Entergy Louisiana) In November 2001, the LPSC decided not to move forward with retail open access for any customers at this time. 'The LPSC instead directed its staff to hold collaborative group meetings concerning open access from time to time, and to have the LPSC staff monitor developments in neighboring states and to report to the LPSC regarding the progress of retail access developments in those states. In September 2004, in response to a study funded by certain industrial customers that evaluated a limited industrial-only retail choice program, the LPSC asked the LPSC staff to solicit comments and obtain information from utilities, customers, and other interested parties concerning the potential costs and benefits of a limited choice program, the impact of such a program on other customers, as well as issues such as stranded costs and transmission service. Comments from interested parties were filed with the LPSC on January 14, 2005. The LPSC has not established a procedural. framework for consideration of the comments. At this time, it is not certain what further action, if any, the LPSC might take in response to the information it received. Mississippi (Entergy Mississippi) In May 2000, after two years of studies and hearings, the MPSC announced that it was suspending its docket studying the opening of the state's retail electricity markets to competition. The MPSC based its decision on its finding. that competition could raise the electric rates paid by residential and small commercial customers. The final decision regarding the introduction of retail competition ultimately lies with the Mississippi Legislature. Management cannot predict when, or if, Mississippi will deregulate its retail electricity market. New Orleans (Entergy New Orleans) Entergy New Orleans filed an electric transition to competition plan in September 1997. No procedural schedule has been established for consideration of that plan by the City Council.
Domestic utility companies and System Energy Notes to Respective Financial Statements Regulatory Assets Other Regulatory Assets The domestic utility companies and System Energy are subject to the provisions of SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. In addition to the regulatory assets that are specifically disclosed on the face of the balance sheets, the tables below provide detail of "Other regulatory assets" included on the balance sheets of the domestic utility companies and System Energy as of December 31, 2004 and 2003 (in millions). Entergy Entergy Entergy Entergy Entergy System 2004 Arkansas Gulf States Louisiana Mississippi New Orleans Energy Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 8) $141.2 $- $141.6 $- $97.3 Deferred distribution expenses - recovered through May 2008 4.9 Deferred fossil plant maintenance expenses - recovered through December 2007 (Note 2) 3.6 Deferred fuel - non-current - recovered through rate riders when rates are redetermined annually 13.7 8.1 Depreciation re-direct - recovery begins at start of retail open access (Note 1) 79.1 DOE Decom. and Decontamination; Fees - recovered through fuel rates until December 2006 (Note 8) 13.1 2.3 5.0 4.9 Incremental ice storm costs - recovered until 2032 14.2 Low-level radwaste - recovery timing dependent upon pending lawsuit 16.2 3.1 Pension costs (Note 10) 70.8 34.1 20.2 15.2 7.4 Postretirement benefits - recovered through 2013 (Note 10) 19.1 Provision for storm damages - recovered through cost of service 29.0 57.1 41.7 Removal costs - recovered through depreciation rates (Note 8) 34.9 0.9 32.7 1.3 17.1 Resource planning - recovery timing will be determined by the LPSC in a base rate proceeding (Note 2) 25.4 River Bend AFUDC - recovered through A'ugust 2025 (Note 1) 37.5 Sale-leaseback deferral - recovered through June 2014 (Note 9) 127.3 Spindletop gas storage facility - recovered through 2032 42.3 Unamortized loss on reaquired debt - recovered over term of debt 37,0 43.4 27.4 15.6 4.6 41.8 Other - various, . 11.0. 19.3 27.3 6.1 10.8 0.5 Total $400.2 $285.0 $302.5 $82.7 $40.4 $296.3 293
Domestic utility companies and System Energy Notes to Respective Financial Statements 2003 Entergy Entergy Entergy Entergy Entergy System Arkansas Gulf States Louisiana Mississippi New Orleans Energy; Asset Retirement Obligation (Note 8) $203.7 $36.2 $132.3 $92.7 Deferred fuel - non-current 17.1 11.1 Depreciation re-direct (Note 1) 79.1 DOE Decom. and Decontamination Fees (Note 8) 17.1 3.0 6.5 6.4 Incremental ice storm costs 14.7. Low-level radwaste 16.2 3.1 Pension costs (Note 10) 41.7 6.4 10.4 7.1 Postretirement benefits (Note 10) 21,5 Provision for storm damages 25.3 57.4 40.9 3.5 Removal costs (Note 8) 26.6 4.2 24.4 2.1 15.1 Resource planning (Note 2) 5.8 River Bend AFUDC (Note 1) 39.4 Sale-leaseback deferral (Note 9) 131.7 Spindletop gas storage facility 38.0 Unamortized loss on reaquired debt 38.3 46.6 24.0 11.8 1.7 41.9 1994 FERC Settlement (Note 2)
- 4.0 Other 15.3 13.4 8.2 1.1 13.0 2.3 Total $437.5 $320.4 $217.7 $58.3 $27.2 $301.2 Deferred fuel costs The domestic utility companies are allowed to recover certain fuel and purchased power costs through fuel mechanisms included in electric rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is recorded as "Deferred fuel costs"t on the domestic utility companies' financial statements. The table below shows the amount of deferred fuel costs as of December 31, 2004 and 2003 that Entergy expects to recover or (refund) through the fuel mechanisms of the domestic utility companies, subject to subsequent regulatory review.
2004 2003 (In Millions) Entergy Arkansas $7.4 $10.6 Entergy Gulf States $90.1 $118.4 Entergy Louisiana $8.7 $30.6 Entergy Mississippi ($22.8) $89.1 Entergy New Orleans $2.6 ($2.7) Entergy Arkansas Entergy Arkansas' rate schedules include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an annual energy cost rate, The energy cost rate includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. In March 2004, Entergy Arkansas filed with the APSC its energy cost recovery rider for- the period April' 2004 through March 2005. The filed energy cost rate, which accounts for 12 percent of a typical residential customer's bill using 1,000 kWh per month, increased 16 percent due primarily to the elimination of a"credit contained in the prior year's rate to refund previously over-recovered fuel costs. Also included in the current year's energy cost calculation is a decrease in rates of $3.9 million as a result of the operation of a revised energy allocation method between the retail and wholesale sectors resulting from the APSC's approval of a life-of-resources power purchase agreement with Entergy New Orleans. 294
Domestic utility companies and System Energy Notes to Respective Financial Statements Entergy Gulf States (Texas) In the Texas jurisdiction, Entergy Gulf States' rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, not recovered in base rates. Under the current methodology, semi-annual revisions of the fixed fuel factor may be made in March and September based on the market price of natural gas. Entergy Gulf States will likely continue to use this methodology until the start of retail open access, which has been delayed. The amounts collected under Entergy Gulf States' fixed fuel factor and any interim surcharge implemented until the date retail open access commences are subject to fuel reconciliation proceedings before the PUCT. In the Texas jurisdiction, Entergy Gulf States' deferred electric fuel costs are $78.6 million as of December 31, 2004, which includes the following: Amount (In Millions) Under-recovered fuel costs for the period 9/03 - 7/04 to be recovered through an interim fuel surcharge over a six-month period'beginning in January 2005 $27.8 Items to be addressed as part of unbundling $29.0 Imputed capacity charges $ 9.3 Other $12.5 The PUCT has ordered that the imputed capacity charges be excluded from fuel rates and therefore recovered through base rates. Entergy Gulf States filed'a retail'electric rate case and fuel proceeding with the PUCT in August 2004. As discussed below, the PUCT dismissed the rate' case and fuel reconciliation proceeding in' October 2004 indicating that Entergy Gulf States is still subject to a rate freeze based on the current PUCT-approved settlement agreement stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless the rate freeze is lifted by the PUCT prior'thereto. Without a Texas base rate proceeding, it is possible that Entergy Gulf States will not be allowed to recover imputed capacity charges in Texas retail rates in the future. Entergy Gulf States believes the PUCT has misinterpreted the settlement and has appealed the PUCT order to the Travis County District Court and also intends to'pursue other available remedies as discussed in "Electric Industry Restructuring and the Continued Application of SFAS '71." The dismissal of the rate case does not preclude Entergy Gulf States from seeking the reconciliation of fuel and purchased power costs of $288 million incurred from September 2003 through March 2004 when, at the appropriate time, similar costs are reconciled in the future. In January 2001, Entergy Gulf States filed with the PUCT a fuel reconciliation case covering the period from March 1999 through August 2000. Entergy Gulf States was reconciling approximately $583 million of fuel and purchased power costs. As part of this filing, Entergy Gulf States requested authority to collect $28 million, plus interest, of under-recovered fuel and purchased power costs. In August 2002, the PUCT reduced Entergy Gulf States' request to approximately $6.3 million, including interest through July 31,2002. Approximately $4.7 million of the total reduction to the requested surcharge relates to nuclear fuel costs that the PUCT deferred ruling on at that time. In October 2002, Entergy Gulf States appealed the PUCT's final order in Texas District Court. In its' appeal, Entergy Gulf States is challenging the PUCT's disallowance of approximately $4.2 million related to imputed capacity costs and its disallowance related to' costs for energy delivered from the 30% non-regulated share of River Bend. The case was argued before the Travis County Texas District Court in August 2003 and the Travis County District Court judge affirmed the PUCT's order. In October 2003, Entergy Gulf States appealed this decision to the Court of Appeals. Oral argument before the appellate court occurred in September 2004 and the matter is still pending. In September 2003, Entergy Gulf States filed an application with the PUCT to implement an $87.3 million interim fuel surcharge, including interest, to collect under-recovered fuel and purchased power expenses incurred from September 2002 through August 2003. Hearings were held in October 2003 and the PUCT issued an order in December 2003 allowing for the recovery of $87 million: The surcharge was collected over a twelve-month period that began in January 2004.
'295
Domestic utility companies and System Energy Notes to Respective Financial Statements In March 2004, Entergy Gulf States filed with the PUCT a fuel reconciliation case covering the period September 2000 through August 2003. Entergy Gulf States is reconciling $1.43 billion of fuel and purchased power costs on a Texas retail basis. This amount includes $8.6 million of under-recovered costs that Entergy Gulf States is asking to reconcile and roll into its fuel over/under-recovery balance to be addressed in the next appropriate fuel proceeding. This case involves imputed capacity and River Bend payment issues similar to those decided adversely in the January 2001 proceeding, discussed above, which is now on appeal. On January 31, 2005, the ALJs issued a Proposal for Decision that recommends disallowing $10.7 million (excluding interest) related to these two issues. A final PUCT decision is expected in the first quarter of 2005. In September 2004, Entergy Gulf States filed an application with the PUCT to implement a $27.8 million interim fuel surcharge, including interest, to collect under-recovered fuel and purchased power expenses incurred from September 2003 through July 2004. Entergy Gulf States proposed to collect the surcharge over a six-month period beginning January 2005. In December 2004, the PUCT approved the surcharge consistent with Entergy Gulf States' request. Amounts collected though the interim fuel surcharge, which will be implemented over the six-month period commencing January 2005, are subject to final reconciliation in a future fuel reconciliation proceeding. Entergv Gulf States (Louisiana) and Entergv Louisiana In Louisiana, Entergy Gulf States and Entergy Louisiana recover electric fuel and purchased power costs for the upcoming month based upon the level of such costs from the prior month. In Louisiana, Entergy Gulf States' purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations of actual fuel costs incurred with fuel cost revenues billed to customers. In August 2000, the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Louisiana pursuant to a November 1997 LPSC general order. The time period that is the subject of the audit is January 1, 2000 through December 31, .2001. In September 2003, the LPSC staff issued its audit report and recommended a disallowance with regard to one item. The issue relates to the alleged failure to uprate Waterford 3 in a timely manner, a claim that also has been raised in the summer 2001, 2002, and 2003 purchased power proceedings. The LPSC staff has quantified the possible disallowance as between $7.6 and $14 million. Entergy Louisiana notified the LPSC that it will contest the recommendation. The procedural schedule in the case has been suspended. A status conference for the purpose of establishing a new procedural schedule will be set when the current hearings in the Power Purchase Agreement proceedings at the FERC are concluded. The FERC hearings in that matter concluded in November 2004. If the LPSC approves the proposed settlement (discussed below under "Retail Rate Proceedings"), the issue of a proposed imprudence disallowance relating to the uprate will be resolved and will no longer be at issue in this proceeding. In January 2003, the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States and its affiliates pursuant to a November 1997 LPSC general order. The audit will include a review of the reasonableness of charges flowed by Entergy Gulf States through its fuel adjustment clause in Louisiana for the period January 1, 1995 through December 31, 2002. Discovery is underway, but a detailed procedural schedule extending beyond the discovery stage has not yet been established, and the LPSC staff has not yet issued its audit report. Enterge Mississippi Entergy Mississippi's rate schedules include an energy cost recovery rider which is adjusted quarterly to reflect accumulated over- or under-recoveries, from the second prior quarter. In May 2003, Entergy Mississippi filed and the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Under the MPSC's order, Entergy Mississippi deferred until 2004;the collection of fuel under-recoveries for the first and second quarters of 2003 that would have been collected in the third and fourth quarters of 2003, respectively. The deferred 296
Domestic utility companies and System Energy Notes to Respective Financial Statements amount of $77.6 million plus carrying charges was collected through the energy cost recovery rider over a twelve-month period that began in January 2004. In January 2005, the MPSC approved a change in Entergy Mississippi's energy cost recovery rider. Entergy Mississippi's fuel over-recoveries for' the third quarter of 2004 of $21.3 million will be deferred from the first quarter 2005 'energy cost recovery rider adjustment calculation. The deferred amount of $21.3 million plus carrying charges will be refunded through the energy cost recovery rider in the second and third quarters of 2005 at a rate of 45% and 55%, respectively. Entergy New Orleans. Entergy New Orleans' electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations, including carrying charges. Entergy New Orleans' gas rate schedules include estimates for the billing month adjusted by a surcharge or credit for deferred fuel expense arising from monthly reconciliations, including carrying charges. In June and November 2004, the City Council passed resolutions implementing a package of measures developed by Entergy New Orleans and the Council Advisors to protect customers from potential gas price spikes during the 2004 -:2005 winter heating season. These measures include: maintaining Entergy New Orleans' financial hedging plan for its purchase of wholesale gas, and deferral of collection of up to $6.2 million of gas costs associated with a cap on the purchased gas adjustment in November and December 2004 and in the event that the average residential customer's gas bill were to exceed a threshold level. The deferrals resulting from these caps will receive accelerated recovery over a seven-month period beginning in April 2005. In November 2004, the City Council directed Entergy New Orleans to confer with the Council Advisors regarding possible modification of the current gas cost collection mechanism in order to address concerns regarding its fluctuations particularly during the winter heating season. Retail Rate Proceedings Filings with the APSC (Entergy Arkansas) Retail Rates No significant retail rate proceedings are pending in Arkansas at this time. Filings with the PUCT and Texas Cities (Entergy Gulf States) Retail Rates Entergy Gulf States is operating in Texas under the terms of a December 2001 settlement agreement approved by the PUCT. The settlement provided for a base rate freeze that has remained in effect during the delay in the implementation of retail open access in Entergy Gulf States' Texas service territory. In view of the PUCT
- orderin July 2004 to further delay retail open access in the Texas service territory, Entergy Gulf States filed a retail electric rate case and fuel reconciliation proceeding with the PUCT in August 2004 seeking the following:
- approval of a base rate increase of $42.6 million annually for the Texas retail jurisdiction;
*. approval to implement a $14.1 million per year rider to recover, over a 15-year period, $110.9 million of incurred costs related to its efforts to transition to a competitive retail market in accordance with the Texas restructuring law;
- approval to implement a proposed $11.3 million franchise fee rider to recover payments to municipalities charging such fees; and
- a requested return on equity of 11.5%.
297
Domestic utility companies and System Energy Notes to Respective Financial Statements In addition, Entergy Gulf States' fuel reconciliation filing made in conjunction with the base rate case sought to reconcile approximately $288 million in fuel and purchased power costs incurred during the period September 2003 through March 2004. In October 2004, the PUCT issued a written order in which it dismissed the rate case and fuel reconciliation proceeding indicating that Entergy Gulf States is still subject to a rate freeze based on a PUCT-approved agreement in 2001 stipulating that a rate freeze would remain in effect until retail open access commenced in Entergy Gulf States' service territory, unless the 'rate freeze is lifted by the PUCT prior thereto. Entergy Gulf States believes the PUCT has misinterpreted the settlement and has appealed the PUCT order to the Travis County District Court and intends to pursue other available remedies. In February 2005, bills were submitted in the Texas Legislature that would clarify that Entergy Gulf States is no longer subject to a rate freeze and specify that retail open access will not commence in Entergy Gulf States' Texas service territory until the PUCT certifies a power region. Recovery of River Bend Costs In March 1998, the PUCT disallowed recovery of $1.4 billion of company-wide abeyed River'Bend plant costs, which have been held in abeyance since 1988. Entergy Gulf States appealed the PUCT's decision on this matter to the Travis County District Court in Texas. In April, 2002, the Travis County District Court issued an order affirming the PUCT's order on remand disallowing recovery of the abeyed plant costs. Entergy Gulf States appealed this ruling to the Third District Court of Appeals. In July 2003, the Third District Court of Appeals unanimously affirmed the judgment of the Travis County District Court. After considering the progress of the proceeding in light of the decision of the Court of Appeals, Entergy Gulf States accrued for the loss that would be associated with a final, non-appealable decision disallowing the abeyed plant costs. The net carrying value of the abeyed plant costs was $107.7 million at the time of the Court of Appeals decision. Accrual of the $107.7 million loss was recorded in the second quarter of 2003 as miscellaneous other income (deductions) and reduced net income by $65.6 million after-tax. In September 2004, the Texas Supreme Court denied Entergy Gulf States' petition for review, and Entergy Gulf States filed a motion for rehearing. In February 2005, the Texas Supreme Court denied the motion for rehearing, and the proceeding is now final. Filings with the LPSC Proposed Settlement (Entergy Gulf States and Entergy Louisiana) In September 2004, the LPSC consolidated various dockets that were the subject of settlement discussions between the LPSC staff and Entergy Gulf States and Entergy Louisiana. The LPSC directed its staff to continue the settlement discussions and submit any proposed settlement to the LPSC for its consideration. In January 2005, Entergy Gulf States and Entergy Louisiana filed testimony with the LPSC in support of a proposed settlement that currently includes an offer to refund $76 million to' Entergy Gulf States' Louisiaila customers, with no immediate change in current base rates and to refund $14 million to Entergy Louisiana's customers. If the LPSC approves the proposed settlement, Entergy Gulf States will be regulated under a three-year formula rate plan that, among other provisions, establishes a ROE mid-point of 10.65% and permits Entergy Gulf States to recover incremental capacity costs without filing a traditional base rate proceedings The settlement resolves all issues' in, and will result in the dismissal of, Entergy Gulf States' fourth, fifth, sixth, seventh, and eighth annual earnings reviews, Entergy Gulf States' ninth post-merger earnings review and revenue requirement analysis, a fuel review for Entergy Gulf States, dockets established to consider issues concerning power purchases for Entergy Gulf States and Entergy Louisiana for the summers of 2001, 2002, 2003, and 2004, and a docket concerning retail issues arising under the Entergy System Agreement. The settlement does not include the System Agreement case pending at FERC. The LPSC has solicited comments on the proposed settlement from the parties to the various proceedings at issue in the proposed settlement. The proposed settlement is scheduled to be presented to the LPSC for consideration on March 23, 2005. 298
Domestic utility companies and System Energy Notes to Respective Financial Statements Annual Earnings Reviews (Entergy Gulf States) In May 2002, Entergy Gulf States filed its ninth and last required post-merger analysis with the LPSC. The filing included an earnings review filing for the 2001 test year that resulted in a rate decrease of $11.5 million, which -was implemented effective June' 2002. In, its latest testimony, in December 2003, the LPSC staff recommended a rate -refund of $30.6 million and a prospective rate reduction of approximately $50 million. Hearings concluded in May 2004. Should the LPSC approve the proposed settlement discussed above, the ninth post-merger analysis would be resolved. In December 2002, the LPSC approved a settlement between Entergy Gulf States and the LPSC staff pursuant to which Entergy Gulf States agreed to make a base rate refund of $16.3 million, including interest, and to implement a $22.1 million prospective base rate reduction effective January 2003. The settlement discharged any potential liability for claims that relate to Entergy Gulf States' fourth, fifth, sixth,' seventh, and eighth post-merger earnings reviews, with the exception of certain issues related to the calculation of the River Bend Deregulated Asset Plan percentage. Entergy Gulf States made the refund in February 2003. Should the LPSC approve the proposed settlement discussed above, the outstanding issue in these proceedings would be resolved. Retail Rates (Entergy Gulf States) In July 2004, Entergy Gulf States filed with the LPSC an application for a change in its rates and charges seeking an increase of $9.1 million in gas base rates in order to allow Entergy Gulf States an opportunity to earn a fair and reasonable rate of return. Entergy Gulf States also is seeking approval of certain proposed rate design, rate schedule, and policy changes.' Discovery is underway, and a decision is expected during the third quarter of 2005. (Entergy Louisiana) '
'In January 2004, Entergy Louisiana made a rate filing with the LPSC requesting a base rate increase of approximately $167 million. In that filing, Entergy Louisiana noted that 'approximately $73 million of the base rate increase was attributable to the acquisition of a generating station and certain power purchase agreements that, based on current natural gas prices, would produce fuel and purchased -power savings for customers that substantially mitigate the impact of the requested 'base rate 'inrease. The filing also requested an allowed ROE midpoint of 11.4%. Entergy Louisiana's previously authorized ROE mid-point currently in effect is 10.5%.
Hearings concluded in December 2004. Based on'the evidence submitted at'the hearing, the LPSC staff is recommending approximately a $7 million base' rate increase. The LPSC 'staff proposed the implementation of a formula rate plan that 'includes a provision for the recovery of incremental capacity costs, including those related to the proposed Perryville acquisition, without: filing a traditional base rate proceeding' A decision by the LPSC is expected in mid- to late-March 2005 on these issues. ' ' : Filings with the MPSC (Entergy Mississippi) Formula Rate Plan Filings - ' ' , , Entergy Mississippi is operating under a December 2002 order issued by the MPSC. The order endorsed a new power management rider schedule designed to more efficiently collect capacity portions of purchased power costs. Also, the order-provides for improvements in the return on equity formula and more robust performance measures for Entergy Mississippi's formula rate plan.. Under the provisions of Entergy Mississippi's formula rate plan, a bandwidth is placed around the benchmark ROE, and if Entergy Mississippi earns outside of the bandwidth (as well as outside of a range-of-no-change at each edge of the bandwidth), then Entergy Mississippi's rates will be adjusted, though on a prospective basis only. Under Mississippi law and Entergy Mississippi's formula rate plan, however, if Entergy Mississippi's earned-ROE is above the top of the range-of-no-change at the top of the formula rate plan bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the point halfway between such earned ROE and the top of the bandwidth; and Entergy Mississippi's retail rates are set at 299
Domestic utility companies and System Energy Notes to Respective Financial Statements that halfway-point ROE level. In the situation where Entergy Mississippi's earned.ROE is not above the top, of the range-of-no-change at the top of the bandwidth, then Entergy Mississippi's "Allowed ROE" for the next twelve-month period is the top of the range-of-no-change at-the top bf the bandwidth. ,'
, Entergy Mississippi made its annual formnula. rate plan filing with the MPSC in March 2004 based on a 2003 test year. In April 2004, the MPSC approved a joint stipulation entered into between the Mississippi Public Utilities Staff and Entergy Mississippi that provides for no change in rates based or. a performance adjusted ROE mid-point of 10.77%, establishing an allowed regulatory earnings range of 9.3% to 12,2%.. .
- Grand Gulf Accelerated Recovery Tariff (GGART1 -
In September 1998, FERC approved the GGART for Entergy Mississippi's allocable portion of Grand Gulf; which was filed with FERC in August 1998. ;The GGART 'provided for the acceleration of Efitergy Mississippi's Grand Gulf purchased power obligation over the period October l '1998'through June 30, 2004. In May 2003, the MPSC authorized the cessation of the GGART effective July. 1 2003. Entergy Mississippi filed notice of the change with FERC, and the FERC approved the filing on JulYi30, 2003; Entergy Mississippi.accelerated a total of $168.4 million of Grand Gulf purchased power obligation costs under the GGART over the period October 1, 1998 through June 30, 2003. Filings with the City Council (Entergy New Orleans) FormulaRatePlans. ,,
*In May 2003, the City Council, approved a resolution, allowing for, a total increase of $30.2 million in electric and gas base rates, effective June 1, 2003. In April 2004, Entergy.New Orleans made filings with the City Council as required by the earnings review process prescribed by the Gas and Electric Formula Rate Plans approved by the City Council in 2003. The filings sought an increase in Entergy New Orleans' electric.revenues of
$1.2 million and an increase in Entergy New Orleans' gas revenues of $32,000. The Council Advisors and intervenors reviewed the filings, and filed their recommendations in July 2004. In August 2004, in accordance with the City, Council's requirements for the formula rate plans, Entergy New' Orleans made,a filing with the City Council reflecting the parties' concurrence that no clhangq in Entergy NewOrleans' electricor gas ratesi$ warranted., Later- in.August 2004, the City.-Councilapproved -an unopposed settlement among, EntergyNew Orleans,jthe Council Advisors, and 'the intervenors inf connection with the. Gas and Electric Formula Rate Plans. In accordance with the resolution approving the settlement agreement,. Entergy. New Orleans' gas and electric, base rates remain unchanged from levels set in May 2003.j The, resolution ordered Entergy New, Orleans. to defeg $3.9 million relating to voluntary severance plan costs allocated to its electric operations and $1,.0 million allocated to its gas opqeations 4 which amounts were accrued on, its books in 2903, and to recor4 on its books regulatory assets ii those amounts to be amortized over five years effective January 2004, Entergy New Orleansalso was orderedto defer $6.0 million of fossil plant maintenance expense incurred in 2003 and to record on its books a regulatory asset in that amount to be amortized over a five-year period effective January 2003. Entergy New Orleans will file its formula rate plan for the year ended December 31, 2004 by May 31, 2005 and also intends to file for an extension of the formula rate plan by September 1, 2005. If the formula rate plan is not extended by the City Council, the rate adjustments in effect based on the December 31, 2004 test year shall continue.' 7;l. ' T' " ' ' '
,In May! 2003, the City Council approved implementation ofa geheration performance-based rate calculation in the, electric fuel adjustment clause under. which Entergy New Orleans receives 10% of calculated fuel and purchased power cost savings in excess of $20 milliozin based. on a defined benchmark; subject to!a 13.25%
return on equity limitation for electric operations. is provided for in the electric formula rate plan. Entergy New Orleans bears- 10%/6 'of any "negative" fuel. and purchased power cost 'savingg. Id October 2004, Entergy New Orleans' annual evaluation report was submitted'for the period June 2003 through'May 2004. Savings associated with'the first year generation performance-based rateicalculatiol was $71 million of which Entergy New Orleans' sharewas$5A million. ,., . . I' 300
Domestic utility companies and System Energy Notes to Respective Financial Statements Fuel Adjustment Clause Litigation l In April 1999, a group of ratepayers filed a complaint against Entergy New Orleans, Entergy Corporation, Entergy Services, and Entergy Power in state court in Orleans Parish-purportedly on behalfof all Entergy. New Orleans ratepayers. The plaintiffs seek treble damages for alleged injuries arising from the defendants' alleged violations of Louisiana's antitrust laws in connection with certain costs passed on to ratepayers in Entergy New Orleans' fuel adjustment filings with the City Council. In particular, plaintiffs allege that; Entergy New Orleans improperly included certain -costs in the calculation of fuel charges and that Entergy New Orleans imprudently purchased high-cost fuel from other Entergy affiliates. Plaintiffs allege that Entergy New ,Orleans and the other defendant Entergy companies conspired to make these purchases to the detriment of Entergy New Orleans' ratepayers and to the benefit of Entergy's shareholders, in violation of Louisiana's antitrust laws. Plaintiffs also seek to recover interest and attorneys' fees. Entergy filed exceptions to the plaintiffs' allegations, asserting, among other things, that jurisdiction over these issues rests with the City Council and FERC. In March 2004, the plaintiffs supplemented and amended their petition. If necessary, at the appropriate time, Entergy will also raise its defenses to the antitrust claims. The suit in state court has been stayed by stipulation of the parties pending a decision by the City Council in the proceeding discussed in the next paragraph. Plaintiffs also filed this complaint with the City Council in order to initiate a review by the City Council of the plaintiffs' allegations and to force restitution to ratepayers of all costs they allege were improperly and imprudently included in the fuel adjustment filings. Testimony was filed on behalf of the plaintiffs in this proceeding asserting, among other things, that Entergy New Orleans and other defendants have engaged in fuel procurement and power purchasing practices and included costs in Entergy New Orleans' fuel adjustment that could have resulted in Entergy New Orleans customers being overcharged by more than $100 million over a period of years. Hearings were held in February and March 2002. In February 2004, the City Council approved a resolution that resulted in a refund to customers, of $11.3 million, including interest, during the months of June through September 2004. The resolution concludes, among other things, that the record does not support an allegation that Entergy New Orleans' actions or inactions, either alone or in concert with Entergy or any of its affiliates, constituted a misrepresentation or a suppression of the truth made in order to obtain an.unjust advantage of Entergy New Orleans, or to cause loss, inconvenience or harm to its ratepayers. Management believes that it has adequately provided for the liability associated with this proceeding. The plaintiffs have appealed the City Council resolution to the state court in Orleans Parish. Oral argument on the plaintiffs' appeal was conducted in February 2005. Purchased Power for Summer 2001, 2002 and 2003 (Entergy Gulf States and Entergy Louisiana) In March 2001, Entergy Louisiana and Entergy Gulf States filed applications with the LPSC for authorization to participate in contracts that would be executed by the Entergy System to meet the summer peak load requirements for the summer of 2001. In May 2001, the LPSC determined that 24% of Entergy Louisiana's and Entergy Gulf States' costs relating to summer 2001 purchases should be categorized as capacity charges. Subsequently, the LPSC raised certain prudence issues related to the 2001 purchases. The administrative law judge (ALJ) presiding over the case issued a Preliminary Recommendation regarding prudence issues primarily associated with the power uprates at the Waterford 3 and Grand Gulf nuclear units. In the event that such decision becomes final, additional calculations would be required to determine the potential refund obligation for the periods 2001, 2002 and 2003. The ALJ also concluded that Entergy should be permitted the opportunity to recover the expenses of the uprates through appropriate rate proceedings. In March 2002 and 2003, Entergy Louisiana and Entergy Gulf States filed an application with the LPSC for the approval of capacity and energy purchases for the summers of 2002 and 2003, respectively, similar to the applications filed for the summers of 2000 and 2001. The LPSC ordered that 14% of Entergy Louisiana's and Entergy Gulf States' costs relating to summer 2002 purchases be categorized as capacity charges, and that 11% of Entergy Louisiana's and Entergy Gulf States' costs relating to summer 2003 power purchases, the price of which was stated on the basis of $/MWh, be categorized as capacity charges. The LPSC did not allow the capacity charges to be set up as a regulatory asset, but authorized Entergy Louisiana and Entergy Gulf States to include these costs in any base rate case for their respective test years. Prudence issues relating to summer 2002 and 2003 purchases were resolved in subsequent settlements approved by the LPSC. In the event that the LPSC adopts the 301
Domestic utility companies and System Energy Notes to Respective Financial Statements ALls recommendation relating to potential uprates at nuclear facilities in the summer 2001 case, and such decision becomes final following an appeal or the expiration of appeal delays, these settlements reserve the LPSC's right to propose in a future case disallowances relating to the effect that such uprates would have had on the summer 2002 and summer 2005 firm energy contracts, while Entergy'Gulf States and Entergy Louisiana reserve their right to oppose any such proposal. No refunds were ordered in the summer 2002 settlement, although with respect to the capacity costs to be incurred pursuant to a particular purchased power contract, Entergy- Louisiana agreed in the settlement to forgo recovery of approximately $0.8 million in-2002, $1.3 million in 2003, and $1.0 million in 2004, and Entergy Gulf States agreed to forgo recovery of approximately $0.5 million in 2002, $0.9 million in 2003, and $0.1 million in 2004. All other purchases for the summers of 2002 and 2003 were found to be prudent. Issues relating to the reasonableness of the long-term planning process were moved from the summer 2002 case' into a separate sub-docket. In the summer 2003 settlement, the LPSC also reserved its right to investigate any alleged imprudence regarding the System's decision to spin off the ISES and Ritchie generating units to an unregulated affiliate, Entergy Power, Inc. Should the LPSC approve the proposed settlement discussed above, all issues arising out of the purchased power cases for the summers of 2001, 2002, and 2003 would be resolved. FERC Settlement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
- In November 1994, FERC approved an agreement settling a long-standing dispute involving income tax allocation procedures of System Energy. In accordance with the'agreernent, System Energy refunded a total of approximately $62 million, plus interest, to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans through June 2004. System Energy also reclassified from utility' plant to other deferred debits approximately $81 million of other Grand Gulf costs. Although'such costs were excluded from rate base, System Energy amortized and recovered these costs over a 10-year period. Interest on the $62 million refund and the loss of the return on the $81 million of other Grand Gulf costs reduced Entergy's and System Energy's net income by approximately $10 million annually.
302
Domestic utility companies and System Energy Notes to Respective Financial Statements NOTE 3. INCOME TAXES Income tax expenses for 2004, 2003, and 2002 consist of the following: Entergy Entergy Entergy Entergy Entergy System
; 2004 Arkansas Gulf States Louisiana Mississippi New Orleans Energy (In Thousands)
Current:
*Federal (a)(b) $14,490 ; $42,436 ; $2,439 ($23,568) ($19,259) $222,622 State (a)(b) 8,727 7,944 1,957 (1,221)' (3,655) 33,926 Total (a)(b) 23,217, 50,380 4,396 (24,789) (22,914) 256,548 , Deferred - net 70,674 63,615 80,207 63,234 40,226 (175,059)
Investment tax credit adjustments - net (4,827) (5,707) (5,128) (1,405) (444) (3,476) Recorded income tax expense $89,064 $108,288 $79,475 $37,040 $16,868 $78,013 Entergy, Entergy Entergy Entergy Entergy System 2003 Arkansas Gulf States Louisiana Mississippi New Orleans Energy (In Thousands) Current:
- Federal (a) $40,632 ($11,535) - ($745,724) ($2,969) ($7,655) $95,670 State (a) 16,306 (1,503) (16,243) 2,565 (1,871) 15,382 Total (a) 56,938 . (13,038) (761,967) (404) (9,526) 111,052 Deferred -- net 53,309 36,652 864,656 36,240 15,853 (31,731)
Investment tax credit adjustments - net (4,951) (12,078) (5,281) (1,405) (452) (3,476) Recorded income tax expense $105,296 $11,536 $97,408 $34,431 $5,875 $75,845
*Entergy Entergy Entergy Entergy Entergy System 2002 Arkansas Gulf States Louisiana Mississippi New Orleans Energy (In Thousands)
Current: Federal (a) $13,206 $66,227 $43,048 $21,817 ($7,103) $99,429 State (a) 3,243 11,345 1,867 3,969 (47) 14,994 Total (a) 16,449 77,572 44,915 25,786 (7,150) 114,423 Deferred - net 59,963 (4,210) 45,253 (6,529) 7,196 (34,770) Investment tax credit adjustments - net (5,008) (7,365) (5,403) (1,411) (468) (3,476) Recorded income tax expense $71,404 $65,997 $84,765 $17,846 ($422) $76,177 r. (a) Entergy Louisiana's actual cash taxes paid/(refunded) were $(70,650) in 2004, $35,128 in 2003, and
$(781,540) in 2002. Entergy Louisiana's mark-to-market tax accounting election significantly reduced taxes paid in 2002. In 2001, Entergy Louisiana changed its method of accounting for tax purposes related to its wholesale electric power contracts. The most significant of these is the contract to purchase power from the Vidalia project (the contract is discussed in Note 8 to the domestic utility companies and System Energy financial statements). The new tax accounting method has provided a cumulative cash flow benefit of approximately $790 million through 2004, which is expected to reverse in the years 2005 through 2031. The election did not reduce book income tax expense. The timing of the reversal of this benefit depends on several variables, including the price of power. Approximately half of the consolidated cash flow benefit of the election occurred in 2001 and the remainder occurred in 2002. In accordance with Entergy's intercompany tax allocation agreement, the cash flow benefit for Entergy Louisiana occurred in the fourth quarter of 2002.
303
Domestic utility companies and System Energy Notes to Respective Financial Statements (b) In 2003, the domestic utility companies and System Energy filed, with the IRS, a change in tax accounting method notification for their respective calculations of cost of goods sold. The adjustment implemented a simplified method of allocation of overhead to the production of electricity,'which is provided under the IRS capitalization regulations. The cumulative adjustment placing these companies on the new methodology resulted in a $1.171 billion deduction for Entergy Arkansas, a $674 million deduction for Entergy Gulf States, a $505 million deduction for Entergy Louisiana, a $145 milliori deduction for Entergy Mississippi, a
$31 million deduction for Entergy New Orleans, and a $430 million deduction for System- Energy on Entergy's 2003 income tax return. There was no cash benefit from the method change in 2003.. In 2004, Entergy Arkansas realized $173 million, Entergy Gulf States realized $69_million, Entergy Louisiana realized
$100 million, Entergy Mississippi realized $36 million, and System Energy realized $144 million in cash tax benefit from the method change. This tax accounting method change is an issue across the utility industry and will likely be challenged by the IRS on audit. Entergy believes that its contingency provision established in its financial statements will sufficiently cover its risk associated with this issue.
Total income taxes differ from the amounts computed by applying the statutory income tax rate to income before taxes. The reasons for the differences for the years 2004, 2003, and 2002 are: I1 7 Entergy Entergy Entergy Entergy Entergy System 2004 - Arkansas Gulf States Louisiana Mississippi New Orleans Energy ' _ I,, (In Thousands) Computed at statutory rate (35%) $80,946 $105,194 $72,440 ' $38,688 $15,729 $64,386 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 12,204 8,289 ' 6,411 3,845 1,158 ' 7?,665 Regulatory differences - utility plant items I 13,775 6,951 ., 10,052 : (1,482) 1,373 10,528 Amortization of investment f .: tax credits (4,827) (5,316)' (5,128) (1,405) '" (444) (3,476) Flow-through/permanent
.differences (9,127) (7,080) (3,576) ; (2,114) (878) \ . .(993)
Other -- net (3,907) 250- -- (724) (492) (70) - (97) Total income taxes $89,064 $108,288. $79,475 . $37,040 $16,868 !, $78,013
'1 ! .. ,- _-. .
Effective Income Tax Rate 38.5% 36.0% 38.4% 33.5% 37,5% ,, 42,4% E1 Entergy Entergy Entergy Entergy atergy System 2003 - Arkansas Gulf States Louisiana Mississippi INev v.Orleans Energ (In Thousands)
.1 ,, !
Computed 'at statutory rate'(35%) i
':$80,957 ;' ' $18,934 ' $85,247 $35,522 $4,807 )S $63,647 Increases (reductions) in tax * -resulting from:
State income taxes net of federal income tax effect 12,987. z. . . 473 ; 7,704 3,000 21,. r 7,765 Regulatory differences - utilitjr plant items 15,994 13,260 10,56X (930) 2,045 11,530 Amortization of investment tax credits (4,951) (8,797) (5,281) (i,404) (452):-~- (3,476) Flow-through/permanen1' X - i.1 I . : . A , , differences 1,090 (10,625) (2,012) (1,112) (625) (420) Benefit of Entergy Corp. expenses (1,145) (888) - - - (3,408) Other - net 364 (821) 1,122 (645) 79 207 Total income taxes $105,296 $11,536 $97,408 $34,431 $5,875 $75,845 Effective Income Tax Rate 45.5% 21.3% 40.0% 33.9% 42.8% 41.7% 304
Domestic utility companies and System Energy Notes to Respective Financial Statements Entergy Entergy Entergy Entergy Entergy System 2002 Arkansas Gulf States Louisiana Mississippi New Orleans Energy (In Thousands) Computed at statutory rate (35%) $72,467 $84,064 $80,317 $24,589 ($228) $62,836
- creases (reductions) in tax resulting from:
State income taxes net of federal income tax effect 8,784 6,401 6,065 2,069 551 7,049 Regulatory differences utility plant items 10,615 2,738 6,875 (3,032) 1,125 11,453 Amortization of investment tax credits (5,008) (6,528) (5,403) (1,411) (468) (3,476) Flow-through/permanent differences (10,687) (15,000) (1,878) (1,453) (538) (1,183) Benefit of Entergy Corp. expenses (3,428) (3,830) (180) (2,331) (434) (191) Other -- net (1,339) (1,848) (1,031) (585) (430) (311) Total income taxes $71,404 $65,997 $84,765 $17,846 ($422) $76,177 Effective Income Tax Rate 34.5% 27.5% 36.9% 25.4% 64.7% 42.4% Significant components of net deferred and long-term accrued tax liabilities as of December 31, 2004 and 2003 are as follows: Entergy Entergy Entergy Enitergy Entergy System 11 . 2004 Arkansas Gulf States Louisiana Missiissiopi New Orleans Enerev (In Thousands) Deferred and Long-term Accrued Tax Liabilities: Net regulatory assets/(liabilities) ($128,594) ($479,158) ($169,675) ($22,864) $44,867 ($223,391) Plant-related basis differences - net * (1,237,303) (1,388,391) (921,976) (389,558) (103,733) (471,026) Power purchase agreements - -- (971,676) - - - Rate refunds (39,163) . - (17,736) (49,124) (14,375) - Deferred fuel (2,899) (36,017) (1,286) (6,424) (3,873) - Other reserves 2,686 (33,916) 27,421 5,856 (323) (80,597) Other (80,980) .(20,781) (68,381) (16,516) (2,982) (11,851) Total (1,486,253) (1,958,263) (2,123,309) (478,630) (80,419) (786,865) beferred Tax Assets: Accumulated deferred investment tax credit 26,936 34,359 36,989 5,235 1,538 28,922 Sale and leaseback - - 82,410 - - 144,745 NOL carryforward 300,249 164,749 164,840 34,642 18,973 - Unbilled/Deferred revenues -. 17,001 - 10,193 - - Pension-related items - 14,499 13,039 - 10,656 6,737 Reserve for regulatory adjustments 131,112 - - - - Rate refund - 32,932 - - - 170,222 Customer deposits 40,880 33,425 17,479 15,777 91 ! Nuclear decommissioning 12,070 2,833 - Other 11,801 10,721 13,021 2,386 193 11,296 Total 391,936 438,798 330,611 68,233 31,451 361,922 Net deferred tax liability ($1,094,317) ($1,519,465) ($1,792,698) ($410,397) ($48,968) ($424,943) 305
Domestic utility companies and System Energy Notes to Respective Financial Statements Entergy Entergy . Entergy Entergy Entergy System 2003 Arkansas Gulf States Louisiana Mississippi New Orleans Energy (In Thousands) Deferred and Long-term Accrued Tax Liabilities: Net regulatory assets/(liabilities) ($157,147) ($478,254) ($195,074) ($34,738) . $38,834. ($246,519) Plant-related basis differences, net (798,641) (1,095,206) (806,955) (284,550) (74,041), (332,197) Power purchase agreements - (945,495) I - - Deferred fuel (4,154).. (45,762) - (40,091) (1I109) - Long term taxes accrued (26,611) (55,155) - (52,646) .(17,491) (57,239) Other (85,528) (26,012) (67,272) (21,806) , (1,728) (11,497) Total (1,072,081) (1,700,389) (2,014,796) (433,831) , (55,535) (647,452) Deferred Tax Assets: Accumulated deferred investment tax credit 28,836 36,192 38,962 5,773 1,709 30,251 Sale and leaseback - 83,539 - - 139,595 NOL carryforward' - 104,489 - . - Unbilled/Deferred revenues 11,959 - 7,357 - - Pension-related items 5,453 11,474 12,562 - 9,324 7,354 Reserve for regulatory adjustments 138,933 - Rate refund 2,351 23,184 789 379 3,977 170,222 Customer deposits 37,778 35,840 16,804 18,085 84 - Nuclear decommissioning - 13,171 2,833 Other 6,399 26,147 26,096 9,722 1,415 8,124 Total 93,988 283,729 286,074 41,316 16,509 355,546 Net deferred tax liability ($978,093) ($1,416,660) ($1,728,722) ($392,515) ($39,026) . ($291,906)
=.=
As of December 31, 2004, federal net operating loss carryforwards were $766.9 million for Entergy Arkansas, $447.5 million for Entergy Gulf States, $195.7 million for Entergy Louisiana, $40.9 million for Entergy Mississippi, and $54.9 million for Entergy New Orleans. If the federal net operating loss carryforwards are not utilized, they will expire in the year 2023. As of December 31, 2004, state net operating loss carryforwards were $1.9 billion for Entergy Louisiana,
$278 million for Entergy Gulf States, $11 million for Entergy New Orleans, and $638 million for Entergy Arkansas. If the state net operating loss carryforwards are not utilized, they will expire in the years 2016 through 2018 for Entergy Louisiana, 2018 for Entergy Gulf States, 2018 for Entergy New Orleans, and 2008 for Entergy Arkansas..
NOTE 4. LINES OF CREDIT AND SHORT-TERM BORROWINGS (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy) The short-term borrowings of Entergy's subsidiaries are limited to amounts authorized by the SEC. The current limits authorized are effective through November 30, 2007. In addition to borrowing from commercial banks, Entergy's subsidiaries are authorized under the SEC order to borrow from Entergy's money pool. The money pool -is an inter-company borrowing arrangement designed to reduce Entergy's subsidiaries' dependence on external short-term borrowings. Borrowings from the money pool and external borrowings combined may not exceed the SEC authorized limits. Under the SEC Order and without further SEC authorization, the domestic 'utility companies and System Energy cannot incur additional short-term indebtedness unless (a) the issuer and Entergy Corporation maintain a common equity ratio of at least 30% and (b) with the exception of money pool borrowings, the security to be issued (if rated) and all outstanding securities of the issuer (other than preferred stock of Entergy Gulf States and Entergy New Orleans), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. 306
Domestic utility companies and System Energy Notes to Respective Financial Statements The following are the SEC authorized limits-for short-term borrowings and the outstanding short-term borrowings from the money pool for the domestic utility companies and System Energy as of December 31, 2004: Authorized Borrowings (In Millions) Entergy Arkansas $235 Entergy Gulf States $340 $59.7 Entergy Louisiana $225 Entergy Mississippi $160 Entergy New Orleans $100 System Energy $140 Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans each have 364-day credit facilities available as follows: Amount of -Amount Drawn as of Company Expiration Date Facility Dec. 31, 2004 Entergy Arkansas April 2005 $85 million Entergy Louisiana April 2005 $15 million(a) Entergy Mississippi May 2005 $25 million Entergy New Orleans April 2005 $14 million(a) (a) The combined amount borrowed by Entergy Louisiana and Entergy New Orleans under these facilities at any one time cannot exceed $15 million. The 364-day credit facilities have variable interest rates and the average commitment fee.is 0.13%. The Entergy Arkansas facility requires it to maintain total shareholder's equity of at least 25% of its total assets. 307
Domestic utility companies and System Energy Notes to Respective Financial Statements NOTE 5. LONG - TERM DEBT (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy) Long-term debt as of December 31, 2004 and 2003 consisted of: 2004 2003 (In Thousands) Enterey Arkansas Mortgage Bonds: 6.125% Series due July 2005 $100,000 $100,000 5.4% Series due May 2018 150,000 150,000 5.0% Series due July 2018 115,000 115,000 7.0% Series due October 2023 175,000 175,000 6.7% Series due April 2032 100,000 100,000 6.0% Series due November 2032 100,000 100,000 5.9% Series due June 2033 100,000 100,000 6.38% Series due November 2034 60,000 Total mortgage bonds 900,000 840,000 Governmental Bonds (a): 6.3% Series due 2016, Pope County (h) 19,500 19,500 5.6% Series due 2017, Jefferson County 45,500 45,500 6.3% Series due 2018, Jefferson County (h) 9,200 9,200 6.3% Series due 2020, Pope County 120,000 120,000 6.25% Series due 2021, Independence County (h) 45,000 45,000 5.05% Series due 2028, Pope County (b) 47,000 47,000 Total governmental bonds 286,200
- 286,200 Other Long-Term Debt Long-term DOE Obligation (c) 156,332 154,409 8.5% Junior Subordinated Deferrable Interest Debentures 61,856 Unamortized Premium and Discount - Net (4,390) (4,708)
Other 621 621 Total Long-Term Debt 1,338,763 1,338,378 Less Amount Due Within One Year 147,000 Long-Term Debt Excluding Amount Due Within One Year $1,191,763 $1,338,378 Fair Value of Long-Term Debt (d) $1,224,942 $1,235,278 308
Domestic utility companies and System Energy Notes to Respective Financial Statements 2004 2003 (In Thousands) Entergv Gulf States Mortgage Bonds: 8.25% Series due April 2004 $292,000 6.77% Series due August 2005 1 98,000 98,000 Libor + 0.9% Series due June 2007 275,000 5.2% Series due December 2007 200,000 3.6% Series due June 2008 325,000 325,000 Libor + 0.4% Series due December 2009 225,000 4.875% Series due November 2011 200,000 6.0% Series due December 2012 140,000 . 140,000 5.6% Series due December 2014 50,000 5.25% Series due August 2015 200,000 200,000 6.2% Series due July 2033 240,000 240,000 Total mortgage bonds 1,478,000 1,770,000 Governmental Bonds (a): 5.45% Series due 2010, Calcasieu Parish -22,095 22,095 6.75% Series due 2012, Calcasieu Parish 48,285 48,285 6.7% Series due 2013, Pointe Coupee Parish 17,450 17,450 5.7% Series due 2014, Iberville Parish 21,600 21,600 7.7% Series due 2014, West Feliciana Parish 94,000 94,000 5.8% Series due 2015, West Feliciana Parish 28,400 28,400 7.0% Series due 2015, West Feliciana Parish 39,000 39,000 7.5% Series due 2015, West Feliciana Parish 41,600 41,600 9.0% Series due 2015, West Feliciana Parish 45,000 45,000 5.8% Series due 2016, West Feliciana Parish 20,000 . 20,000 5.65% Series due 2028, West Feliciana Parish (e) 62,000 6.6% Series due 2028, West Feliciana Parish 40,000 40,000 Total governmental bonds 417,430 479,430 Other Long-Term Debt 8.75% Junior Subordinated Deferrable Interest Debentures 87,629 87,629 Unamortized Premium and Discount - Net (2,397) (2,596) Other 8,816 9,150 Total Long-Term Debt 1,989,478 2,343,613 Less Amount Due Within One Year 98,000 354,000 Long-Term Debt Excluding Amount Due Within One Year $1,891,478 $1,989,613 Fair Value of Long-Term Debt (d) $1,999,249 $2,438,997 309
Domestic utility companies and System Energy Notes to' Respective Financial Statements 2004 2003 (In Thousands) Entergv Louisiana Mortgage Bonds: 6.5% Series due March 2008 $115,000 5.09% Series due November 2014 115,000 5.5% Series due April 2019 100,000 7.6% Series due April 2032 ' 150,000 150,000 6.4% Series due October 2034 70,000' Total mortgage bonds 435,000 265,000 Governmental Bonds (a): 7.5% Series due 2021, St. Charles Parish (h) 50,000 50,000 7.0% Series due 2022, St. Charles Parish (h) 24,000 24,000 7.05% Series due 2022, St. Charles Parish (h) 20,000 20,000 5.95% Series due 2023, St. Charles Parish (h) 25,000 25,000 6.2% Series due 2023, St. Charles Parish (h) 33,000 33,000, 6.875% Series due 2024, St. Charles Parish (h) 20,400 20,400 6.375% Series due 2025, St. Charles Parish 16,770 16,770 5.35% Series due 2029, St. Charles Parish (i) Auction Rate due 2030, St. Charles Parish (h) ' 60,0004 60,000 4.9% Series due 2030, St. Charles Parish (f) (g) 55,000 55,000 Total governmental bonds 304,170 304,170 Other Long-Term Debt: Waterford 3 Lease Obligation 7.45% (Note 9) 247,725 262,534 9.0% Junior Subordinated Deferrable Interest Debentures - 72,165 Unamortized Premium and Discount - Net (1,200) (1,373) Total Long-Term Debt 985,695 902,496 Less Amount Due Within One Year 55,000 14,809 Long-Term Debt Excluding Amount Due Within One Year $930,695 $887,687 Fair Value of Long-Term Debt (d) $762,782 $668,700
., . I i 3 lb
Domestic utility companies and System Energy Notes to Respective Financial Statements 2004 2003 (In Thousands) Enteray Mississippi Mortgage Bonds: 6.2% Series due May 2004 I - $75,000 6.45% Series due April 2008 80,000 4.35% Series due April 2008 ' I I 100,000 100,000 4.65% Series due May 2011 80,000 5.15% Series due February 2013 ' 100,000 I 100,000 4.95% Series due June 2018 X- i -95,000 95,000 7.7% Series due July 2023 60,000 6.0% Series due November 2032 75,000 75,000 7.25% Series due December 2032 100,000 I 100,000 6.25% Series due April 2034 100,000 Total mortgage bonds 650,000 685,000 I I . Governmental Bonds (a): 7.0% Series due 2022, Warren County 8,095 7.0% Series due 2022, Washington County 7,935 4.60% Series due 2022, Mississippi Business Finance Corp. . .. 16,030 Auction Rate due 2022, Independence County (h) 30,000 30,000 Total governmental bonds 46,030 46,030 Other Long-Term Debt: Unamortized Premium and Discount - Net (957) (1,074) Total Long-Term Debt 695,073 729,956 Less Amount Due Within One Year 75,000 Long-Term Debt Excluding Amount Due Within One Year $695,073 . $654,956 Fair Value of Long-Term Debt (d) $716,201 $771,402 1- . I
; I
.1 .
j . , :~-, 311
Domestic utility companies and System Energy Notes to Respective Financial Statements 2004 2003 (In Thousands) Enteray New Orleans Mortgage Bonds: 8.125% Series due July 2005 $30,000 . $30,000 3.875% Series due August 2008
- 30,000 30,000
.5,25% Series due August 2013 70,000 70,000 6.75% Series due October 2017 25,000 25,000 8.0% Series due March 2023
- 45,000 7.55% Series due September 2023 30,000 5.6% Series due September 2024 I 35,000 5.65% Series due September 2029 40,000 Total mortgage bonds 230,000 230,000
. I Other Long-Term Debt:
Unamortized Premium and Discount - Net (98) (783) Total Long-Term Debt 229,902 229,217 Less Amount Due Within One Year 30,000 Long-Term Debt Excluding Amount Due Within One Year $199,902 $229,217 Fair Value of Long-Term Debt (d) $231,957 $239,816 2004 2003-(In Thousands) System Enermv Mortgage Bonds: 4.875% Series due October 2007 $70,000 $70,000" Total mortgage bonds 70,000- 70,000' Governmental Bonds (a): 5.875% Series due 2022, Mississippi Business Finance Corp. 216,000 216,000 5.9% Series due 2022, Mississippi Business Finance Corp. 102,975 102,975 7.3% Series due 2025, Claiborne County - 7,625 6.2% Series due 2026, Claiborne County 90,000 90,000 Total governmental bonds 408,975 416,600 Other Long-Term Debt: Grand Gulf Lease Obligation 5.0 1%(Note 9) 397,119 403,468 Unamortized Premium and Discount - Net (1,235) (1,319) Total Long-Term Debt 874,859 888,749 Less Amount Due Within One Year 25,266 6,348 Long-Term Debt Excluding Amount Due Within One Year $849,593 $882,401 Fair Value of Long-Term Debt (d) $470,187 $489,436 312
Domestic utility companies and System Energy Notes to Respective Financial Statements (a) Consists of pollution control revenue bonds and environmental revenue bonds. (b) The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on September 1, 2005 and can thenibe remarketed. (c) Pursuant to the Nuclear Waste Policy Act of 1982, Entergy's nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt. (d) The fair value excludes lease obligations and long-term DOE obligations, and includes debt due within one year. It is determined using bid prices reported by dealer markets and by nationally recognized investment banking firms., (e) The bonds had a mandatory tender date of September 1, 2004. Entergy Gulf States purchased the bonds from the holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time. (f) On June 1, 2002, Entergy Louisiana remarketed $55 million St. Charles Parish Pollution Control Revenue Refunding Bonds due 2030, resetting the interest rate to 4.9% through May 2005. (g) The bonds are subject to mandatory tender for purchase from the holders at 100% of the principal amount outstanding on June 1, 2005 and can then be remarketed. (h) The bonds are secured by a series of collateral first mortgage bonds. (i) The bonds in the principal amount of $110.95 million had a mandatory tender date of October 1, 2003. Entergy Louisiana purchased the bonds from the holders, pursuant to the mandatory tender provision, and has not remarketed the bonds at this time. The annual long-term debt maturities (excluding lease obligations) for debt outstanding as of December 31, 2004, for the next five years are as follows: Entergy Entergy Entergy Entergy Entergy System Arkansas Gulf States Louisiana' Mississippi New Orleans Energy (In Thousands) 2005 $147,000 $98,000 $55,000 - $30,000 2006 2007 - - - - - $70,000 2008 $621 $325,000 - $100,000 $30,000 2009 - $225,000 - - - The long-term securities issuances of Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and System Energy are limited to amounts authorized by the SEC. Under their SEC orders and without further SEC authorization, Entergy Gulf States, Entergy Louisiana, and Entergy Mississippi cannot incur additional indebtedness or issue other securities unless (a) the issuer and Entergy Corporation maintain a common equity ratio of at least 30% and (b) the security to be issued (if rated) and all its outstanding securities of the issuer (other than preferred stock of Entergy Gulf States), as well as all outstanding securities of Entergy Corporation, that are rated, are rated investment grade. Junior Subordinated Deferrable Interest Debentures and Implementation of FIN 46 (Entergy Arkansas, Entergy Gulf States, and Entergy Louisiana) Entergy implemented FASB Interpretation No. 46, "Consolidation of Variable Interest Entities" effective December 31, 2003. FIN 46 requires existing unconsolidated variable interest entities to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among their investors. Variable interest entities (VIEs), generally, are entities that do not have sufficient equity to permit the entity to finance its operations without additional financial support from its equity interest holders and/or the group of equity interest holders are collectively not able to exercise control over the entity. The primary beneficiary is the party that absorbs a majority of the entity's expected losses, receives a majority of its expected residual returns, or both as a result of holding the 313
Domestic utility companies and System Energy Notes to Respective Financial Statements variable interest. A company may have an interest in a VIE through ownership or other contractual rights or obligations. Entergy Louisiana Capital I, Entergy Arkansas Capital 1, and Entergy Gulf States Capital I (Trusts) were established as financing subsidiaries of Entergy Louisiana, Entergy Arkansas, and Entergy Gulf States, respectively, (the parent company or companies, collectively) for the purposes of issuing common and preferred securities. The Trusts issued Cumulative Quarterly Income Preferred Securities (Preferred Securities) to the public and issued common securities to their parent companies. Proceeds from such issues were used to purchase junior subordinated deferrable interest debentures (Debentures) from the parent company. The Debentures held by each Trust are its only assets. Each Trust uses interest payments received on the Debentures owned by it to make cash distributions on the Preferred Securities and common securities. The parent companies fully and unconditionally guaranteed payment of distributions on the Preferred Securities issued by the respective Trusts. Prior to the application of FIN 46, each parent company consolidated its interest in its Trust. Because each parent company's share of expected losses of its Trust is limited to its investment in its Trust, the parent companies are not considered the primary beneficiaries and therefore de-consolidated their interest in the Trusts upon application of FIN 46 with no significant impacts to the financial statements. The parent companies' investment in the Trusts and the Debentures issued by each parent company are included in Other Property and Investments and Long-Term Debt, respectively. Tax Exempt Bond Audit (Entergy Louisiana) In November 2000, the Internal Revenue Service (IRS) began an audit of certain Tax Exempt Bonds issued by St. Charles Parish, State of Louisiana (the Issuer). The Bonds were issued to finance previously unfinanced acquisition costs expended by Entergy Louisiana to acquire certain radioactive solid waste disposal facilities (the Facilities) at the Waterford Steam Electric Generating Station. In January 2002, the IRS issued a preliminary adverse determination that the Bonds were not tax exempt. The stated basis for this determination was that radioactive waste did not constitute "solid waste" within the provisions of the Internal Revenue Code and therefore the Facilities did not qualify as solid waste disposal facilities. In a "technical advice memorandum," issued in October 2004 to the parish, the IRS National Office, concurred with the preliminary adverse determination. The Issuer and Entergy Louisiana intend to continue to vigorously contest this matter. 314
Domestic utility companies and System Energy Notes to Respective Financial Statements NOTE 6. PREFERRED STOCK (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans) The number of shares authorized and outstanding and dollar value of preferred stock for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans as of December 31, 2004 and 2003 are presented below. Only the two Entergy Gulf States series "with sinking fund" contain mandatory redemption requirements. All other series of the U.S. Utility are redeemable at Entergy's option at the call prices presented. Dividends paid on all of Entergy's preferred stock series are eligible for the dividends received deduction. The dividends received deduction is limited by Internal Revenue Code section 244 for the following preferred stock series: Entergy Arkansas 4.72%, Entergy Gulf States 4.40%, Entergy Louisiana 4.96%, Entergy Mississippi 4.56%, and Entergy New Orleans 4.75%. Shares Call Price Per Authorized Dollars Share as of and Outstanding (In Thousands) December 31, 2004 2003 2004 2003 2004 Enterev Arkansas Preferred Stock Without sinking fund: Cumulative, $100 par value: 4.32% Series 70,000 70,000 $7,000 $7,000 $103.65 4.72% Series 93,500 93,500 9,350 9,350 $107.00 4.56% Series 75,000 75,000 7,500 7,500 $102.83 4.56% 1965 Series 75,000 75,000 7,500 7,500 $102.50 6.08% Series L 100,000 100,000 10,000 10,000 $102.83 7.32% Series 100,000 100,000 10,000 10,000 $103.17 7.80% Series 150,000 150,000 15,000 15,000 $103.25 7.40% Series 200,000 200,000 20,000 20,000 $102.80 7.88% Series 150,000 150,000 15,000 15,000 $103.00 Cumulative, $0.01 par value:
$1.96 Series (a) 600,000 600,000 15,000 15,000 $25.00 Total without sinking fund 1,613,500 1,613,500 $116,350 $116,350 315
Domestic utility companies and System Energy Notes to Respective Financial Statements Shares . I, Call Price Per Authorized Dollars Share as of and Outstanding ; ; (In Thousands) December 31, 2004 2003 2004 2003 2004 Enterav Gulf States Preferred Stock Preferred Stock Authorized 6,000,000 shares,
$100 par value, cumulative Without sinking fund; 4.40% Series 51,173 51,173 $5,117 $5,117 $108.00 4.50% Series 5,830 5,830 583 i 583 $105.00 4.40% 1949 Series 1,655 1,655 166 166 $103.00 4.20% Series 9,745 9,745 975 975 $102.82 4.44% Series 14,804 14,804 1,480 1,480 $103.75 5.00% Series 10,993 10,993 1,099 1,099 $104.25 5.08% Series 26,845 26,845 2,685 2,685 $104.63 4.52% Series 10,564 - 10,564 1,056 1,056 $103.57 6.08% Series 32,829 32,829 3,283 3,283 $103.34 7.56% Series 308,830 308,830 30,883 30,883 $101.80 I ! I I Total without sinking fimd 473,268 473,268 $47,327 $47,327 With sinking fund:
Adjustable Rate-A, 7.0% (b) 84,000 96,020 $8,400 $9,602 $100.00 Adjustable Rate-B, 7.0% (b) 90,000, 112,500 9,000 11,250 $100.00 Total with sinking fund 174,000 208,520 $17,400 $20,852 Fair Value of Preferred Stock with Sinking Fund (c) $15,286 $15,354 ;
'I.
I ( Cia l i Pc. Shares !: :-Call Price Per Authorized Dollars Share as of and Outstanding (In Thousands) December 31, 2004 2003 2004 2003 2004 Enterev Louisiana Preferred Stock Without sinking fund: Cumulative, $100 par value: 4.96% Series 60,000 60,000 $6,000 $6,000 $104.25 4.16% Series 70,000 70,000 7,000 7,000 $104.21 4.44% Series 70,000 70,000 7,000 7,000 $104.06 5.16% Series 75,000 75,000 7,500 7,500 $104.18 5.40% Series 80,000 80,000 8,000 8,000 $103.00 6.44% Series 80,000 80,000 8,000 8,000 $102.92 7.84% Series 100,000 100,000 10,000 10,000 $103.78 7.36% Series 100,000 100,000 10,000 10,000 $103.36 Cumulative, $25 par value: 8.00% Series 1,480,000 1,480,000 37,000 37,000 $25.00 Total without sinking fund 2,115,000 2,115,000 $100,500 $100,500 316
Domestic utility companies and System Energy Notes to Respective Financial Statements Shares Call Price Per Authorized - Dollars' Share as of and Outstanding (In Thousands) December 31, 2004 2003 i 2004 : 2003 2004 Entereg Mississippi Preferred Stock Without sinking fund: Cumulative, $100 par value: 4.36% Series 59,920 59,920 $5,992 $5,992 $103.86 4.56% Series 43,887 43,887 4,389 4,389 $107.00 4.92% Series 100,000 100,000 10,000- 10,000 $102.88 7.44% Series 100,000 100,000 10,000 .10,000 $102.81 8.36% Series 200,000 200,000 20,000 . 20,000 $100.00 Total without sinking fund 503,807 503,807 $50,381 $50,381
-Shares Call Price Per
-Authorized - Dollars Share as of and Outstanding (In Thousands) December 31, 2004 2003 2004 2003 - 2004 Enter&i New Orleans Preferred Stock Without sinking fund:
Cumulative, $100 par value: 4.75% Series 77,798 77,798 $7,780 $7,780 $105.00 4.36% Series 60,000 60,000 6,000 6,000 $104.58 5.56% Series ' 60,000 60,000 6,000 6,000 $102.59 Total without sinking fund 197,798 197,798 $19,780 $19,780 (a) The total dollar value represents the liquidation value of $25 per share. (b) Represents weighted-average annualized rates for 2004 and 2003. (c) Fair values were determined using bid prices reported by dealer markets and'by nationally recognized investment banking firms. There is an additional disclosure of fair value of financial instruments in Note 11 to the domestic utility companies and System Energy financial statements. Entergy Gulf States' preferred stock with sinking fund retirements were 34,500 shares in 2004 and 2003, and 18,579 shares in 2002. Entergy Gulf States has annual sinking fund requirements of $3.45 million through 2009 for its preferred stock outstanding. Entergy Gulf States has the annual non-cumulative option to redeem, at par, additional amounts of certain Series of its outstanding preferred stock. NOTE 7. COMMON EQUITY (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans Dividend 'Restrictions ' Provisions within the 'Articles of Incorporation or pertinent 1irxdntures and various other agreements relating to the long-term debt and preferred stock of the domestic utility, companies and System Energy restrict the payment of cash dividends or other distributions on their common and preferred stock. Additionally, PUHCA prohibits Entergy Corporation's subsidiaries from making loans or advances to. Entergy Corporation. As of December 31, 2004, Entergy Arkansas and Entergy Mississippi had restricted-retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. 317
Domestic utility companies and System Energy Notes to Respective Financial Statements NOTE 8. COMMITMENTS AND CONTINGENCIES The domestic utility companies and System Energy are involved in a number of legal, tax, and regulatory proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of their business. While management is unable to predict the outcome of such proceedings, it is not expected that the ultimate resolution of these matters will have a material adverse effect on Entergy Arkansas', Entergy Gulf States', Entergy Louisiana's, Entergy Mississippi's, Entergy New Orleans', or System Energy's results of operations; cash flows, or financial condition. Vidalia Purchased Power Agreement (Entergy Louisiana) Entergy Louisiana has an agreement extending through the year 2031 to purchase energy generated by a hydroelectric facility known as the Vidalia project. Entergy Louisiana made payments under the contract of approximately $147.7 million in 2004, $112.6 million in 2003, and $104.2 imiillion in 2002. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $125.3 million in 2005, and a total of $3.5 billion for the years 2006 through 2031. Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause: In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $11 million each year oforup -to ten years, beginning in October 2002. The provisions of the settlement -also provide that the LPSC shall not recognize or use Entergy Louisiana's use of the cash benefits from the tax treatment in setting any of Entergy Louisiana's rates. Therefore, to the extent Entergy Louisiana's use of the proceeds would ordinarily have reduced its rate base, no change in rate base shall be reflected for ratemaking purposes. System Fuels (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy) - -. The domestic utility companies that are owners of System Fuels have made loans to System Fuels to finance its fuel procurement, delivery, and storige activities. The following loans outstanding to System Fuels as of December 31, 2004 mature in 2008: - -
-, - Ownership ' Loan Outstabiding Owner - Percentage ., - at December 31, 2004: -
-,Entergy Arkansas - - -- 35% ; . $11.0 million -
Entergy Louisiana 33% $14.2 million Entergy Mississippi 19% $5.5 million
- Entergy New Orleans . 13%. . $3.3 million Nuclear Insurance (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
Third Party Liability Insurance , ;- - . . - - The Price-Anderson Act provides insurance for the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Originally passed by Congress in 1957 and most recently amended in 1988, the Price-Anderson Act requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident. This protection must consist of two levels: 1: The primary level is private insurance underwritten by American Nuclear Insurers and provides liability
-'insurance coverage of-$300 million.) If this amunt iis not sufficient to cover claims arising from the accident, the secondleVel, Secondary Financial Protection, applies. An industry-wide aggregate limitation of $300 million ekists for domestically-sponsored 'terrorist acts. There is no limitation for foreign-sponsored terrorist acts. ; i ' -; ,
- 2. Within the Secondary Financial Protection level, each nuclear plant must pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, up to a maximum of $100.6 318
Domestic utility companies and System Energy Notes to Respective Financial Statements million per reactor per incident. This consists of a $95.8 million maximum retrospective premium plus a five percent surcharge that may be applied, if needed, at a rate that is presently set at $10 million per year per nuclear power reactor. There are no domestically- or foreign-sponsored terrorism limitations. Currently, 104 nuclear reactors are participating in the Secondary Financial Protection program - 103 operating reactors and one closed reactor that still stores used nuclear fuel on site. The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactors provides over $10 billion in insurance coverage to compensate the public in the event of a nuclear power reactor accident. Entergy Arkansas has two licensed reactors and Entergy Gulf States, Entergy Louisiana, and System Energy each have one licensed reactor (10% of Grand Gulf is owned by a non-affiliated company (SMEPA), which would share on a pro-rata basis in any retrospective premium assessment under the Price-Anderson Act). An additional but temporary contingent liability exists for all nuclear power reactor owners because of a previous Nuclear Worker Tort (long-term bodily injury caused by exposure to nuclear radiation while employed at a nuclear power plant) insurance program that was in place from 1988 to 1998. The maximum premium assessment exposure to each reactor is $3 million and will only be applied if such claims exceed the program's accumulated reserve funds. This contingent premium assessment feature will expire with the Nuclear Worker Tort program's expiration, which is scheduled for 2008. Property Insurance Entergy's nuclear owner/licensee subsidiaries are members of certain mutual insurance companies that provide property damage coverage, including decontamination and premature decommissioning expense, to the members' nuclear generating plants. These programs are underwritten by Nuclear Electric Insurance Limited (NEIL). As of December 31, 2004, the domestic utility companies and System Energy were insured against such losses per the following structures: ANO I and 2, Grand Gulf. River Bend, and Waterford 3
- Primary Layer (per plant) - $500 million per occurrence
- Excess Layer (per plant) - $100 million per occurrence
- Blanket Layer (shared among all plants) - $ 1.0 billion per occurrence
- Total limit - $1.6 billion per occurrence
- Deductibles:
* $5.0 million per occurrence - Turbine/generator-damage
* $5.0 million per occurrence - Other than turbine/generator damage Note: ANO 1 and 2 share in the Primary Layer with one policy in common.
In addition, Waterford 3 and Grand Gulf are also covered under NEIL's Accidental Outage Coverage program. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL property damage loss, subject to a deductible. The foll6wing'summarizes this coverage as of December 31, 2003: Waterford 3
* $2.95 million weekly indemnity
* $413 million maximum indemnity
- Deductible: 26 week waiting period Grand Gulf
* $100,000 weekly indemnity
* $14 million maximum indemnity
- Deductible: 26 week waiting period 319
Domestic utility companies and System Energy Notes to Respective Financial Statements Under the property damage and accidental outage insurance programs, Entergy's nuclear plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. As of December 31, 2004, the maximum amount of such possible assessments per occurrence were $15.1 million for Entergy Arkansas, $11.1 million for Entergy Gulf States, $13.0 million for Entergy Louisiana, $0.06 million for Entergy Mississippi, $0.06 million for Entergy New Orleans, and $11.5 million for System Energy. Entergy maintains property insurance for its nuclear units in excess of the NRC's minimum requirement of $1.06 billion per site for nuclear power plant licensees. NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors. In the event that one or more acts of domestically-sponsored terrorism causes property damage under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such nuclear insurance policies shall be an aggregate of $3.24 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses. There is no aggregate limit involving one or more acts of foreign-sponsored terrorism. Nuclear Decommissionin! and Other Retirement Costs (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, System Energy) SFAS 143, "Accounting for Asset Retirement Obligations," which was implemented effective January 1, 2003, requires the recording of liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets. These liabilities are recorded at their fair values (which is the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense,'to reflect the time value of money for this present value obligation. The amounts added to the carrying amounts of the long-lived assets are depreciated over the useful lives of the assets. The net effect of implementing this standard for the rate-regulated business of the domestic utility companies and System Energy was recorded as a regulatory asset, with no resulting impact on Entergy's net income. Entergy recorded these regulatory assets. because existing rate mechanisms in each jurisdiction are based on the principle that Entergy will recover all ultimate costs of decommissioning from customers. As a result of this treatment, SFAS 143 is expected to be earnings neutral to the rate-regulated business of the domestic utility companies and System Energy.,, Upon implementation of SFAS 143 in 2003, assets and liabilities increased $1.1 billion for the U.S. Utility segment as a result of recording the asset retirement obligations at their fair values of $1.1 billion as determined under SFAS 143, increasing utility plant by $287 million, reducing accumulated depreciation by $361 million and recording the related regulatory assets of $422 million. The implementation of SFAS 143 for the portion of River Bend not subject to cost-based ratemaking decreased earnings in the first quarter of 2003 by $21 million net-of-tax as a result of a cumulative effect of accounting change. In accordance with ratemaking treatment and as required by SFAS 71, the depreciation provisions for the domestic utility companies and System Energy include a component for removal costs that are not asset retirement obligations under SFAS 143. In accordance with regulatory accounting principles, the domestic utility companies and System Energy have recorded regulatory assets (liabilities) in the following amounts to reflect their estimates of the difference between estimated incurred removal costs and estimated removal costs recovered in rates previously recorded as a component of accumulated depreciation: 320
Domestic utility companies and System Energy Notes to Respective Financial Statements December 31, 2004 2003 (In Millions) Entergy Arkansas $34.9 $26.6 Entergy Gulf States $0.9 $4.2 Entergy Louisiana ($34.6) ($26.8) Entergy Mississippi $32.7 $24.4 Entergy New Orleans $1.3 $2.1 System Energy $17.1 $15.1 The cumulative decommissioning liabilities and expenses recorded in 2004 by Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy were as follows: Change in Liabilities as of Cash Flow Liabilities as of December 31, 2003 Accretion Estimate December 31, 2004 (In Thousands) ANO l and ANO 2 $567.5 $32.9 ($107.7) $492.7 River Bend $298.8 $19.7 ($166.4) $152.1 Waterford 3 $325.3 $22.0 - $347.3 Grand Gulf $312.5 $23.4 - $335.9 Entergy periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. In the first quarter of 2004, Entergy Arkansas recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for ANO 1 and 2 as a result of revised decommissioning costs and changes in assumptions regarding the timing of when the decommissioning of the plants will begin. The revised estimate resulted in a $107.7 million reduction in its decommissioning liability, along with a $19.5 million reduction in utility plant and an $88.2 million reduction in the related regulatory asset. In the third quarter of 2004, Entergy Gulf States recorded a revision to its estimated decommissioning cost liability in accordance with a new decommissioning cost study for River Bend that reflected an expected life extension for the plant. The revised estimate resulted in a $166.4 million reduction in decommissioning liability, along with a $31.3 million reduction in utility plant, a $49.6 million reduction in non-utility property, a $40.1 million reduction in the related regulatory asset, and a regulatory liability of $17.7 million. For the portion of River Bend not subject to cost-based ratemaking, the revised estimate resulted in the elimination of the asset retirement cost that had been recorded at the time of adoption of SFAS 143 with the remainder recorded as miscellaneous other income of $27.7 million. If SFAS 143 had been applied by Entergy Gulf States for the portion of-River Bend not subject to cost-based ratemaking during prior periods, the following impacts would have resulted:
,Year Ended December 31, 2002 Entergy Gulf States Earnings applicable to common stock - as reported $169,190 Pro forma effect of SFAS 143 ($2,227)
Earnings applicable to common stock - pro forma $166,963 321
Domestic utility companies and System'Energ-Notes to Respective Financial Statements Entergy maintains decommissioning trust funds that are committed to meeting the costs of decommissioning the nuclear poWer plants. The fair values of the decommissioning trust funds and asset retirement obligation-related regulatory assets ofEntergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy as of December 31, 2004 are as follows:
.(. f Decommissioning Regulatory
* >,i Trust Fair Values Assets,
*o W ,}r'(itz (In Millions)__,,e:<'-J ANO I & ANO 2 $383.8 $i4l.2 1'm River Bend $291.0 -
W.,aterford 3 J , f $172.1 , $141.6 . Grand Gulf $205.1 , . $97.3 ; ,., The Energy Policy Act of 1992 contains a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning (D&D) of the DOE's past vlraniv~m enrichment operations. Annual assessments in 2004 were $4.4 million for Entergy Arkansas, $1.1 million for Entergy Gulf States, $1.6 million for Entergy Louisiana, hand $1.8 miLfor' SysfemiEii 2004.'The~Eiey P61lic' AXct calls for cessation of annual D&D assessments not later than October 24, 2007. At December 31, 2004, two years of assessments were remaining. D&D fees are included in other current liabilities and othermpon-current liabilities and, as of December 31, 2004, recorded liabilities were $8.8 million for Entergy Arkansas, $1.9 million for Entergy Gulf States, $3.3 million for Entergy Louisiana, and $3.3 million for System Energy. Regulatory assets in the financial statements offset these liabilities, with the exception of Entergy Gulf States' 30% non-regulated portion. These assessments are recovered through rates in the same manner as fuel costs. Income Taxes . r. .e
,t:- - ; Itig'.rz-) e - i Ls itt, ! VgOJ .
Entergy is currently under audit by the IRS with respect to tax returns for tax periods subsequent to 1995 and through_2001, and is subject tq audit, by the ,IRS, and other taxing autho'rities for subsequent tax periods. The amount and timing of any tax assessments resu1ting from these Audits are uncertain, and could haye a material effect on Entergy's finanpcial, position and results of operations.,,nitergy btelieves that the contingency provisions established in its financial statements will sufficiently cover the risk associated with tax matters. Cer~,ain material audit matters austo which managemnc tbelieves there, is a reasoinable pqssibility of a. future tax assessment are discussed below. See Note 3 to the domestic utility companies and System Energy financial statements for additional discussion of income taxes. , -. <,, a ; 9 : ;, ; } d DepreciableProperty Lives (. i.- ":..ji!;>r o tU) flat T'i-During the years 1997 through 2004, Entergy subsidiaries, Entergy Services, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, .and System Energy Resources reflected changes in tax depreciation, methods with respect to certain types of deprepiable property (e.g. street lighting, billing meters, and various generation plant equipment). As of December 31, 2004, the cumulative effect of these changes results in additional depreciation deductions generating a cash flow benefit of $45 million for Entergy Arkansas, $38. million for Entergy.Gqlf States, $32 million forEntergy Louisiana, $19 million for Entergy Mississippi, $6 million for Entergy New Qrleans, and $12 million for System Energy. As o.f December 31, 2004, the related IRS interest exposure if the deduction is ultimately disallowed is $13 million for Entergy Arkansas, $11 million for Entergy Gulf States, $9 million for Entergy Louisiana, $6 million for Entergy Mississippi, $2 million for Entergy New Orleans, -and ii' million for System Energy. This benefit reverses over time and will also fluctuate with each year's addition to those types of assets. Due to the temporary nature of the tax benefit, the potential interest charge represents the total net exposure of the domestic utility companies and, System Energy. For the years under audit, 1996-2001, the IAS clalleged Egys classification' of these assets and proposed adjustments to the depreciation deductions taken. Entergy disagr es with the position of the IRS and has 322
Domestic utility companies and System Energy Notes to Respective Financial Statements protested the disallowance of these deductions to the Office of IRS Appeals. Entergy expects to receive a Notice of Deficiency in 2005 for this item, and plans to vigorously contest this matter. Entergy believes that the contingency provision established in its financial statements sufficiently covers the'tisk associated with this item.. Mark to Market of Certain Power Contracts '. ' , C}i.i 4 : In 2001, Entergy Louisiana changed its method of accounting for tax purpo'ses related to its wholesale electric power contracts. The most significant of these is the contract to purchase power from the Vidalia hydroelectric project>t -The'riew tax' accounting 'method has provided a cumulative cash flow benefit of approximately $790 million 'as of December 31, 2004. The related IRS, interest exposure is $93 million at December 31, 2004. This benefit is expected to reverse in the years 2005 through 2031. The election did not reduce book inomne tax'expense. The timing of the reversal of this betiWefi't depends on several variables, including the price of power. Due to the temporarynature of the tax beAefit, the p6tential interest charge represents Entergy's net earnings exposure. Ent&Srgy Louisiana's 2001 tax return is currently Under examination by the IRS, though no adjustments have yet been prdposed with 'respect to the mark to market election. Entergy believes that the contingency provision established in its financial statements will sufficiently cover the risk associated with this issue. jik'?ttjg~ts ?oi
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CashPoint Bankruptcv (Entergy Arkansas, Entergy Gulf Statesr'ne'rky Louisiana, Entegy Mississippi, and Entergy New Orleans)
- In 2003 the domestic utility companies entered an agreement wlihtashPoint Network Services (CashPoint) under which ,CashPoint,was to manage a network of payment agents through which Entergy's utility customers could pay their bills. The payment agent system allows customers to pay their bills at various, commercial or goyernmental locations, rather than sending payments by mail. Approximately one-third of Entergy's utility customers use payment agents. t : J 10 .ii -;
W!i Qn April, 19, 2004, CashPoinxt failed to pay funds due to the domestic utility companies that had been collected through payment agents. The domestic utility companies ihen obtained a temporary restraining order ftrom theCivil District Court for the Parish of Orleans, State of Louisiana, enjoining CashPoint from distributing fu ds belonging toEntergy, except by paying those funds to Entergy. On April 22, 2004, a petition for involuntary Chapter 7 bankruptcy was filed against CashPoint by other creditors in the United States Bankruptcy Court for the SQuthernDistripct of New York.. Inresponse to these events, the domestic utility companies expanded an existing coqntract~with another cojmpany to manage all of their payment agents. The domestic utility companies filed proofs of claim in the CashPoint bankruptcy proceeding in September 2004. Although Entergy cannot precisely determine at this time the aamount that CashPoint owes to the domestic utility companies that may not be repaid, it has accrued an estimate of loss based on current information. If no cash is repaid to the domestic utility companies, an event Entergy does not believe is likely, the current estimates of maximunm6-6sure to loss are approximately as follows: Amount (In Millions) , - , Entergy Arkansas $1,8 i - . Entergy Gulf States $7
. ... Entergy Louisiana,, . $8.8 , .
- L;Entergy MNississippi i i $4 3 iI.,. a S., J Entergy New Orleans -. $2.4 Environmental Issues (Ent,tr Gulf Staes) v' ii??:. ? 4/; -i~Xh . ".!,
Entergy Gulf States has been designated as a PRP for the cleanup of certain hazardous waste disposal sites.
As of December 31, 2004, Entergy Gulf States does not expect the remaining clean-up costs to exceed its recorded liability of $1.5 million for the remaining sites at which the EPA has designated Entergy Gulf States as a PRP. 323
Domestic utility companies and System Energy Notes to Respective Financial Statements City Franchise Ordinances (Entergy New Orleans) Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to franchise ordinances. These ordinances contain a continuing option for the city to purchase Entergy New Orleans' electric and gas utility properties. . , Waterford 3 Lease Obligations (Entergy Louisiana) On September 28, 1989, Entergy Louisiana entered into, three identical transactions for the sale and leaseback of undivided interests (aggregating approximately 9.3/o)' in Waterford 3.; In July 1997, Entergy Louisiana caused the lessors to issue $307.6 million, aggregate principal amount, of Waterford 3 Secured Lease Obligation Bonds, 8.09% Series due 2017, to refinance the outstanding bonds originally issued to finance the purchase of the undivided interests by the lessors;. The lease payments were reduced to reflect the lower, interest costs. Upon the occurrence of certain events, Entergy Louisiana may be obligated to pay. amounts sufficient to permit the termination of the lease transactions and may be required to, assume the outstanding bonds, issued, to finance, in part, the lessors' acquisition of the undivided interests in Waterford 3. .- Employment Litigation (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, Entergy New. Orleans, and System Energy) . Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy New Orleans, System Energy, or their affiliates, are defendants in numerous lawsuits filed by former employees asserting that they were wrongfully terminated and/or discriminated against on the basis of age, race, sex, and/or other protected characteristics: Entergy Arkansas, Entergy Gulf States;, Entergy Louisiana, Entergy Mississippi; Entergy New Orleans, System Energy, and' their affiliates are vigorously defending these suits and deny any liability to the 'plaintiffs., Nevertheless, no assurance can be given as to the outcome of these cases. Asbestos and Hazardous Material Litigation (Entergy Gulf States, Entergy Louisiana, Entergy New Orleans) Numerous lawsuits have been filed in federal and state courts in 'Texas, Louisiana, and Mississippi primarily by contractor employees in the 1950-1980 timeframe against Entergy Gulf States, Entergy Louisiana, and Entergy New Orleans, and Entergy Mississippi as premises owners of power plants, for damages caused by alleged exposure to asbestos or other hazardous material. Many other defendants are named in these lawsuits as well. Presently, there are'approximately 480 lawsuits involving approximately 10,000 claims. Management believes that adequate provisions have been established to cover any exposure. Additionally, negotiations continue with insurers to recover more reimbursement, while new coverage is being secured to minimize 'anticipated future potential exposures. Management believes that loss exposure has been 'and will continue to be handled' successfully so that the ultimate resolution of these matters will not be material, 'in the aggregate, to its financial position or results of operation. Grand Gulf - Related Agreements Capital Funds Agreement (System Energy) System Energy has entered into agreements with' Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans whereby they are obligated to purchase their respective entitlements of capacity and energy from System Energy's 90% interest in Grand Gulf, and to make payments that, together with other available funds, are adequate to cover System Energy's operating expenses. System Energy would have to secure funds from other sources, including Entergy Corporation's obligaiio'ns' under the Capital Funds Agreement, to cover any shortfalls from payments received from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under these agreements. 324
Domestic utility companies and System Energy Notes to Respective Financial Statements Unit Power Sales Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and.System Energy) System Energy has agreed to sell all of its 90% share of capacity and energy from Grand Gulf to Entergy Arkansas,- Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans in accordance with specified percentages (Entergy Arkansas-36%, Entirgy Louisiana-14%, Entergy Mississippi-33%, and Entergy New Orleahs-170/) as ordered by FERC. Charges under' this agreement are paid in consideration for the purchasing companies' respective entitlement to receive capacity and energy and are payable irrespective of the quantity of energy delivered so long as the unit remains in commercial operation. The agreement will remain in effect until terminated by the parties and the termination is approved by FERC, most likely upon Grand Gulfs retirement from service. Monthly obligations are based on actual capacity and energy costs. The average monthly payments for 2004 under the agreement are approximately $16.6 million for Entergy Arkansas, $6.7 million for Entergy Louisiana, $13.7 million for Entergy Mississippi, and $8.1 million for Entergy New Orleans. Availability Agreement (Entergy Atkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy) Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (Entergy Arkansas-17. 1%, Entergy Louisiana-26.9%, Entergy Mississippi-31.3%, and Entergy New Orleans-24.7%) in amounts that, when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy's operating expenses as defined, including an amount sufficient to amortize the cost of Grand Gulf 2 over 27 years. (See Reallocation Agreement terms below.) System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Since commercial operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement.' Accordingly, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by Systert Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments. Reallocation Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy) , System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans entered into the Reallocation Agreement relating to the sale of capacity and energy from Grand Gulf and the related costs, in which Entergy Louisiana, Enterky Mississippi, and Entergy New Orleans agreed to assume all of Entergy Arkansas' responsibilities and obligations with respect to Grand Gulf under the Availability Agreement. FERC's decision allocating a portion of Grand Gulf 1 capacity and energy to Entergy Arkansas supersedes the Reallocation Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2 amortization amounts has been individually! allocated (Entergy rLouisiana-26.23%, Entergy Mississippi43.97%, and Entergy New Orleans-29.80%) under the terms of the Reallocation Agreement., However, the Reallocation Agreement does not affect Entergy Arkansas' obligation to System Energy's lenders under the assignments referred to in the preceding paragraph. Entergy Arkansas would be liable for its share of such amounts if Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans were unable to meet their contractual obligations. No payments of any amortization' amounts will be required so long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available o' System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future. Reimbursement Agreement (System Energy) In December 1988, System Energy entered into two separate, but identical, arrangements for the sale and leaseback of an approximate aggregate 11.5% ownership interest in Grand Gulf. In connection with the equity 325
Domestic utility companies and System Energy Notes to Respective Financial Statements funding of the sale and leaseback arrangements, letters of credit are required to be maintained to secure certain amounts payable for the benefit of the equity investors by System Energy under the leases, The current letters of credit are effective until May 29, 2009. Under the provisions of the reimbursement agreement relating to the letters of credit, System Energy has agreed to a number of covenants regarding the maintenance of certain capitalization and fixed charge coverage ratios. System Energy agreed, during the term of the reimbursement agreement, to maintain a ratio of debt to total liabilities and equity less than or equal to 70%. In addition, System Energy must maintain, with respect to each fiscal quarter during the term of the reimbursement agreement, a ratio of adjusted net income to interest expense of at least 1.50 times earnings. As of December 31, 2004, System Energy's debt ratio was approximately, 32.5%, and its fixed charge coverage ratio for 2004 was approximately 4.12,, calculated, in each case, as prescribed in the reimbursement agreement. NOTE 9. LEASES (Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and System Energy) General As of December 31, 2004 the domestic utility companies had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities (excluding nuclear fuel leases and the sale and leaseback transactions) with minimum lease payments as follows: Capital Leases-Entergy Entergy i Year __ .Arkansas Mississippi - (In Thousands) 2005 $9,610 $50 2006 5,682 f 42 2007 , 3,427 ' 11. 2008 1,754 2009 237 Years thereafter 2,606 E Minimum lease payments 23,316 103 Less: Amount representing interest 3,386 ' ' 2 Present value of net minimum lease payments $19,930 $101' Overating Leases Entergy Entergy Entergy Entergy Year Arkansas Gulf States' Louisiana Mississippi: (In Thousands) 2005 $23,743 $26,744 $9,974 $7,421 2006 20,029 23,942 5,647 6,596 2007 17,563,: 17,223 5,109 3,552 2008 14,977 9,742 3,546 3,039 2009 8,622 9,108 2,346 2,676 Years thereafter 54,339 115,216 2,524 11,068' Minimum lease payments. $139,273 $201,975 $29,146 $34,352 326
Domestic utility companies and System Energy Notes to Respective Financial Statements Rental Expense Entergy Entergy Entergy Entergy Year Arkansas Gulf States Louisiana Mississippi (In Millions) 2004 $17.4 $24.4 $11.9 $3.4 2003 $19.4 $26.5 $13.8 $5.4 2002 $20.8 $25.8 $13.6 $5.4 In addition to the above rental expense, railcar operating lease payments and oil tank facilities lease payments are recorded in fuel expense in accordance with regulatory treatment. Railcar operating lease payments were $9.3 million in 2004, $6.8 million in 2003, and $8.3 million in 2002 for Entergy Arkansas and $2.0 million in 2004, $1.8 million in 2003, and $2.0 million in 2002 for Entergy Gulf States. Oil tank facilities lease payments for Entergy Mississippi were $3.2 million for 2004 and $3.1 million for each of the years 2003 and 2002. Nuclear Fuel Leases As of December 3i, 2004, arrangements to lease nuclear fuel existed in an aggregate amount up to $150 million for Entergy Arkansas, $105 million for Entergy Gulf States, $80 million for Entergy Louisiana, and $110 million for System Energy. As of.December 31, 2004, the unrecovered cost base of nuclear fuel leases amounted to approximately $93.9 million for Entergy Arkansas, $71.2 million for Entergy Gulf States, $31.7 million for Entergy Louisiana, and $65.6 million for System Energy. The lessors finance the acquisition and ownership of nuclear fuel through loans made under revolving credit agreements, the issuance of commercial paper, and the issuance of intermediate-term notes. The credit agreements for Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, and System Energy each have a termination date of October 30, 2006. The termination dates may be extended from time to time with the consent of the lenders. The intermediate-term notes issued pursuant to these fuel lease arrangements have varying maturities through February 15, 2009. It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. However, if such additional financing cannot be arranged, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations in accordance with the fuel lease. Lease payments are based on nuclear fuel use. The table below represents the total nuclear fuel lease payments (principal and interest) as well as the separate interest component charged to operations in 2004, 2003, and 2002: 2004 2003 2002 Lease Lease Lease Payments Interest Payments Interest Payments Interest (In Millions) Entergy Arkansas $53.0 $4.3 $49.9 $3.3 $49.6 $3.2 Entergy Gulf States 29.7 3.2 27.8 3.0 29.2 3.0 Entergy Louisiana 36.1 2.5 32.3 2.4 32.9 2.6
-System Energy 27.8 2.8 32.0 3.1 26.1 2.5 Total $146.6 $12.8 $142.0 $11.8 $137.8 $11.3 327
Domestic utility companies and System Energy Notes to Respective Financial Statements Sale and Leaseback Transactions Waterford 3 Lease Obligations (Entergy Louisiana) In 1989, Entergy Louisiana sold and leased back 9.3% of its interest in Waterford 3 for the aggregate sum of $353.6 million. The lease has an approximate term of 28 years. The lessors financed the sale-leaseback through the issuance of Waterford 3 Secured Lease Obligation Bonds. The lease payments made by Entergy Louisiana are sufficient to service the debt. In 1994, Entergy Louisiana did Inot exercise its option to repurchase the 9.3% interest in Waterford 3. As a result, Entergy Louisiana issued $208.2 million of non-interest bearing first mortgage bonds as collateral for the equity portion of certain amounts payable under the lease. In 1997, the lessors refinanced the outstanding bonds used to finance the purchase of Waterford 3 at lower interest rates, which reduced the annual lease payments. Upon the occurrence of certain events, Entergy Louisiana may be obligated to assume the outstanding bonds used to finance the purchase of the unit and to pay an amount sufficient to withdraw from the lease transaction. Such events include lease events of default, events of loss, deemed loss events, or certain adverse "Financial Events." "Financial Events" include, among other things, failure by Entergy Louisiana, following the expiration of any applicable grace or cure period, to maintain (i) total equity capital (including preferred stock} at least equal to 30% of adjusted capitalization, or (ii) a fixed charge coverage ratio of at least 1.50 computed on a rolling 12 month basis. As of December 31, 2004, Entergy Louisiana's total 'equity capital (including preferred stock) was 51.33% of adjusted capitalization and its fixed charge coverage ratio for 2004 was 3.76. As of December 31, 2004, Entergy Louisiana had future minimum lease payments- (reflecting an overall implicit rate of 7.45%) in connection with the Waterford 3 sale and leaseback transactions;, which are' recorded as long-term debt, as follows: (In Thousands) 2005 $14,554 2006 18,261 2007 18,754 2008 22,606 2009 32,452 Years thereafter 334,062 Total 440,689 Less: Amount representing interest 192,964 Present value of net minimum lease payments $247,725 Grand Gulf Lease Obligations (System Energy) In December 1988, System Energy sold 11.5% of its undivided ownership interest in Grand Gulf for the aggregate sum of $500 million. Subsequently, System Energy leased back its interest in the unit for a term of 26 1/2 years. System Energy has the option of terminating the lease and repurchasing the 11.5% interest in the unit at certain intervals during the lease. Furthermore, at the end of the lease term, System Energy has the option of renewing the lease or repurchasing the 11.5% interest in Grand Gulf. In May 2004 System Energy caused the Grand Gulf lessors to refinance the outstanding bonds that they had issued to finance the purchase of their undivided interest in Grand Gulf. The refinancing is at a lower interest rate, and System Energy's lease payments have been reduced to reflect the lower interest costs. 328
Domestic utility companies and System Energy Notes to Respective Financial Statements System Energy is required to report the sale-leaseback as a financing transaction in its financial statements. For financial reporting purposes, System Energy expenses the interest portion of the lease obligation and the plant depreciation. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes. .Consistent with a recommendation contained in a FERC audit report, System Energy recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and is recording this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance at the end of the lease term. The amount of this net regulatory asset was $75.4 million and $83.2 million as of December 31, 2004 and 2003, respectively. As of December 31, 2004, System Energy had future minimum lease payments (reflecting an implicit rate of 5.01%), which are recorded as long-term debt as follows: (In Thousands) 2005 $45,423 2006 46,019 2007 46,552 2008- 47,128 2009 47,760 Years thereafter. 302,402 Total 535,284 Less: Amount representing interest 138,165 Present value of net minimum lease payments $397,119 NOTE 10. RETIREMENT AND OTHER POSTRETIREMENT BENEFITS (Entergy Arkansas, Entergy Gulf States, Entergy,Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy) Pension Plans Entergy's domestic utility companies and System Entergy participate in two of Entergy's pension plans: "Entergy Corporation Retirement Plan for Non-Bargaining Employees" and "Entergy Corporation Retirement Plan for Bargaining Employees." Entergy Corporation and its subsidiaries fund pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue 'Code of 1986]]