ML052700468

Duke Energy Plants and Independent Spent Fuel Storage Installation, Annual Financial Reports - Summary Annual Report

ML052700468
Person / Time
Site:	Oconee, Mcguire, Catawba, McGuire
Issue date:	12/31/2004
From:	Patricia Anderson Duke Energy Corp
To:	Office of Nuclear Material Safety and Safeguards, Office of Nuclear Reactor Regulation
References
Download: ML052700468 (103)

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Paul M. Anderson 14MVrEnerqy..

is 2004 OBJECTIVES Generate cash and educe 0 per share-Preserve the dividend of $1.1 portfolio Resize and realign our asset Improve safety record -

modest expansion Invest in maintenance and

'4 generation M Reduce losses in merchant bureaucracy-Streamline systems to reduce and overhead-rewards/2 I Set clear accountabilities, linking to results-stakeholders Restore credibility with key issues -

Resolie regulatory and legal

$AAIAAlY

J INTHIS REPORT 1 CHAIRMAN'S LETTER TO SHAREHOLDERS 2 FINANCIAL HIGHLIGHTS 5 OUR 2005 CHARTER 6 PRESIDENT'S REPORT ON OPERATIONS 9, DUKE POWER 10 DUKE ENERGY GAS TRANSMISSION 11 DUKE ENERGY FIELD SERVICES I 11

- , .I I

-1 I I 12 DUKE ENERGY AMERICAS I i I. - I 14 CRESCENT RESOURCES - 'i I

- I i 15 CONSOLIDATED FINANCIAL STATEMENTS I - I i

. Ii 20 NON-GAAP FINANCIAL MEASURES I 22 BOARD OF DIRECTORS 24 EXECUTIVE MANAGEMENT 25 INVESTOR INFORMATION

- )

Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995 This document contains forward-looking information which is subject to risks and uncertainties that could cause actual reiults~to be different than those contemplated, including, but not limited to: changes instate, federal or international regulatory environments; comm~erc ial, industrial and residential growth inthe company's service territory; the weather and other natural phenomena; the timing 'and extent of changes in commodity prices, interest rates and foreign currency exchange rates; general economic conditions; 'Changes inienvironmental and other laws and regula-

tions to which Duke Energy and its subsidiaries are subject, or 'other external factors over which Duke Energy has no control; the results of financing efforts; the effect of accounting pronouncements; -growth inoppo rtunities for Duke Energy's business units; and other risks' described inthe company's 2004 SEC Form 10-K and other Securities and Exchange Commission filings. The company undertakes no obligation to publicly update or revise any for'ward-looking statements, whether as a result of new information, future events or otherwise.

c i _ : I I - "- - . b - -

Dear Fellow Shareholder,

My letter to you last year focused on the challenges our company faced as we sought to redefine our position in an industry which was itself emerging from a painful restructuring. At that time, we were long on promises and resolve, but rather short on results. We had assessed our situation, implemented some organizational changes, articulated an investment proposition and developed a charter for the company.

The charter listed five imperatives which formed the basis for a number of specific objectives for 2004. Assessing our performance against those objectives gives me a sense of accomplishment - even cautious pride - which is tempered by deep disappointment over where we have failed. We also have some unfinished business to address.

Our Accomplishments InJanuary 2004, we detailed a financial plan for our investors. At that time, many inthe financial community were skeptical as to our ability to achieve that plan, but we ended up significantly exceeding each of our commitments. We maintained the dividend of $1.10 per share, beat our ongoing basic earnings-per-share goal of $1.20 by 18 cents, reduced debt by $4.6 billion (lowering debt as a percent of total capital to 51 percent from 58 percent), maintained liquidity well over $1 billion and voluntarily contributed more than $500 million to our U.S. pension plan and nuclear decommissioning funds.

We were also able to significantly reduce DENAs (Duke Energy North America's) mark-to-market exposure and close out a number of legal and regulatory uncertainties that the company was facing. As a result, our credit rating stabilized, and the market also responded positively, as our share price rose by 25 percent to close the year at $25.33. We delivered a total return to shareholders of 30 percent for 2004 - outpacing the S&P 500's 11 percent.

Much of our financial plan was achieved by aggressively realigning our portfolio. We realized over $3.1 billion of proceeds from the sale of assets, such as our merchant plants inthe southeast United States, our asset portfolios inthe Asia-Pacific region and Europe, and two of our three deferred plants. (The sale of the third plant is expected to close in March 2005.)

1

74 FINANCIAL :H IGH LIGHTS-Years Ended December 31:

(inmillions., exceot per-share amounts) r-i-1 2003b 2002 2001, 2000 Statemerit of Operations.

Operating revenues $ ~22,503 $ 22,080 'S 15,860 .$17,889 'S15,800 Oeaigepnses' 1946 22,818 '- 1,28 14,311 12,775 Gains on sales of investments in commercial and multi-family real estate i - I 192 84106 '. 106 K. 75 (Losses) gains on sales ofohrastnt1 (2) (9)32 ~23821 Operating income (loss). 3,014 (~853)! ~2,740 - ,92 3,314 Other income and expenses,~net 302 584 ~ 379 ~ .07

-31 Interest expense 1, 1,349 I~1,380 ' 1,097~ .760 '887 Minority interest expense Earnings (loss) from continuing operations.

beore e incometaxes " ,7 (1,710) 1,906 ,147 2,832 .-:i. i income tax expense (benefit) from`11continuing operations - 1 .540 ~*,.%J(707) 1 1149 1 -'1,032 I. II Income (loss) from continuing operations I123 2 Incom e (loss) from discontinued operations, net of tax 258 (158) KY21 ~

,4 2)

Income (loss) before cumulative effect of change in accounting picle .1,9 '(1,161) 104 1 994 1._II6]7 Cumulativ~ effect of change inaccounting principle net of tax-and minority interest 7- (162)- '- '(96) - '.

1,034 1,898, 1,776  :

1 Net income (loss) 1,49 (1,323)

'Divideinds~and premiurms on redemption of preferred sand preference stock .: i] 9 :15' :114 1 -

Erig(ls)available for common stockholders:1 $~-;1,481I .5 (1,338) S 1,021 - .,884--S1,757 Rtoof Earnings to Fixed Charges 2.3 ~C *'~2.2 3.9 3.7 Common Stock Data a Shares of common stock outstanding Year-ena 957 911 89 777 73

'Weighted average `"-<'I _ 931' 836

`0 767 73 Earnings (loss) per share (from continuing operations)

Basic $ 13 S (1.3 S -1.53 S 259 ,$ 24 Diluted: 1.271 -- .53 257 ~' 2.41

• .Earnings (loss) per share (from discontinued operations) I'

• Basic $ 0.28 S (0.17)' (0.31) S (0.01) $ (0.03)

Diluted O.27J -'(0.17) '.~-_;i0.31) (-0 01) ~-(0.03),

Earning (loss) per share (eoe Cumulative effect 1 4 'K J, of chanrge inacco'unrtingi principle) -!

Basic - .$ -5(1.30) 5,122 $ A2.58 $ 2.39, Diluted J 1.54 (1.30): 1.22' E2 56 - 2.38 Earnings (los) per share

~Basic$ 1.59 S(.48) $ 2 S 2.45-`S 2.39

Diluted ~1.54 (148) >1.22 2.44 - 2.38 Dividerids per share i 1.1 0 1.1I0 ~ 1 10 1 10' Balance Sheet $5,7

• Total assets'~ 540 S57,225 $ 60,122 $49,624 $ 59,276 -

Long-er debt inclu'ding capital leases, lescurrent maurities S1,3 S20 622 $' 20,221 $ 12,321' S~10,717.,:

Capitalization 36 r 41% 37%

Comrnon equity. - 450/' 37%6% -4 70

• Preferied stock 7:'0% 0%-

Trust preferred securities -"- *-- 0%

Total common equity and preferred securities -45% I 37%_ 40/n 47% 43%

Minority interests -

4

/a -5% 5% 7%

`7 9/a

-Total debt51 -:58% SSV 4/

• V46c a Amount pnior to 2001 were restated to reflect the two-for-one common stock split effective January 26, 200:

b As of January 1 2003, Duke Energy adopted the remaining provisions of Emerging Issues Task Force Issue N'o. 02-03, 'Issues involved inAccounting for Denivative contraicts Heid for Trading Purposes and forContracts invoived inEnergy Trading and Risk Management Activities' and Statemnent of Fina Accounting Standards No. 143, Accouintingf for Asset Retirement Obflgitions.

nciai inaccordance with the transition guidance for these standards, Duke Energy recorded a net-of-tax and minoriti, interest cumuiative effect adjuntmnnt for cha nge in accounting principleIs.

c Earnings were inadequate to cover ruxed charges by $1,707 millkonfor the year ended December 31, 2003.

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In addition to generating funds, those sales repositioned Duke Energy as a company focused on the Americas and eliminated some of our lowest-return assets. We also challenged our real estate subsidiary, Crescent Resources, to become a major contributor of cash, and it responded with a stunning contribution of more than $440 million.

We moved into 2005 with a solid earnings base and the financial flexibility to once again control our own destiny. In February, we announced that we would buy back up to $2.5 billion incommon stock over the next three years, based on our strong cash position. This share repurchase program will create value for shareholders, without inhibiting our ability to pursue future growth opportunities. We plan to pursue new growth cautiously, remaining mindful that we spent the year 2004 recovering from the effects of what in hindsight was an overly aggressive growth strategy.

Pride in the Organization Given the significant achievements of the last 12 months, it is noteworthy that the members of the team that accomplished them were, with few exceptions, already here when I rejoined the company in November 2003. It is a tribute to that depth of talent that I was not forced to go outside the company to renew the organization. Using existing bench strength, we have significantly refreshed the organization and taken a number of steps to further develop the talent we have.

I am quite proud of the team we have in place today. Employees at all levels recognized the challenges that the company faced and stepped up to accept responsibility for resolving them. The company has done its part by aligning rewards with results, refocusing on talent management and reinvigorating a number of employee development programs. Particular attention has been focused on diversity, training, performance management and management development. During December 2004, the senior management team underwent a 360-degree evaluation, and a number of executive rotations were set in motion to ensure that we are developing the next generation of leadership at all levels.

Another source of pride was the contribution that Duke employees made to their communities. To commemorate Duke Power's 100th anniversary in 2004, our annual month-long Global Service Event was expanded to 100 days. An estimated 9,000 employees and retirees spent approximately 27,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> completing more than 500 service projects in the United States, Canada, Brazil and Peru.

Also in 2004, Duke Power proactively engaged leaders in business, industry, government, education and the nonprofit sector in economic development summits in North Carolina and South Carolina. In the Carolinas and elsewhere, Duke is actively involved inthe communities in which we operate.

We also made progress in increasing our focus on customers and working with regulators to achieve win-win outcomes. For example, regulators in the Carolinas embraced an innovative approach where we share profits from Duke Power's bulk power marketing sales with our customers. Those dollars are funding job retraining programs and providing energy assistance to low-income households - improving the quality of life in our region. In North Carolina, some of these funds are also being used to reduce industrial rates, allowing those customers to offer more cost-competitive products and services.

We began a process of renewal at the Board level, beginning with an in-depth assessment led by an independent third party. As a result, we established a lead director, formed a Nuclear Oversight Committee, rotated committee heads and welcomed two new Board members, Roger Agnelli and Dennis Hendrix. We thank Bob Brown, George Dean Johnson and Leo Linbeck for their many contributions over the years; they will be retiring from the Board in May 2005.

Disappointments While we are proud of our successes, we cannot ignore our failures. The biggest disappointment of 2004 was our unacceptable safety record. A number of measures can be used to judge an organization's safety record, but none is so personal or powerful as the number of employee and contractor fatalities. In 2004, one employee and three contractors lost their lives while working for Duke Energy. This is more than unacceptable - it is a tragedy for which I feel personally responsible. I would like to rationalize 3

why those fatalities occurred, but I simply cannot. Safety is not something that can be prescribed or controlled through process alone. It relies on a culture that is nurtured from the top, and Duke's top management cannot allow safety to be overshadowed by other priorities.

Another disappointment was the fire last August at our Moss Bluff natural gas storage facility near Houston. Thankfully, no employee or contractor was injured, yet it is disappointing that such an incident could occur.

We have taken a number of steps to improve our safety focus. Later on in this report, Fred Fowler will address some of them. For my part, I will not feel that we have had a truly successful year unless that year is free of fatalities and major operational incidents.

Unfinished Business We made significant progress in a number of areas, but we are left with unfinished business. Developing a sustainable business model for DENA is one such area. We made substantial progress in restructuring DENA and expect it will cut its losses by nearly half in 2005, but it may take a combination with one or more other parties, including other merchant generators, to provide the scope, scale and fuel diversity needed to realize an acceptable return on that investment.

A tremendous effort and significant funds were expended to comply with Sarbanes-Oxley Section 404, which mandates a thorough self-assessment of our internal controls over financial reporting. Despite the frustration of a rigid process and a challenging time frame, the effort proved very beneficial in helping us understand where we could improve our processes and systems. In 2005, we will build on what we have learned and re-engineer our financial systems, simplify our organization and reduce bureaucracy.

Ultimately, this effort should greatly reduce our overhead costs in future years.

Looking Forward As we enter 2005 and beyond, I am optimistic. The management objectives inour 2005 charter reflect the progress we made in 2004 to reclaim control of our future. This year, we are pursuing growth opportunities and reasserting our role as an industry leader.

The financial objective for 2005 is to deliver on our financial plan and provide superior total shareholder return. This reflects how far we have come - 2004's financial goal was to defend the dividend. We had an ongoing basic earnings-per-share target of $1.20 for employee incentive payouts in 2004. For 2005, we have increased that target by 33 percent to ongoing basic earnings per share of $1.60.

Another management objective is to establish industry-leadingpositionsin core businesses and identify new energy-related growth strategies. We are in a position to grow any of our existing businesses if we find the right opportunity, and we will evaluate new but related lines of business to fuel future growth.

One 2005 objective relates to the unfinished business I discussed earlier: to position DENA to be a successful merchant operator with a sustainable business model.

We will also enhance a high-performance culture by focusing on safety, inclusionand diversity, employee development, business structure and process simplification.The highest priority here is to improve our safety culture. We have created a shared safety goal for 2005 for the top 700 leaders in the company. If any Duke employee, contractor or subcontractor loses his or her life while doing work for us, this group will have their total short-term incentive payout reduced.

Our final objective for 2005 is to build stakeholder relationshipsand future shareholder value through effective leadership on key policy issues related to energy, regulation and the environment. It is clear that the United States needs cohesive environmental and energy policies that break the continuing logjam, and we intend to take a leadership role in developing and advancing those policies. For example, we will be proactive on the issue of global climate change. By helping shape public policy, we can advance the interests of our investors and customers, while also addressing the issue itself. Ideally, 4

U.S. public policy should encourage a transition to a lower-carbon-intensive economy through a broad-based approach, such as a carbon tax or other mechanism which addresses all sectors of the economy.

As I close this letter, I would be remiss if I did not address the most critical concern I wrote of last year: restoring credibility with our key constituents. In 2004, I believe we made significant progress in re-earning their trust. While trust and credibility are hard to measure, we see positive indicators - in the tone and tenor of questions from our many stakeholders, in the spirit and resilience of our employees, and in the contracts and handshakes with our partners and customers. As I said last year, the task of building confidence will always be unfinished business for us, but I hope that you share my sense of real progress in this area and a positive view of our company's future.

I appreciate your many comments and suggestions over the past year and thank you for your continued investment in Duke Energy.

Sincerely, Paul M. Anderson Chairman of the Board and Chief Executive Officer March 15, 2005 OUR 2005 CHARTER We are Duke Energy, a leading energy company located inthe In conducting our business, we value:

Americas with an affiliated real estate operation.

• Stewardship - A commitment to health, safety, environmental responsibility and our communities.

Our purpose is to create superior value for our customers, employees, communities and investors through the production, conversion,

• Integrity - Ethically and honestly doing what we say we will do.

delivery and sale of energy and energy services.

• Respect for the Individual - Embracing diversity and inclusion, enhanced by openness, sharing, trust, teamwork and involvement.

To provide a stable platform for future growth, we must:

• High Performance - The excitement and fulfillment of achieving

• Enhance a high-performance culture by focusing on safety, inclusion superior business results and stretching our capabilities.

and diversity, employee development, business structure and

• Win-Win Relationships - Having relationships which focus on the process simplification.

creation of value for all parties.

• Position DENA to be a successful merchant operator with a

• Initiative - Having the courage, creativity and discipline to lead sustainable business model.

change and shape the future.

• Deliver on our financial plan and provide superior total shareholder return. We will be successful when:

• Establish industryleading positions incore businesses and

• Our investors realize a superior return on their investment.

identify new energy-related growth strategies.

• Our customers and suppliers benefit from our business relationships.

• Build stakeholder relationships and future shareholder value

• The communities in which we operate value our citizenship.

through effective leadership on key policy issues related to energy, regulation and the environment.

• Every employee starts each day with a sense of purpose, and ends each day with a sense of accomplishment.

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OPERATIONS

Dear Shareholders,

Overall, 2004 was a year of considerable progress in Duke Energy's operations. I welcome this opportunity to report on those results, and review some of the past year's successes and disappointments.

Duke Energy's diverse portfolio allows us to balance the market risk in our nonregulated businesses with the relatively stable earnings that our regulated companies provide.

Regulated Businesses Generated Steady Earnings Duke Power contributed $1.47 billion in segment earnings before interest and taxes (EBIT) in 2004. The utility provides us with a solid base of earnings and cash flow. Duke Power is working hard at diversifying its customer base and attracting new business to our area. Duke Power's customers pay essentially the same average rate per kilowatt-hour today as in 1986. At about 21 percent below the national average (due to efficient operations, cost management and lower-cost nuclear generation) those competitive rates offer an important advantage to customers inour service territory, and are especially attractive to potential new industries.

In 2004, Duke Energy Gas Transmission's (DEGT's) 17,500 miles of transmission pipeline continued to move natural gas to key distribution companies along the U.S. East Coast and in Canada, contributing S1.31 billion in segment EBIT. Expansion activity has been brisk over the past year, with infrastructure projects completed in western Canada and in the U.S. Northeast, Mid-Atlantic, Southeast and Gulf Coast regions. Transportation reliability was also strong, with DEGT operations in both the United States and Canada setting numerous all-time peak volume records. Reliability, combined with outstanding customer service, contributed to contract renewal levels of nearly 100 percent in our northeast U.S. market.

Weather - as it relates to heating and cooling needs - has a major impact on both DEGT and Duke Power, but the weather created a different challenge in 2004. For most of the southeastern United States, 2004 will be remembered as the year of the hurricanes. Several of our businesses experienced minor disruptions, but Duke Power's transmission and distribution system was 2004 operations leadership (above, left to right): Ruth Shaw, Duke Power; Bill Easter, Duke Energy Field Services; Fred Fowler, President and Chief Operating Officer, Duke Energy; Bobby Evans, Duke Energy Americas; Tom O'Connor, Duke Energy Gas Transmission; Art Fields, Crescent Resources 6

largely spared from effects of the hurricanes. That allowed our line crews to provide needed support to utility customers in Florida and throughout the Southeast.

Unregulated Businesses Saw Challenges and Opportunities Paul provided an overview of our progress with Duke Energy Americas, which includes Duke Energy North America (DENA) and Duke Energy International (DEl). Those businesses ended 2004 with very different scale and scope than when they began. The sale of DEl's Asia-Pacific assets allows us to focus on our operations in Latin America. In 2004, DEI generated segment EBIT from continuing operations of $222 million and is looking for a 2 to 3 percent compound annual growth rate over the next three years, based on its 2004 ongoing segment EBIT of $236 million.

While unfinished business remains for DENA in 2005, we should not overlook the significant progress made in 2004. We sold our generating portfolio inthe Southeast as well as two deferred plants in the West - and expect to close on the sale of a third in March 2005. We also changed the DENA business model to focus on contracting a larger share of electric generation through tolls and capacity sales. (Tolls are agreements to sell all or part of a plant's capacity or production for a fee.) We are now beginning to see the benefits of that approach. For example, in 2004 DENA sold more than 50 major tolls and future capacity contracts to investor-owned utilities, municipalities and other customers, adding significantly to DENA revenue for 2005 and beyond. Additionally, DENA reduced operating expenses by nearly $180 million. We expect to cut DENA's $288 million ongoing segment EBIT loss from continuing operations in 2004 roughly in half, to a projected ongoing EBIT loss of approximately $150 million in 2005. We continue to pursue various options thati will create a sustainable business model for DENA, including consideration of potential business partners. Duke Energy North America's Moss Landing facility inI Calitornia is one ot the largest and most etficient While market conditions have challenged DENA, they have provided opportunities for generating plants inthe state. (Photo: David Sievert) our other businesses. Record-high crude oil prices meant a blockbuster year for Duke Energy Field Services (DEFS), generating EBIT from continuing operations of $380 million to Duke Energy. DEFS is the largest processor of natural gas liquids (NGLs) in the United States, and NGL prices roughly track the price of crude oil. But it is not only the price of crude that is helping DEFS. Even in a record-breaking year, DEFS initiated business improvements that reduced costs for its ongoing operations by $30 million.

In February 2005, we reached agreement with ConocoPhillips to restructure our 70 percent ownership of DEFS into an equal partnership, which will reduce our exposure to commodity price risk and provide more than $500 million in pre-tax cash to Duke Energy. The deal will also transfer DEFS' natural gas gathering and processing facilities and ConocoPhillips' natural gas liquids system in western Canada to DEGT - adding significantly to the scope, scale and diversity of DEGT's Canadian operations.

Crescent Resources, our real estate and land management subsidiary, concentrated on the strongest segments of the U.S. real estate market in2004, generating record results of $240 million in segment EBIT from continuing operations. While Crescent regularly refreshes its property holdings, 2004 results reflected an opportunistic sale of property in the Washington, D.C. area. Going forward, we expect Crescent's segment EBIT contribution to return to a more historic level of approximately $150 million in 2005.

Legal Issues Resolved We made tremendous progress in 2004 in resolving many of the company's regulatory and legal risks. Most significantly, a comprehensive settlement with western U.S. power market participants, approved by the Federal Energy Regulatory Commission in December, provided needed closure to issues that arose inthat market in 2000 and 2001. We were also gratified that the U.S.

Attorney closed an investigation into Duke Power's 1998 to 2000 accounting practices, concluding that no action was warranted against the company or its employees.

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Safety Performance Must Improve Regarding safety, I can only say that our performance in 2004 was, in a word, unacceptable. Four people who came to work at Duke Energy facilities last year did not go home to their families. In response, we are building a zero-injury safety culture to prevent employee and contractor injuries.

• We have communicated a new safety vision to all employees that aims for zero injuries through continuous safety improvement, and we are setting the same expectations for our contractors.

• We are leading this culture change from the top - every member of the Expanded Executive Committee has personal safety objectives that spell out exactly how they a will lead their organization to an improved safety record. -

• I will discuss in person our safety expectations with more than 2,500 managers and l supervisors in 2005.

• Business units are conducting employee safety perception surveys, and I will person-ally review the safety improvement plans developed in response to those surveys.

Hector Gutierrez and Pilar DMvila of Duke Energy We Gave Back to Our Communities Perus Lima office brighten the educational experi ence for local elementary students with afresh coat To customers and communities, our employees are the face of Duke Energy. Corporate of paint for their desks.

giving and volunteerism remain hallmarks of Duke Energy, and in 2004 we continued to make a real difference in our communities in the following ways:

• Duke Energy marks its birthday each year with a Global Service Event. In 2004, thousands of employees and retirees participated in more than 500 volunteer projects in 170 communities where Duke Energy operates. Most of the projects helped improve the lives of children, senior citizens and disabled individuals. In Peru, for example, employees focused on children and education.

They donated books and school supplies, painted classrooms, served lunch and organized activities.

• Duke Energy employees were recognized with Ethics in Action's Community Care Award for developing innovative community partnerships and programs serving the residents of British Columbia.

• In the Carolinas, we are leading economic development efforts to diversify our region's economy and provide opportunities for growth. That's good for Duke Power and good for the region. In 2004, Duke Power contracted more than $23.3 million of new annual electric load (compared to $6.2 million for 2003), and nearly 200 additional projects are pending.

• Crescent Resources won accolades from community leaders and state officials for committing to sell nearly 3,000 acres and to make a one-time multi-million-dollar gift to the state of North Carolina to expand Lake James State Park almost sixfold.

• The Texas Corporate Wetlands Restoration Partnership, led by DEGT employees, participated in one of only 12 projects honored nationwide by Coastal America - a partnership of federal agencies and state and local private organizations. Our work on the San Jacinto battleground project near Houston contributed to the restoration of 115 acres of historic marshland as well as adjacent prairie and bottomland forest.

These are just a few examples of the many ways the people of Duke Energy work to improve our communities, economy and environment. On the following pages, the leaders of our businesses will tell you more about their performance and future objectives.

Sincerely, Fred J. Fowler President and Chief Operating Officer 8

DUKE POWER BEGINNING A SECOND CENTURY OF SERVICE In2004, Duke Power celebrated its 100th anniversary in a way that honored our heritage - by taking a leading role in advancing economic development in the Carolinas.

Inrecent years, textiles and other industries that were once the bedrock of the region's economy have steadily declined.

Our competitive electric rates are one way to attract new business. But energy costs are just one aspect of a region's commercial appeal. Much like our founders, i =

who used electricity to help drive the textile boom early in the 20th century, we are working to strengthen and diversify our economy and expand our customer base by attracting new business and industry to our service territory.

Major accomplishments:

/ Duke Power jump-started the economic development engine by bringing more than 500 business, industry, government, nonprofit and academic leaders together for two Carolinas Competitiveness Forums in 2004.

/ We are already seeing results from our push to help recruit and retain manufac- Catawba Nuclear Station inYork County, S.C., set turing. Major companies like Merck and Dell, and many smaller businesses, have a new Duke Power reliability record in2004, and announced plans to locate facilities in Duke Power's service territory. was recognized by the U.S. Nuclear Regulatory

/ Regulators embraced our plan to share some of the profits from our bulk power marketing sales 50-50 with shareholders and customers. Programs funded by these sharing arrangements help pay energy bills for low-income residents, fund workforce training at community colleges, help reduce industrial rates in North Carolina, and support energy-efficient industrial improvements and local economic development initiatives in South Carolina.

/ Duke Power's generating fleet continues to excel in reliability and efficiency. Catawba Nuclear Station set a new company reliability record in September, operating for 531 continuous days, and Electric Light & Power magazine named Marshall Steam Station the most efficient coal-fired station in the United States.

No amount of business achievement can make up for the tragic loss of three of our contractors in 2004. Ensuring the safety of employees, contractors and customers remains a core Duke Power value, and we are focused intently on both the cultural and process changes needed to reduce avoidable accidents, injury and risk.

Looking ahead, our growth forecasts indicate a need for new base-load generation within the next decade. We are evaluating options to meet that need inways that are both economical and environmentally sound. We are upgrading a number of our existing coal-fired stations with state-of-the-art environmental equipment, and evaluating emerging clean-coal technologies. The relicensing of our hydroelectric facilities, currently underway, will ensure the continuation of hydropower as an economical and emission-free energy resource, while preserving water quality and recreational access. And to secure the option of future nuclear generation capacity, we are in the initial stages of preparing a combined construction and operating license application for a new, advanced-design nuclear plant.

As Duke Power enters its second century, we continue to build on the fundamentals of customer service, operational performance, safety, responsible citizenship and innovation.

-Ruth Shaw, President and Chief Executive Officer, Duke Power Profile: One of the largest investor-owned electric utilities inthe United States, Duke Power delivers safe, reliable and economically priced electricity to more than 2 million customers in North Carolina and South Carolina.

Operating Data 2004 2003 2002 2001 2000 Franchised Electric Sales, gigawatt-hours 82,708 82,828 83,783 79,685 84,766 Nuclear capacity factora 90% 91% 95% 92% 92%

Average number of customers 2,197,000 2,160,000 2,117,000 2,117,000 2,072,000 a Includes 100 percent ofCatawba Nuclear Station, which is 12.5 percent ownedbyDukePower.

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DUKE ENERGY GAS TRANSMISSION RETOC:IS CON' CGROWi.'T'IH Duke Energy Gas Transmission (DEGT) pipelines are strategically located with access to diverse supply basins and growing markets throughout North America, and our storage facilities offer customers reliability and seasonal flexibility.

We expect demand for natural gas to grow by an average 2 to 3 percent annually in our key markets over the next five years.

Our challenge is to keep pace with that demand, by developing the infrastructure needed to connect new supplies to growing markets.

Major accomplishments:

/ Three natural gas pipeline and two gas storage expansion projects began to serve DEGT customers in 2004, adding delivery capacity for customers inthe U.S. Northeast, Southeast and Mid-Atlantic states. Storage facility expansions in Louisiana and Virginia increased available gas storage capacity by 1.8 billion cubic feet.

/ The 110-mile extension of the Gulfstream pipeline from central Florida to the state's east coast was completed in February 2005, doubling the pipeline's firm contracted capacity. (Gulfstream is a joint development of Duke Energy and Williams.)

/ Multiple peak-volume days on our Texas Eastern, Algonquin, East Tennessee, Gulfstream and Union Gas systems demonstrated our ability to operate reliably u and provide access to growing markets. I

/ In August, DEGT employees mobilized quickly and effectively in response to a fire at our Moss Bluff gas storage facility near Houston. We regret that this incident occurred and the inconvenience that it caused our neighbors and customers.

/ A successful "open season' in the northeast United States and eastern Canada signaled strong customer demand for new natural gas transportation and storage solutions. Many of those responses should result in new contracts and several expansion projects over the next three to five years.

v/ Union Gas added more than 31,000 new customers in 2004 through focused Plant operator Charles Barker monitors storage marketing efforts and reliable service. operations at the Kingsport liquefied natural gas storage facility, on DEGT's East Tennessee Natural Rate proceedings involving our BC Pipeline and Union Gas businesses were G/

Gas pipeline system.

resolved fairly for both customers and shareholders.

Over the next several years, we plan to invest more than $1 billion in DEGT facility expansions. We expect liquefied natural gas (LNG) to play a major role in North America's future natural gas supply. LNG import terminals are proposed along the Gulf Coast and the northern East Coast, including the Canadian Maritimes, and most of them would have ready access to Duke Energy's existing pipelines and storage facilities. We intend to be a major player in providing the pipeline expansion and storage needed to connect this new supply to growth markets.

Our assets are equally well-positioned in the growing Western Canadian Sedimentary Basin, and the addition of ConocoPhillips' natural gas liquids operations and DEFS' gathering and processing facilities to our system in 2005 will enhance that position.

We are ready and willing to expand further, as natural gas drilling activity increases in northeastern British Columbia.

As I move on to pursue new career opportunities at Duke Energy, I am confident about the continued success of the business that Martha Wyrsch will now lead.

- Tom O'Connor, President and Chief Executive Officer, Duke Energy Gas Transmission Profile: Duke Energy Gas Transmission serves its customers by transporting natural gas from North America's major supply areas to growing markets inthe northeastern and southeastern United States and inCanada. DEGT also stores natural gas, distributes natural gas to retail customers in Ontario, and gathers and processes natural gas for customers inwestern Canada.

Operating Data 2004 2003 2002 2001 2000 Natural Gas Transmission Throughput, trillion British thermal units (TBtu)a 3,332 3,362 3,160 1,781 1,771 Storage capacity, billion cubic feet 258 257 254 101 98 a Represents share of capacity owned by DEGL.

10

DUKE ENERGY FIELD SERVICES A YEAR OF RECORD RETURNS Duke Energy Field Services (DEFS) captured enormous value from strong natural gas liquids (NGL) prices and gas processing margins in 2004. We also improved operating and commercial performance, and benefited from increased production and a strategic acquisition. The combination of these factors resulted in record earnings for the DEFS joint venture.

Major accomplishments:

/ We were able to handle higher natural gas volumes in many areas in 2004, due to increased drilling by our customers, with little or no additional investment. For example, we successfully processed and delivered almost 10 percent more gas on our Oklahoma 'supersystem" by redistributing the flow of natural gas among the system's four plants.

a We delivered strong marketing results and continued to renegotiate natural gas supply contracts in order to better align our interests with those of producers, reduce earnings volatility and improve profitability.

/ DEFS acquired natural gas gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips for $74 million. The acquisition included three processing plants and more than 1,000 miles of gathering pipeline. In addition to adding new customers and volumes, these assets, in combination with our existing facilities, improve market access and reliability for our customers.

/The number and severity of employee and contractor injuries declined at DEFS in 2004, as evidenced by a 40 percent reduction in safety-related lost workdays and more than a 50 percent reduction in contractor injuries versus 2003. Tragically, an employee of our former TEPPCO affiliate lost his life in a work-related accident, -

underscoring the importance of maintaining safety as our top priority.

/ We successfully consolidated our computer operations into Duke Energy' s1 computing center in Charlotte, eliminating our Denver data center and generating significant efficiency and cost improvements. The Platteville facility is one of DEFS' newest gathering and processing plants, built to process DEFS is poised to deliver another exceptional year of earnings in 2005. We expect increased natural gas production inthe Denver-commodity prices to remain above traditional levels, though perhaps somewhat lower Julesburg Basin area of Colorado.

than 2004.

In this, my second year at the helm at DEFS, we are working to further improve our underlying operational and commercial performance through continued application of best practices, by capturing efficiencies inherent in our large operating scale and scope, and by continually improving our processes and information systems.

Two 2005 transactions will allow us to focus on further strengthening our competitive position inthe United States. As part of the pending restructuring of DEFS into a 50/50 joint venture with ConocoPhillips, we expect to receive additional U.S. midstream assets and our Canadian operations will move to DEGT. In addition, with the February 2005 sale of TEPPCO, our affiliated master limited partnership, we exited the business of transporting refined products and crude oil, as well as selected natural gas and NGL activities.

Going forward, we will invest to improve the capability of our existing assets and pursue selective growth opportunities. Given today's competitive landscape, we will also evaluate the merits of establishing another master limited partnership.

- Bill Easter, Chairman, President and Chief Executive Officer, Duke Energy Field Services Profile: The largest producer of natural gas liquids in North America and one of the largest marketers, Duke Energy Field Services gathers, processes, transports, markets and stores natural gas and produces, transports and markets NGLs. DEFS is a joint venture of Duke Energy and ConocoPhillips.

Operating Data 2004 2003 2002 2001 2000 Field Services Natural gas gathered and processed/transported, TBtu/day 7.3 7.4 7.9 8.0 7.0 Natural gas liquids production, thousand barrels per day 363 353 379 384 343 Average natural gas price per million Btu $ 6.14 $ 5.39 $ 3.22 S 4.27 $ 3.89 Average natural gas liquids price per gallon $ 0.68 $ 0.53 $ 0.38 $ 0.45 $ 0.53 11

DUKE ENERGY AMERICAS REALIGNIIN1G OUR PORTFOLIO Duke Energy North America - Reducing Merchant Risk Our goal for DENA in 2004 was to stabilize the business. We accomplished that through asset sales and cost efficiencies, and by moving from a commodity trading model to a stronger focus on marketing energy to customers from our own assets.

An anticipated $300 million ongoing segment EBIT loss came in at $288 million, including unanticipated mark-to-market losses of $25 million. A team of employees committed to controlling costs and optimizing resources made it possible to achieve our financial goal.

Major accomplishments:

/ The sale of our fleet of eight merchant plants inthe southeast United States came sooner than many predicted. Completed in August, the sale boosted Duke Energy's 2004 divestiture proceeds by approximately $975 million, including about $500 million in tax benefits and a note receivable of approximately $50 million.

/ We sold two partially completed plants in 2004 (Luna in New Mexico and Moapa in Nevada), as well as surplus turbines and related equipment. Proceeds from those transactions totaled approximately $600 million, including about

$270 million in tax benefits. At year-end, we signed an agreement to sell a third deferred-construction plant (Grays Harbor in Washington state).

/ We mitigated our earnings volatility by significantly reducing the exposure to fluctuating commodity prices associated with our mark-to-market portfolio.

/ DENA strengthened its position in long-term gas storage capacity, providing flexibility to fuel our own plants as well as serve other customers.

/ Duke Energy's settlement of refund proceedings and other litigation related to the 2000-2001 western U.S. energy crisis cleared the way for some of the Production technicians Mike Armstrong, Benny King large utilities in those markets to return as DENA customers. and Steve Anderson ensure that the Washington Energy Facility in southeastern Ohio operates safely A DENA's Lee facility in Illinois added 'black start" capability in 2004 that will allow and reliably. The plant has had no recordable injuries the unit to start without any outside electrical supply. Even during a blackout, since it opened in2001.

it can be brought into service to help ensure the stability and reliability of the electric grid in the Midwest.

/ We made substantial progress on winding down the Duke Energy Trading and Marketing joint venture with ExxonMobil.

By the end of 2004, we had completed or signed transactions to sell about 90 percent of that business.

Success at DENA is measured in relative terms. We are determined to reduce DENA's losses and return the business to profitability. We expect to cut our ongoing EBIT loss nearly in half in 2005, to approximately $150 million. By the end of 2006, on an ongoing basis, we anticipate breaking even, and we look forward to being profitable again in 2007.

We will continue to control costs and manage our portfolio with smart business decisions. We have strong assets in growing areas, and energy demand continues to grow. We intend to be a strong player in the merchant energy market.

As in the rest of Duke Energy, we are renewing our emphasis on safety. Many of our plants have perfect safety records.

We are challenging ourselves to spread that zero-injury culture across our entire fleet.

Profile: Duke Energy North America owns and operates merchant power generation facilities, and markets electricity, natural gas, energy management and related services to wholesale customers throughout North America.

Operating Data 2004 2003 2002 2001 2000 Duke Energy North America Actual plant production, gigawatt-hours 21,884 24,046 24,962 20,516 18,523 Proportional capacity inoperation, megawattsa 9,890 15,820 14,157 6,799 5,134 a Represents share of capacity o(wed by DENA.

12

Duke Energy International - A Sharper Focus Duke Energy International (DEl) began 2004 with a goal of exiting the European and Asia-Pacific markets - to focus on increasing the returns from our power generation business in Latin America. Energy demand in that part of the world isgrowing at 4 to 6 percent a year, two to three times the growth rate in North America, and DEI owns generation assets in seven Latin American countries.

DEl's continuing operations delivered solid results in 2004, contributing $222 million inEBIT toward Duke Energy's overall goals.

Major accomplishments:

a With the USS1.2 billion sale of our assets inAustralia and New Zealand in April (including $840 million of debt assumed by the buyer), Duke Energy reached its 2004 divestiture target just four months into the year. InMay, DEI sold its 30 percent equity interest in the Cantarell nitrogen facility in Mexico, and by year-end, our exit from Europe was largely complete.

/ Planta Arizona in Guatemala completed its dual-fuel conversion, making it one of the most efficient thermal plants in Central America. By using a mix of different .*<..C - ......

fuels, Duke Energy has become one of the lowest-cost energy providers in =

that region.

/ In Brazil, a successful contracting strategy significantly reduced our exposure to low-price spot markets in 2004 and eliminated that exposure for 2005. At the same time, we are preserving capacity for 2006 and beyond, in anticipation of improving market conditions and price levels.

I DEl's overall safety record improved in 2004. DEI Brazil became the first company to earn the Eloy Chaves Medal, the most prestigious safety award in the country's electric power industry, for three consecutive years. The 160-megawatt Planta Arizona inGuatemala Our employees in Brazil have worked for more than five years without a lost-time generates electricity using dual-fuel efficiently and at low cost, technology.

incident, and our Peru and Argentina facilities recently surpassed two years without a lost-time incident.

/ Duke Energy Peru became the first company in Peru, and the first in the Duke Energy system, to obtain simultaneous international certifications for operations management, environmental management, and occupational health and safety practices, based on International Organization for Standardization (ISO) guidelines.

DEl's operations are wellpositioned to achieve higher earnings and returns in the near term, and to benefit from continued growth in energy demand in Latin America.

-Bobby Evans, President and Chief Executive Officer, Duke Energy Americas Profile: Duke Energy International owns and operates power generation facilities, and sells electric power and natural gas. Its primary focus is on power generation activities in Latin America.

Operating Data 2004 2003 2002 2001 2000 International Energy Sales, gigawatt-hours 17,776 16,374 18,350 15,749 14,154 Proportional capacity in operation, megawattsa 4,139 4,121 3,917 3,968 3,768 a Represents share of capacity owned byDEL.

13

CRESCENT RESOURCES Our challenge in 2004 was to contribute $400 million in cash and $155 million in EBIT to Duke Energy. We hit those targets - and then some - thanks to continuing strong demand for investment-grade real estate. At the same time, we kept all of our platforms - commercial, residential and multi-family - growing and well-positioned for 2005 and beyond. We didn't hold a liquidation sale to meet 2004's financial goals. We executed our strategy, continued to invest in our base of assets and enhanced our development and land management practices, upholding our reputation as a 'green" developer. Every segment of our business contributed to our success in 2004.

Major accomplishments:

I/ Crescent completed master planning for Potomac Yard, a 300-acre mixed-use site adjacent to Reagan National Airport, and sold most of the property to other developers in 2004. We retain ownership of two office buildings under construction, and the General Services Administration has leased 405,000 square feet of that space for the Environmental Protection Agency.

v/ In the residential market, Crescent reached its all-time record of more than

$413 million in individual homesite sales.

/ Property sales are brisk at Palmetto Bluff, an environmental preserve and residential community in South Carolina's lowcountry. A portion of every real estate transaction funds the Palmetto Bluff Conservancy, a nonprofit organization dedicated to natural resource protection on the property. H

/ We sold nearly 3,000 acres of lakefront property and made a one-time multi-million-dollar gift to the state of North Carolina to expand Lake James State Park.

The sale, which closed in January, is a key component in a master plan to drive

i. I iI I I economic growth in the Lake James region and preserve the lake environment for wildlife and recreation. The Auberge Inn at crescents Palmetto Bluff

/ We're participating inthe development of a major mixed-use development in community inSouth Carolina opened in2004, along with the Jack Nicklaus-designed May River Charlotte, N.C., that will include the new corporate headquarters for Piedmont golf course.

Natural Gas.

Most segments of the real estate market held strong in 2004, and Crescent is well-positioned for the future regardless of market conditions. We are investing primarily in the Southeast and the Southwest - growing regions with diverse economies.

Studies show that 85 percent of growth in the United States is occurring in the coastal states, plus Arizona and Nevada.

Within this geographic area, we offer a diversified mix of high-growth product types, including second homes and retirement homes for baby boomers. We're broadening our reach into that market with more diverse real estate offerings, and branching out into residential condominiums, primarily in Florida. We'll continue to adjust our portfolio to invest in both residential and commercial growth markets.

It should be noted that 2004 was a banner year, and it's unrealistic to expect the same results on an annual basis. We can promise, however, to continue to capitalize on opportunities without taking undue risks, and to fulfill our commitments to Duke Energy and its investors.

-Art Fields, President and Chief Executive Officer, Crescent Resources Profile: Crescent Resources manages land holdings and develops high-quality commercial, residential and multifamily real estate projects in nine states. Crescent Resources has received numerous awards for its environmentally sensitive property development strategies and partnerships with environmental and wildlife groups.

Operating Data 2004 2003 2002 2001 2000 Crescent Resources Residential lots sold 2,473 2,060 1,221 1,075 955 Commercial square footage sold, in millions 2.1 1.7 1.2 3.1 2.0 Multi-family units sold 273 950 - - -

Surplus (legacy) land sold, acres 9,087 5,088 10,982 11,402 8,562 14

CONSOLIDATED STATEMENTS OF OPERATIONS Years Ended December 31 (Inmillions, except per-share amounts) 2004- 2003 2002 Operating Revenues Non-regulated electric, natural gas, natural gas liquids and other i$ 14,275 -] $14,178 $ 8,780 Regulated electric 5,111 i 4,960 4,880 Regulated natural gas - 3,117 2,942 2,200 Total operating revenues 22,503 22,080 15,860 Operating Expenses - 1 5,360 Natural gas and petroleum products purchased S 11,335 11,419 5,360 Operation, maintenance and other -3,568 3,796 3,304 Fuel used inelectric generation and purchased power -2,098 2,075 2,191 Depreciation and amortization 1,851 1,792 1,506 Property and other taxes 539 526 533 Impairment and other related charges 65 2,956 364 Impairments of goodwill Ace 254 Total operating expenses j 19,456 22,818 13,258 Gains on Sales of Investments in Commercial and Multi-Family Real Estate .192 84 106 (Losses) Gains on Sales of Other Assets, net (225). (199) 32 Operating Income (Loss) 3,014 (853) 2,740 Other Income and Expenses Equity in earnings of unconsolidated affiliates 161 123 218 (Losses) Gains on sales and impairments of equity investments (4) 279 32 Other income and expenses, net 145 182 129 Total other income and expenses 302 584 379 Interest Expense 1,349 1,380 1,097 Minority Interest Expense v195. 61 116 Earnings (Loss) from Continuing Operations Before Income Taxes 1 772 (1,710) 1,906 Income Tax Expense (Benefit) from Continuing Operations 540 (707) 611 Income (Loss) from Continuing Operations l 1,232: (1,003) 1,295 Discontinued Operations  : .

Net operating loss, net of tax (10) (27) (261)

Net gain (loss) on dispositions, net of tax H268 (131)

Income (Loss) from Discontinued Operations 258 (158) (261)

Income (Loss) Before Cumulative Effect of Change in Accounting Principle -1,490=1 (1,161) 1,034 Cumulative Effect of Change inAccounting Principle, net of tax and minority interest it (162)

Net Income (Loss) [ 1,490 (1,323) 1,034 Dividends and Premiums on Redemption of Preferred and Preference Stock l 9 15 13 Earnings (Loss) Available for Common Stockholders i$ 1,481 $ (1,338) $ 1,021 Common Stock Data Weighted-average shares outstanding a-931 903 836 Earnings (Loss) per share (from continuing operations)

Basic 1.31 $ (1.13) $ 1.53 Diluted $ 1.27 $ (1.13) $ 1.53 Earnings (Loss) per share (from discontinued operations)

Basic $ 0.28 $ (0.17) $ (0.31)

Diluted $ 0.27 $ (0.17) $ (0.31)

Earnings (Loss) per share (before cumulative effect of change inaccounting principle)

Basic $ 1.59 $ (1.30) $ 1.22 Diluted $ 1.54r $ (1.30) $ 1.22 Earnings (Loss) per share Basic 1.59 $ (1.48)

$s 1.22 Diluted UE$ 1.54; $ (1.48) 1.22 Dividends per share j~t :1.10: $ 1.10 1.10 15

CONSOLIDATED BALANCE SHEETS December 31 (Inmillions) 2004 2003 ASSETS Current Assets Cash and cash equivalents $ 533 $ 397 Short-term investments 1,319 763 Receivables (net of allowance for doubtful accounts of $276 at 2004 and S280 at 2003) 3,237 2,953 Inventory 942 941 Assets held for sale 40 361 Unrealized gains on mark-to-market and hedging transactions 962 1,566 Other 938 694 Total current assets 7,971 7,675 Investments and Other Assets Investments in unconsolidated affiliates 1,292 1,398 Nuclear decommissioning trust funds 1,374 925 Goodwill 4,148 3,962 Notes receivable 232 260 Unrealized gains on mark-to-market and hedging transactions 1,379 1,857 Assets held for sale 84 1,444 Investments in residential, commercial and multifamily real estate (net of accumulated depreciation of $15 and $32 at December 31, 2004 and 2003, respectively) 1,128 1,353 Other 1,896 2,137 Total investments and other assets 11,533 13,336 Property, Plant and Equipment Cost 46,806 45,987 Less accumulated depreciation and amortization 13,300 12,139 Net property, plant and equipment 33,506 33,848 Regulatory Assets and Deferred Debits Deferred debt expense 297 275 Regulatory assets related to income taxes 1,269 1,152 Other 894 939 Total regulatory assets and deferred debits 2,460 2,366 Total Assets $ 55,470 $ 57,225 16

December 31 (Inmillions) Lw 200 4 - 2003 LIABILITIES AND COMMON STOCKHOLDERS' EQUITY Current Liabilities k Accounts payable [S 2,414; - $ 2,317 Notes payable and commercial paper [ 68 - 130 Taxes accrued

• 273 14 Interest accrued 287 304 Liabilities associated with assets held for sale - .30 651 Current maturities of long-term debt 1,832 1,200 Unrealized losses on mark-to-market and hedging transactions -819 1,283 Other I 1,815 - 1,849 Total current liabilities 1 7,538 7,748 Long-term Debt, including debt to affiliates of $876 at 2003 16,932 A 20,622 Deferred Credits and Other Liabilities ar e I l Deferred income taxes . -5,228 - 4,120 Investment tax credit 154 165 Unrealized losses on mark-to-market and hedging transactions 971 i 1,754 Liabilities associated with assets held for sale  ; -14 737 Asset retirement obligations - 1,926 i 1,707 Other 4,646 4,789 Total deferred credits and other liabilities 1 12,939-3 13,272 Commitments and Contingencies t Minority Interests 1,486 1,701 Preferred and Preference Stock without Sinking Fund Requirements - 134 134 Common Stockholders' Equity [

Common stock, no par, 2 billion shares authorized; 957 million and 911 million.

shares outstanding at December 31, 2004 and 2003, respectively - 11,252 9,519 Retained earnings - 4,539 - 4,060 Accumulated other comprehensive income 650. 169 Total common stockholders' equity 16,441 13,748 Total Liabilities and Common Stockholders' Equity [5 55,470. $ 57,225 17

CONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended December 31 (Inmillions) 2004 2003 2002 Cash Flows from Operating Activities Net income (loss) $ 1,490 $ (1,323) S 1,034 Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation and amortization (including amortization of nuclear fuel) 2,037 1,987 1,692 Cumulative effect of change inaccounting principle 162 Gains on sales of investments incommercial and multi-family real estate (201) (103) (106)

Gains on sales of equity investments and other assets (193) (86) (81)

Impairment charges 194 3,495 545 Deferred income taxes 867 (534) 495 Purchased capacity levelization 92 194 175 Contribution to company-sponsored pension plans (278) (192) (9)

(Increase) decrease in Net realized and unrealized mark-to-market and hedging transactions 216 (15) 596 Receivables (188) 1,126 12 Inventory (48) (30) 134 Other current assets (35) (77) (335)

Increase (decrease) in Accounts payable (5) (1,047) 798 Taxes accrued 188 (168) (332)

Other current liabilities 116 79 (194)

Capital expenditures for residential real estate (322) (196) (179)

Cost of residential real estate sold 268 167 117 Other, assets (305) (249) 205 Other, liabilities 246 206 (368)

Net cash provided by operating activities 4,139 3,396 4,199 Cash Flows from Investing Activities Capital expenditures, net of refund (2,055) (2,242) (4,745)

Investment expenditures (46) (153) (584)

Acquisition of Westcoast Energy Inc., net of cash acquired - - (1,707)

Purchases of available-for-sale securities (64,594) (40,032) (12,393)

Proceeds from sales and maturities of available-for-sale securities 64,092 39,641 11,859 Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable 1,542 1,966 516 Proceeds from the sales of commercial and multi-family real estate 606 314 169 Other (309) (162) (69)

Net cash used in investing activities (764) (668) 16,954)

Cash Flows from Financing Activities Proceeds from the:

Issuance of long-term debt 153 3,009 5,114 Issuance of common stock and common stock related to employee benefit plans 1,704 277 1,323 Payments for the redemption of:

Long-term debt (3,646) (2,849) (1,837)

Preferred stock of a subsidiary (176) (38)

Preferred and preference stock (88)

Guaranteed preferred beneficial interests in subordinated notes (250)

Notes payable and commercial paper (67) (1,702) (1,067)

Distributions to minority interests (1,477) 12,508) (2,260)

Contributions from minority interests 1,277 2,432 2,535 Dividends paid (1,065) (1,051) (938)

Other 19 23 64 Net cash (used in)provided by financing activities (3,278) (2,657) 2,846 Changes incash and cash equivalents associated with assets held for sale 39 (55)

Net increase in cash and cash equivalents 136 16 91 Cash and cash equivalents at beginning of year 397 381 290 Cash and cash equivalents at end of year S 533 S 397 S 381 Supplemental Disclosures Cash paid for interest, net of amount capitalized

$ 1,323 S 1,324 S 1,011 Cash (refunded) paid for income taxes (339) S (18) S 344 Significant non-cash transactions: $

Debt retired in connection with disposition of businesses 840 $ 387 S -

Note receivable from sale of southeast plants 48 $ $ -

Remarketing of senior notes 1,625 $ S -

Acquisition of Westcoast Energy Inc.

Fair value of assets acquired S 9,254 Liabilities assumed, including debt and minority interests

$ S 8,047 Issuance of common stock -

1,702 Capital lease obligations related to property, plant and equipment S 117 18

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)

Accumulated Other Comprehensive Income (Loss)

Net Gains Minimum Common Foreign (Losses) on Pension Stock Common Retained Currency Cash Flow Liability (Inmillions) Shares Stock Earnings Adjustments Hedges Adjustment Total Balance December 31, 2001 777 $ 6,217 $ 6,292 $(307) S 487 S - $12,689 Net income 1,034 1,034 Other Comprehensive Income Foreign currency translation adjustments (340) (340)

Net unrealized gains on cash flow hedgesb 37 37 Reclassification into earnings from cash flow hedgesc (102) (102)

Minimum pension liability adjustmentd (484) (484)

Total comprehensive income 145 Dividend reinvestment and employee benefits 13 342 342 Equity offering 55 975 975 Westcoast acquisition 50 1,702 1,702 Common stock dividends (905) (905)

Preferred and preference stock dividends (13) (13)

Other capital stock transactions, net 9 9 Balance December 31,2002 895 $9,236 $6,417 $ (647) $ 422 $(484) $14,944 Net loss (1,323) (1,323)

Other Comprehensive Loss Foreign currency translation adjustmentsa 986 986 Foreign currency translation adjustments reclassified into earnings as a result of the sale of European operations (24) (24)

Net unrealized gains on cash flow hedgesb 116 116 Reclassification into earnings from cash flow hedgesc (240) (240)

Minimum pension liability adjustmentd 40 40 Total comprehensive loss (445)

Dividend reinvestment and employee benefits 16 283 (6) 277 Common stock dividends (993) (993)

Preferred and preference stock dividends (15) (15)

Other capital stock transactions, net (20) (20)

Balance December 31, 2003 911 $9,519 $4,060 $ 315 $ 298 $ (444) $13,748 Net income 1,490 1,490 Other Comprehensive Income Foreign currency translation adjustments 279 279 Foreign currency translation adjustments reclassified into earnings as a result of the sale of Asia-Pacific Business (54) (54)

Net unrealized gains on cash flow hedgesb 311 311 Reclassification into earnings from cash flow hedgesc (83) (83)

Minimum pension liability adjustmentd 28 28 Total comprehensive income 1,971 Dividend reinvestment and employee benefits 5 108 20 128 Equity offering 41 1,625 1,625 Common stock dividends (1,018) (1,018)

Preferred and preference stock dividends (9) (9)

Other capital stock transactions, net (4) (4)

Balance December 31, 2004 957 $11,252 $4,539 $ 540 $ 526 $(416) $16,441 a Foreign currency translation adjustments, net of S114 tax benefit in 2003 b Net unrealized gains on cash flow hedges, net of $170 tax expense in 2004, $49 tax expense in 2003 and S72 tax expense in 2002 c Reclassification into earnings from cash flow hedges, net of $45 tax benefit in 2004, $130 tax benefit in 2003 and $94 tax benefit in 2002 d Minimum pension liability adjustment, net of $18 tax expense in 2004, S27 tax expense in 2003 and $309 tax benefit in 2002 19

NON-GAAP FINANCIAL MEASURES Pages 1 and 4 of the Chairman's letter reference a 2004 ongoing basic earnings-per-share goal of $1.20, which we beat by 18 cents. Page 4 of the Chairman's letter also references the 2005 ongoing basic earnings-per-share target of $1.60. Ongoing basic earnings per share is a non-GAAP (generally accepted accounting principles) financial measure because it excludes the per-share effects of any 'special items," which represent certain income or charges which management believes will not be recurring on a regular basis. The most directly comparable GMP measure is basic earnings per share.

Information to reconcile the 2005 ongoing basic earnings-per-share target to the most directly comparable GMP financial measure is not available at this time, as management is unable to project special items for 2005. The following is a reconciliation of ongoing to reported basic earnings per share for 2004:

Ongoing Basic Earnings per Share - 2004 (Inmillions, except earnings per share)

Pre-tax Tax Basic EPS Amount Effect Impact Ongoing Basic Earnings per Share $ 1.38 Net gain on sale of discontinued operations (net of minority interest of S7 million) $ 278 S 116) 0.28 Net loss on asset sales, primarily sale of southeast U.S. plants (including minority interest benefit of S25 million) (206) 72 (0.14)

Impairments and other related charges (net of minority interest of S12 million) (25) 9 (0.02)

Litigation reserves and settlements (net of minority interest of $5 million) and contract termination charges (5) 2 0.00 Tax benefit from restructuring _ 48 0.05 Adjustment to captive insurance reserve 64 (22) 0.04 Net loss on sales of equity investments (including minority interest benefit of $7 million) and loss on asset exchanges (8) 3 0.00 Total basic earnings-per-share impact of special items 0.21 Basic Earnings per Share, as Reported S 1.59 Page 1 of the Chairman's letter references a debt reduction of $4.6 billion. This amount represents a non-GAAP measure because it includes changes in amounts presented in the Consolidated Balance Sheets as other than "debt," including amounts classified as "liabilities associated with assets held for sale" and "minority interests." The following is a reconciliation of the

$4.6 billion to the changes in the amounts reported in the Consolidated Balance Sheets as 'debt":

Reconciliation of Debt Paydown to Consolidated Balance Sheets - 2004 (Inmillions) 12/31/03 12/31/04 Difference Long-term debt $20,622 S16,932 $ (3,690)

Current maturities of long-term debt and preferred stock 1,200 1,832 632 Notes payable and commercial paper 130 68 (62)

Total Debt 21,952 18,832 (3,120)

Changes due to foreign currency (300)

Other cash changes (89)

Sub-total (389)

Redeem Australia debt (890)

Redeem Westcoast Energy, Inc. preferred securities (176)

Total Change $(4,575)

Total debt paydown disclosed S (4,600) 20

Page 1 of the Chairman's letter references $3.1 billion of proceeds from asset sales in 2004. This amount represents a non-GAAP measure because it includes amounts that are presented in the Consolidated Statements of Cash Flows as other than net 'proceeds from sales of equity investments and other assets, and sales of and collections on notes receivable," including $750 million of tax benefits and $840 million of non-cash debt reductions.

The Financial Highlights on page 2 include amounts for "earnings (loss) before interest and taxes from continuing operations."

This non-GAAP measure represents the combination of "operating income (loss)" and "other income and expenses" as presented in the Consolidated Statements of Operations, and it excludes results and impacts from discontinued operations.

Page 3 of the Chairman's letter mentions a 2004 contribution from Crescent Resources of more than $440 million. This amount represents the cash that Crescent Resources generated from its operating and investing activities and contributed to Duke Energy.

In this report, for certain segments we use ongoing segment EBIT (earnings before interest and taxes) as a measure of historical and anticipated future performance. For some segments we also use a forecasted ongoing segment EBIT growth rate, which is based on historical and forecasted ongoing segment EBIT, as an indicator of anticipated future compound annual growth rates.

When used for future periods, ongoing segment EBIT may also include amounts that may be reported as discontinued operations.

Ongoing segment EBIT and related growth rates are non-GMP financial measures because they represent reported segment EBIT adjusted for special items. The most directly comparable GAAP measure for ongoing segment EBIT is reported segment EBIT, which represents EBIT from continuing operations, including any special items.

For future periods, information to reconcile ongoing segment EBIT and related growth rates to the most directly comparable GAAP financial measures is not available at this time, as management is unable to forecast special items or amounts that may be reported as discontinued operations. The following is a reconciliation of ongoing segment EBIT to reported segment EBIT for 2004:

Reconciliation of Ongoing to Reported Segment EBIT - 2004 (Inmillions)

Special Items Gains Gains (Losses) on Impairment Enron/

Ongoing (Losses) on Sales of and Other Early Contract California Reported Segment Sales of Equity Related Termination Settlements, Segment EBIT Assets Investments Charges Charges net Total EBIT Earnings Before Interest and Taxes from Continuing Operations Duke Energy North America $(288) $(228)a $- $ (2) $(20)b $3bc $(247) $(535)

International Energy 236 (2) 1 (13)b - - (14) 222 a Net of minority interest benefit of $26 million b Recorded in operation and maintenance expense c Net of minority interest of S5 million 21

BOARD OF DIRECTORS (Left to right) Robert J. Brown, George Dean Johnson Jr., G.Alex Bernhardt Sr., A. Max Lennon, Paul M.Anderson, Roger Agnelli, James T. Rhodes BOARD MEMBERS Roger Agnelli, 45, President and Chief Executive Officer, Robert J. Brown, 70, Chairman and Chief Executive Officer, Companhia Vale do Rio Doce (CVRD), Brazil. Compensation B&C Associates Inc. Audit Committee. Corporate Governance Committee. Finance and Risk Management Committee. Committee. Director since 1994. Brown founded B&C Director since 2004. Agnelli leads CVRD, a global mining Associates Inc., a marketing research and public relations firm company and the world's largest producer of iron ore. For in High Point, N.C. He serves on the Board of Trustees of the several years he held various positions at Bradesco, a National Urban League. Brown will retire from the Duke Energy Brazilian financial conglomerate. Agnelli joined Duke Energy's Board of Directors at the 2005 Annual Meeting.

Board of Directors in November 2004.

William T. Esrey, 65, Chairman Emeritus, Sprint Corp. Chair, Paul M. Anderson, 59, Chairman of the Board and Chief Audit Committee. Director since 1985. Esrey joined Sprint in Executive Officer, Duke Energy. Director since 2003. 1980, and went on to serve as the company's chief financial Anderson rejoined Duke Energy in 2003, having served as its officer, president, chief executive officer and chairman.

first president and chief operating officer in 1997 and 1998, He also served as chairman of Japan Telecom from 2003 and with Duke Energy predecessor companies since 1977. to 2004.

He retired as managing director and chief executive officer of Australia-based BHP Billiton Ltd. in 2002. Ann Maynard Gray, 59, Former President, Diversified Publishing Group of ABC Inc. Lead Director. Chair, Corporate G. Alex Bernhardt Sr., 62, Chairman and Chief Executive Governance Committee. Compensation Committee. Finance Officer, Bemhardt Fumiture Co. Audit Committee. Nuclear and Risk Management Committee. Nuclear Oversight Oversight Committee. Director since 1991. Besides leading Committee. Director since 1994. At American Broadcasting the family business in Lenoir, N.C., Bernhardt serves as a Companies Inc., Gray also held positions as treasurer and vice director of Cities in Schools and Smart Start, and on the president of planning. She currently serves as a trustee Davidson College Board of Trustees. for J.P. Morgan Funds.

22

(Left to right) Leo E. Linbeck Jr., Ann Maynard Gray, Michael E.J. Phelps, William T.Esrey, James G.Martin, Dennis R.Hendrix Dennis R. Hendrix, 65, Retired Chairman of the Board, James G. Martin, 69, Corporate Vice President, Carolinas PanEnergy Corp. Compensation Committee. Finance and HealthCare System. Chair, Compensation Committee.

Risk Management Committee. Director since 2004. Hendrix Corporate Governance Committee. Nuclear Oversight rejoined the Board of Directors in December 2004. He was Committee. Director since 1994. Martin was governor of the chairman of the board of PanEnergy Corp prior to the 1997 state of North Carolina from 1985 to 1993, and previously merger of Duke Power and PanEnergy. served as a U.S. congressman. He is chairman of the Global TransPark Foundation Inc.

George Dean Johnson Jr., 62, Owner, Johnson Development Associates Inc. Finance and Risk Management Committee. Michael E.J. Phelps, 57, Chairman, Dornoch Capital Inc.

Director since 1986. Johnson was formerly chief executive Chairman, Duke Energy Canadian Advisory Council. Chair, officer and director of Extended Stay America Inc. He served Finance and Risk Management Committee. Corporate in the S.C. House of Representatives and as a director of the Governance Committee. Director since 2002. Phelps is Federal Reserve Bank of Richmond. Johnson will retire from former chairman of the board and chief executive officer of the Duke Energy Board of Directors at the 2005 Annual Meeting. Westcoast Energy Inc., acquired by Duke Energy in 2002.

A. Max Lennon, 64, President, Education and Research James T. Rhodes, 63, Retired Chairman, President and Services. Audit Committee. Director since 1988. Lennon is a Chief Executive Officer, Institute of Nuclear Power Operations.

former president of Clemson University and Mars Hill College. Chair, Nuclear Oversight Committee. Audit Committee.

He also served as president and chief executive officer of Director since 2001. Rhodes was formerly president and Eastern Foods Inc. chief executive officer of Virginia Power. He is a member of the Advisory Council of the Electric Power Research Institute.

Leo E. Linbeck Jr., 70, Senior Chairman, Linbeck Corp.

Compensation Committee. Finance and Risk Management Committee. Director since 1986. Linbeck Corp. is a group of four construction-related firms headquartered in Houston, Texas. Linbeck is past chairman and director of the Federal Reserve Bank of Dallas. He will retire from the Duke Energy Board of Directors at the 2005 Annual Meeting.

23

EXECUTIVE MANAGEMENT 2004 Executive Committee (left to right): A.R. Mullinax, Fred Fowler, Martha Wyrsch, Jim Mogg, Paul Anderson, David Hauser, Julie Dill, Rich Osborne EXECUTIVE COMMITTEE EXPANDED EXECUTIVE COMMITTEE Duke Energy's Executive Committee is Jim W.Mogg, Group Vice President and The Expanded Executive Committee responsible for driving a strategy that Chief Development Officer. Mogg oversees includes the Executive Committee members generates shareholder value by providing a strategy and corporate transactions, corpo- as well as the heads of the major business stable platform for growth and continued rate and human resources development, units. This group is responsible for corpo-profitability. This group develops corporate mergers and acquisitions, diversity and the rate policies and programs that reach strategy, allocates capital, outlines enter- company's real estate affiliate. across the business units.

prise goals, implements Board direction, A.R. Mullinax, Group Vice President (Pictured on page 6) and in general leads the enterprise.

and Chief Information Officer. Mullinax William H. Easter 111, Chairman, President Paul M. Anderson, Chairman of the Board leads information technology and is and Chief Executive Officer, Duke Energy and Chief Executive Officer. Anderson has responsible for global sourcing and Field Services. Easter leads the company's lead responsibility for positioning Duke logistics, corporate real estate services natural gas gathering and processing and Energy as a company that achieves superior and human resources services. natural gas liquids business.

results, focusing the organization on its vision and purpose, improving execution Richard J. Osborne, Group Vice Robert B. Evans, President and Chief and ensuring clear accountability. He chairs President, Public and Regulatory Policy. Executive Officer, Duke Energy Americas.

the Executive Committee and the Expanded Osborne has responsibility for Duke Evans is responsible for Duke Energy's Executive Committee. Energy's public policy agenda and North American and Latin American whole-relationships with regulators, legislators, sale energy generation business.

Fred J. Fowler, President and Chief communities and other key stakeholders.

Operating Officer. Fowler chairs Duke Thomas C. O'Connor. O'Connor served Energy's Enterprise Performance Martha B. Wyrsch. Wyrsch served as as president and chief executive officer Committee, with responsibility for the group vice president, general counsel and of Duke Energy Gas Transmission until operational, commercial and financial results secretary until March 1, 2005, when she March 1, 2005. He will have responsibilities of the company's energy-related businesses. became president and chief executive for corporate strategy upon his completion officer of Duke Energy Gas Transmission. of Harvard University's Advanced David L. Hauser, Group Vice President Management Program, and will be joining and Chief Financial Officer. Hauser is Julie A. Dill, Secretary to the Executive the Executive Committee later in2005.

responsible for treasury, accounting, tax Committee and Vice President, Investor and and risk management. His duties include Shareholder Relations. Dill is responsible for Ruth G. Shaw, President and Chief certifying financial statements and over- relationships and communication with the Executive Officer, Duke Power Company.

seeing risk control policies and systems. investment community, and for monitoring Shaw oversees the electric utility that changes and trends in investment markets. serves more than 2 million customers in North Carolina and South Carolina.

24

INVESTOR INFORMATION I I - I I Annual Meeting InvestorDirect Choice Plan Transfer Agent and Registrar.

The 2005 Annual Meeting of Duke The InvestorDirect Choice Plan provides Duke Energy maintains shareholder Energy Shareholders will be: a simple and convenient way to purchase records and acts as~transfer agent and Date: Thursday, May 12, 2005 common stock directly through the ~registrar for the coripany's common .and Time: 10 a.m. company, without incurring brokerage *preferred stock issues. .

Place: O.J. Miller Auditorium, fees. Purchases may be made weekly.

Energy Center Bank'drafts for monthly purchases, as Dividend Payment 526 South Church Street well as a safekeeping option for deposit- Duke Energy has paid quarterly cash Charlotte, NC 28202 ing certificates into the plan, are dividends on its comMon stock for available. The plan also provides for - 78 consecutive yea~rs. Dividends on Shareholder Services full reinvestment,-direct deposit or -common and preferred stock are Shareholders may call (800) 488-385;3 cash payment of dividends. Additionally, expected to be paid, subject to'declara-'

or (704) 382-3853 with questions 'abc)ut participants may register for DUK-Online. tion by the Board of Directors, on March their stock accounts, legal transfer 16, June 16, Sept. 16 and Dec: 16, requirements, address changes, repla ce- Financial Publications 2005L ment dividend checks, replacement Duke Energy will furnish to any share-of lost certificates or other services; holder, without charge,' printed copies Bond Trustee Additionally, registered users of of the 2004 Summary Annual Report *ifyou have questions regarding your

'DUK-Online, our online account and SEC Form' 10-K. Those and other bond account, call (800) 275-2048, or management service, may access financial publications can also write to:

their ~accounts through the Internet.. be found on our Web site at 'JPMorgan Chase bank Send written requests to: www.duke-energy.com/investors. Institutional T-rust Services Investor Relations, -PO. Box 2320 Duke Energy Electronic Delivery, DalsTX 7522 1-2320 P.O. Box 1005 With a shareholder's consent, we can Charlotte, NC 28201-1005 stop mailing paper copies of financial We welcome your opinion on Duke For electronic correspondence, pleasi information and proxy statements. You Energy's 2004 AnnualReport. Please visit go0 to ' MContact Investor Relations' at: can go to www.icsdelivery.com/duk to www.duke-energy corrvinvestors, where you-www.duke-energy.com/investors. enroll in electronic delivery. You will need can view the online Annual Report and provide to provide your Social Security number feedback on both the print and online versions.

Stock Exchange Listing or Tax I.D.- number, your emil address, Or contact Investor Relations directly.

andPINnumer ofyur chie for Duke Energy's common stock and cer tain is-sues of first and refunding Mort

• electronic voting. Duke Energy isan equ~al opportunity emplo-yer.

gage bonds, preferred securities and This report is published solely to inform share-senior notes are'listed on the New Yoirk Duplicate Mailings holders -and is not to be considered an offer, Stock Exchange.-The company's corn

• If your shares are registered in different or the solicitation of an offer, to buy or sell

• mon stock trading symbol is DUK. accounts, you may receive duplicate securities. This report was printed inthe USA mailings .of annual reports, proxy* on recycled paper.

Web Site Addresses Corporate home page:.

www~duke]-energy.com statements and other shareholder information; Call Investor Relations for instructions on eliminating duplications

©o Investor Relations: or combining your accounts.

www.duke-energy-com/nnVestors

25

Duke E Energy.

526 South Church Street Charlotte, NC 28202-1802 704.594.6200 www.duke-energy.com

Grant Thornton S Financial Statements and Report of Independent Certified Public Accountants North Carolina Electric Membership Corporation As of December 31, 2004, 2003 and 2002

North Carolina Electric Membership Corporation Table of Contents Report of Independent Certified Public Accountants ......................................... 1-2 Financial Statements:

Balance Sheets ..................................... 3 Statements of Operations and Members' Equity .......................................... 4 Statements of Cash Flows ......................................... 5 Notes to Financial Statements ......................................... 6-21

Grant Thornton Mr Accountants and Business Advisors REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS To the Board of Directors of North Carolina Electric Membership Corporation:

We have audited the accompanying balance sheets of North Carolina Electric Membership Corporation, a North Carolina corporation, as of December 31, 2004 and 2003, and the related statements of operations and members' equity and cash flows for the years ending December 31, 2004, 2003 and 2002. 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.

NWe conducted our audits in accordance with auditing standards generally accepted in the United States of America as established by the Auditing Standards Board of the American Institute of Certified Public Accountants and the standards applicable to financial audits contained in Goz'ernmentAuditin~gStandardsissued by the Comptroller General of the 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements and 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, the financial statements referred to above present fairly, in all material respects, the financial position of North Carolina Electric Membership Corporation as of December 31, 2004 and 2003, and the results of its operations and its cash flows for the years ending December 31, 2004, 2003 and 2002, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note A to the financial statements, the Company changed its method of accounting for asset retirement obligations as ofJanuary 1, 2003.

4140 ParkLake Avenue Suite 130 Raleigh, NC 27612 www.grantthornton.com Grant Thornton LLP US Member of Grant Thornton Intemational

Grant Thornton sr In accordance with GovernmenftAuditing Standards, we have also issued a report dated February 18, 2005, on our consideration of North Carolina Electric Membership Corporation's internal control over financial reporting and our tests of its compliance with certain provisions of laws, regulations, contracts, grant agreements and other matters. The purpose of that report is to describe the scope of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on the internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with GovernmentAuditing Standards and should be read in conjunction with this renort in considering the results of our audit.

C ~ C)<.MTOA6 god Raleigh, North Carolina February 18, 2005

'1  % I. k North Carolina Electric Membership Corporation Balance Sheets December 31, 2004 and 2003 (in thourands)

Assets 2004 2003 Members' Equity and Liabilities 2004 2003 Electric plant: Members' equity:

In-service $1,457,854 $1,493,746 Membership fees $ 1 S I Accumulated depreciation (742,008) (730,892) Patronage capital 22,112 22,112 715,846 762,854 Net unrealized gain on available-for-sale securities 4,555 7,269 Nuclear fuel, at amortized cost 29,103 32,761 26,668 29,382 Construction work-in-process 14,894 1,083 759,843 796,698 Other assets and investments: Long-term debt 848,411 896,060 Long-term investments 37,785 38,603 Noncurrent receivables 15,310 16,608 Investments in associated organizations 7,490 7,469 Special deposits 31,091 30,115 Decommissioning fund 75,661 72,069 Current liabilities:

167,337 164,864 Current maturities of long-term debt 59,062 45,113 Current assets: Accounts payable 67,580 61,018 Cash and cash equivalents 17,700 11,000 Accrued interest 13,392 155 Short-term investments 7,009 8,747 Other accrued expenses 13,468 11,785 Accounts receivable 115,964 105,484 153,502 118,071 Accounts receivable - Affiliated companies, net 595 1,244 Interest receivable 941 1,073 Other current assets 15,821 21,773 158,030 149,321 Deferred credits and other liabilities:

Deferred charges:

Asset retirement obligation (Note A) 103,088 128,618 Regulatory asset (Note A) 29,058 37,100 Deferred loss on debt extinguishment (Note F) Accrued Department of Energy assessment 2,546 3,078 13,347 14,719 Other noncurrent liabilities 8,673 4,975 Debt issuance costs 6,173 6,651 Preliminary project costs 7,418 7,418 114,307 136,671 Other 1,682 3,413 Commitments and contingencies 57,678 69,301 (Notes G, H. 1, J and K)

$1,142,888 $1,180,184 $1,142,888

=

$1,180,184

=

The accompanying notes are an integral part of these financial statements.

Page 3

North Carolina Electric Membership Corporation Statements of Operations and Members' Equity For the Years Ended December 31, 2004, 2003 and 2002 (in thomsands) 2004 2003 2002 Operating revenues $802,733 $772,519 $749,200 Operating expenses:

Fuel and purchased power 561,725 526,145 515,071 Other production expenses 114,764 114,176 104,104 Depreciation and amortization 45,921 45,718 38,956 Administrative and general 16,541 18,927 19,588 General taxes 11,796 11,709 11,633 750,747 716,675 689,352 Operating margin 51,986 55,844 59,848 Other income:

Interest and dividend income 5,979 5,393 3,735 Other 1,022 121 333 7,001 5,514 4,068 Interest charges:

Interest expense 56,673 59,059 61,637 Debt fees and expenses 2,314 2,299 2,279 58,987 61,358 63,916 Net margin 0 0 0 Change in net unrealized gain on available-for-sale securities (2,714) 4,385 2,829 Comprehensive (loss) income (2,714) 4,385 2,829 Members' equity, beginning of year 29,382 24,997 22,168 Members' equity, end of year $ 26,668 $ 29,382 $ 24,997 The accompanying notes are an integral part of these financial statements.

Page 4

North Carolina Electric Membership Corporation Statements of Cash Flows For the Years Ended December 31, 2004, 2003 and 2002 (in thousands) 2004 2003 2002 Cash flows from operating activities:

Net margin $ 0 $ 0 $ 0 Adjustments to reconcile net margin to net cash and cash equivalents provided by operating activities:

Depreciation and amortization 45,921 45,718 38,956 Other amortization 5,023 5,335 1,207 Amortization of nuclear fuel 14,623 16,775 14,928 Interest on decommissioning fund 0 0 237 Deferred charges (1,180) (5,536) 22,889 Other noncurrent assets and liabilities 4,996 3,089 4,381 Changes in other operating assets and liabilities:

Accounts receivable (9,831) 17,014 (17,245)

Interest receivable 132 (242) 204 Accounts payable 6,562 10,057 10,538 Accrued interest 13,237 24 (43)

Wholesale power cost adjustment 5,218 (17,896) (2,603)

Other 277 236 369 Net cash and cash equivalents provided by operating activities 84,978 74,574 73,818 Cash flows from investing activities:

Additions to electric plant (41,439) (30,223) (20,876)

Increase in decommissioning fund (3,746) (8,661) (237)

Decrease (increase) in long-term investments 472 (3,451) (2,328)

Decrease (increase) in short-term investments 1,657 4,101 (2,156)

Other, net (1,522) (1,716) (4,495)

Net cash and cash equivalents used in investing activities (44,578) (39,950) (30,092)

Cash flows from financing activities - Principal payments of long-term debt (33,700) (42,560) (40,458)

Net increase (decrease) in cash and cash equivalents 6,700 (7,936) 3,268 Cash and cash equivalents, beginning of year 11,000 18,936 15,668 Cash and cash equivalents, end of year $17,700 $11,000 $18,936 Supplemental disclosures of cash flow information:

Transfer of intercompany accounts receivable from current to noncurrent:

Accounts receivable, affiliated companies, net $ 0 $ (8,605) $ 0 Noncurrent receivables 0 8,605 0 Implementation of FAS 143:

(Disposal) addition of decommissioning asset (26,206) 28,824 0 Increase (decrease) in deferred credits and other liabilities 32,003 (63,283) 0 (Decrease) increase in regulatory asset (5,797) 34,999 0 Reclass of other noncurrent liabilities:

Preliminary project costs 0 (2,000) 0 Other noncurrent liabilities 0 2,000 0 Cash paid during the year for:

Interest 43,435 59,036 61,680 Income taxes 0 0 0 The accompanying notes are an integral part of these financial statements.

Page 5

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 Note A - Summary of Significant Accounting Policies Basis of Accounting North Carolina Electric Membership Corporation (the Company) is a member-owned cooperative of 26 electric membership cooperatives (the members) in North Carolina. The Company was formed in 1949 to develop itself as a full-requirements supplier, providing power generation, wholesale electric service and transmission to its members, who in turn service more than 860,000 homes, farms and businesses in North Carolina. The Company follows accounting principles generally accepted in the United States of America and the practices prescribed in the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC) as modified and adopted by the Rural Utilities Service (RUS). Effective January 1, 2004, four members elected to independently obtain their future power supply resources. Another member elected to independently obtain its future power supply resources, effective May 1, 2005, or a later date to be mutually agreed upon by the parties. See the Member Power Supply Resource Policy for further discussion.

Electric Plant Electric plant is stated at original cost, which is the cost of the plant when placed into service plus the cost of subsequent additions and includes engineering and other indirect construction costs. The cost of renewals and betterments of property is capitalized. The cost of maintenance and repairs and replacements and renewals of items determined to be less than units of property is charged to expense when incurred. At the time properties are disposed of, the original cost plus the cost of removal less salvage of such property is charged to accumulated depreciation, except in certain cases of properties sold as entireties where profit or loss is recognized.

Depreciation and Decommissioning Depreciation is computed using the straight-line method over the estimated service lives of the property as follows:

Estimated Lives Catawba Nuclear Station (Catawba) 23-40 years Diesel generation equipment 30 years Load management equipment 15 years Building and improvements 35 years Furniture and fixtures 5-10 years Computers and telecommunications equipment 3-10 years Vehicles 4 years The Company reviews its long-lived assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If this review indicates that the asset will not be recoverable based on the expected undiscounted net cash flows of the related asset, an impairment loss is recognized and the asset's carrying value is reduced. No such impairment loss was recognized in 2004, 2003 or 2002.

Page 6

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 The estimate of the expected cost for decommissioning is adjusted periodically to reflect changing price levels and technology. Using a 1999 site study of expected decommissioning costs, including the costs of decontamination, dismantling and site restoration, the Company estimated its portion of such costs to be approximately $246,224,000 in 1999 dollars. The decommissioning cost estimates are based on the plant location and cost characteristics for Catawba and assume prompt dismantlement and removal of the plant from service.

The actual decommissioning costs are expected to vary from the above estimates because of changes in assumed dates of decommissioning, changes in regulatory requirements, changes in technology and changes in costs of labor, materials and equipment.

The Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations," on January 1,2003, to provide for the expected cost of decommissioning Catawba. SFAS No. 143 establishes accounting and reporting standards for the way companies recognize and measure retirement obligations that result from the operation of a long-lived asset. SPAS No. 143 requires that the fair value of asset retirement obligations be recorded in the balance sheet at the time the liability is incurred which, in most cases, will be when the asset is placed in service. The cost associated with recognizing this obligation is capitalized into the cost of the related long-lived asset. The implementation of SPAS No. 143 on January 1, 2003, resulted in a cumulative effect of a change in accounting principle of $34,999,000, which was recorded as a regulatory asset and was to be amortized over the remaining life of Catawba. Additionally, implementation resulted in a net increase in Electric Plant of $28,824,000 and an increase in deferred credits and other liabilities of $63,823,000. In compliance with a Nuclear Regulatory Commission (NRC) regulation, amounts recovered through rates for estimated decommissioning costs (plus interest thereon) are maintained in a separate external trust fund.

In November 2003, the NRC extended the licenses for Catawba through December 31, 2043. As such, in 2004, the Company received an updated site study that included consideration of the extended licenses for Catawba.

Using this study, the Company estimates its portion of expected decommissioning costs to be approximately

$281,056,000 in 2003 dollars. The new study resulted in a change in accounting estimate of $5,797,000, which was recorded as a reduction to the regulatory asset, which will continue to be amortized over the remaining life of Catawba. In addition, the new study resulted in a net decrease in Electric Plant of $26,206,000 and a decrease in asset retirement obligation of $32,003,000.

Regulatory Assets and Deferred Charges The Company currently complies with the provisions of SPAS No. 71, "Accounting for the Effects of Certain Types of Regulation," as amended and, accordingly, has recorded regulatory assets related to its operations. This statement requires that regulatory assets be probable of future recovery at each balance sheet date. If recovery of the regulatory assets becomes unlikely or uncertain, these accounting standards may no longer apply. The Company periodically reviews these criteria to ensure the continuing application of SPAS No. 71 is appropriate.

Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, the Company believes that its regulatory assets are probable of future recovery.

Page 7

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 Deferred charges, other than preliminary project costs (Note I), are amortized using the straight-line method over the following estimated periods:

Estimated Periods Regulatory asset 1-23 years Deferred loss on debt extinguishment (Note F) 15-24 years Debt issuance costs 19-24 years Other 1-5 years Nuclear Fuel The cost of nuclear fuel, including a provision for the estimated cost of permanent storage of spent fuel, is being amortized based on core burn-up and amounted to $14,623,000 in 2004, $16,775,000 in 2003 and $14,928,000 in 2002. Final disposition of the spent fuel may require future adjustments to fuel expense. Pending ultimate disposition, sufficient storage capacity for spent fuel is available through 2008. The accumulated amortization is

$131,445,000 and $116,822,000 at December 31, 2004 and 2003, respectively.

Derivative Accounting Tihe Company complies with the provisions of SEAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SEAS No. 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. SEAS No. 133 requires that certain derivative instruments be recorded in the balance sheet as either an asset or liability measured at fair value and that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

Substantially all of the Company's bulk powver purchases and sales meet the definition of a derivative under SEAS No. 133. IHowever, these transactions also meet the normal purchase and sale exception under SFAS No. 133 and, therefore, do not need to be accounted for as derivatives.

In addition, the Company uses derivative instruments to manage the risks associated with the impact of fluctuating natural gas fuel prices on purchased powver contracts. These derivatives are carried at their fair market value as determined by broker quotes. Unrealized gains are recorded as derivative assets of $382,000 and

$1,071,000 in other current assets in the accompanying balance sheets at December 31, 2004 and 2003, respectively. Unrealized losses of $1,625,000 and $173,000 are recorded as derivative liabilities in other accrued expenses in the accompanying balance sheets at December 31, 2004 and 2003, respectively. As these derivatives are designated as cash flow hedges, gains or losses are deferred as a component of members' equity- and will be recognized concurrently with the hedged purchased power costs.

Membership Fees and Patronage Capital The Company is organized and operates as a cooperative. Its cooperative members paid a total of $700 in membership fees.

Page 8

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 Patronage capital is the net margin retained by the Company, which is allocated to members based upon their respective purchases of power from the Company.

Income Taxes The Company is a not-for-profit membership corporation exempt from federal income taxes. In management's opinion, based on the applicable statutes, the Company is not subject to state income taxes.

For the years 1984 and prior, the Company claimed tax-exempt status under Section 501(c)(12) of the Internal Revenue Code of 1954 (the Code), as amended. In 1985, the Company reported as a taxable entity as a result of income received from Duke Power Company (Duke) under a capacity and energy sell-back agreement applicable to Catawba Units No. 1 and 2. As a taxable electric cooperative, the Company annually allocated its income and deductions between member and nonmember activities. Any member taxable income was offset with a patronage exclusion.

In 1999, the Company reapplied for tax-exempt status under Section 501(c)(12) of the Code. The application was approved by the Internal Revenue Service retroactively to January 1, 1996.

Cash and Cash Equivalents The Company considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.

Revenue Recognition The Company recognizes revenue on the sale of power when supplied to members. Amounts for which revenue has been billed and not collected are included as accounts receivable in the accompanying balance sheets.

Accounts receivable are due within 60 days and are stated as amounts due from members net of an allowance for doubtful accounts. Accounts outstanding longer than the payment terms are considered past due. No provision for doubtful accounts was recorded during the years ended December 31, 2004, 2003 and 2002.

The Company implemented a wholesale power cost adjustment in 2002 as a means of collecting monthly costs in excess of budget amounts or returning monthly revenue in excess of budget amounts. The wholesale power cost adjustment is returned to or collected from the members over the six-month period following the month in which the variance occurred. During 2004 and 2003, the Company incurred costs in excess of budget of

$39,854,000 and $39,027,000, respectively. Of the 2004 amount, $24,572,000 ,vas collected from the members in 2004 and $15,282,000 was recorded as other current assets at December 31, 2004, to be collected in 2005. Of the 2003 amount, $18,528,000 wvas collected from members in 2003 and $20,499,000 was recorded as other current assets at December 31, 2003, and collected in 2004.

Page 9

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 Member Power Supply Resource Policy In February 1998, the Company adopted a policy allowing members to independently procure a portion of their future wholesale power supply if they so desired. The policy was revised in 2002 and 2003 to reflect changes in the marketplace. In June 2003, four members (Independent Members) elected to exercise their rights consistent with the policy to independently arrange for future purchases of capacity and energy. Each of the four members executed a wholesale powver supply agreement with the Company effective January 1, 2004, that will remain in effect until December 31, 2026. The Independent Members continue to be responsible for their share of capacity and energy commitments made by the Company prior to January 1, 2004. In 2004, another member elected to exercise its rights to independently arrange for future purchases of capacity and energy. This agreement will become effective May 1, 2005, or at a later date to be mutually agreed upon by the parties. The new Independent Member will continue to be responsible for its share of capacity and energy commitments as agreed upon by the parties.

Concentration of Credit Risk One member accounted for approximately 9.2%, 12.9% and 12.9% of revenues during 2004, 2003 and 2002, and 6.4%, 8.9%, 13.6% of accounts receivable at December 31, 2004, 2003 and 2002, respectively.

Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Reclassifications Certain reclassifications have been made to the prior-year financial statements to conform to the current-year presentation.

Recent Accounting Pronouncements In Mlay 2003, the Financial Accounting Standards Board (FASB) issued SEAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity," effective for financial instruments entered into or modified after May 31, 2003, and otherwise effective at the beginning of the first interim period beginning afterJune 15, 2003, except for mandatorily redeemable financial instruments of nonpublic entities.

The application of this statement has been indefinitely deferred for nonpublic entities with mandatorily redeemable financial instruments. This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The Company does not believe that it will be affected by this statement.

Page 10

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 In Mlay 2003, the Emerging Issues Task Force (EITF) issued EITF Abstract No. 01-8, "Determining Whether an Arrangement Contains a Lease," effective for agreements entered into or modified after the beginning of the first fiscal period subsequent to May 28, 2003. This abstract establishes criteria for determining whether an agreement which has fixed supply requirements, called "Take-or-Pay contracts," or agreements which provide one party with the right to use property, plant and equipment qualify as lease agreements. The Company is not affected by this abstract.

Note B - Jointly Owned Electric Plant and Related Agreements On February 6, 1981, the Company entered into (a) the Catawba Nuclear Station Purchase, Construction and Ownership Agreement with Duke, together with (b) an Operating and Fuel Agreement and (c) an Interconnection Agreement (the Contracts). Contracts (a) and (b) basically provide for the purchase by the Company of a 56.25% undivided interest in Unit No. 1 of the Catawba Nuclear Station together with a 28.125%

interest in the support facilities and for a sharing of direct construction and operating costs in relation to the respective ownership share of the parties. The Company's total investment in jointly owned facilities totaled

$1,386,272,000 and $1,372,064,000, including capitalized interest expense net of related investment income, and is included in electric plant in-service in the accompanying balance sheets as of December 31, 2004 and 2003, respectively.

The cost of power purchased from Duke, as well as power purchased by the Company from other powver supply sources, including Carolina Power & Light doing business as Progress Energy Carolinas, Inc. (CP&L), Dominion North Carolina Power (VEPCO) and American Electric Power Company (AEP) has been recorded as purchased powver on the accompanying statements of operations and members' equity.

Note C - Fair Value of Financial Instruments A detail of the estimated fair values of the Company's financial instruments as of December 31, 2004 and 2003, is as follows (in thousands):

2004 2003 Carrying Fair Carrying Amount Value Amount Fair Value Cash and cash equivalents $ 17,700 $ 17,700 $ 11,000 $ 11,000 Short-term investments 7,009 7,009 8,747 8,747 Long-term investments 37,785 37,785 38,603 38,603 Special deposits 31,091 31,091 30,115 30,115 Decommissioning fund 75,661 75,661 72,069 72,069 Long-term debt 907,473 987,862 941,173 1,039,856 For cash and cash equivalents, the carrying amount approximates fair value due to the short maturity of those instruments. The special deposits fund balance is contractually determined to meet certain funding requirements.

The fair value of the Company's long-term debt is estimated by management based on the current rates offered to the Company for debt of similar maturities.

Page I1

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 The Company's investments may be classified as available for sale, trading or held to maturity. Available-for-sale securities are carried at market value with unrealized gains and losses added to or deducted from equity. Trading securities are also carried at market value with unrealized gains and losses charged to income. Held-to-maturity securities are carried at amortized cost. All realized and unrealized gains and losses are determined using the specific identification method. All investments are classified as available for sale.

The amortized cost, gross unrealized holding gains, gross unrealized losses and fair value of available-for-sale securities by major security type at December 31, 2004 and 2003, are as follows (in thousands):

Gross Gross Amortized Unrealized Unrealized Estimated December 31 Cost Gain Loss Fair Value 2004:

Available-for-sale securities:

U.S. Government and agency securities $ 35,756 $1,350 $(235) $ 36,871 Corporate bonds 26,749 246 (290) 26,705 Equity investments 29,008 4,856 0 33,864 Other 72,066 70 (330) 71,806

$163,579 $6,522 $(855) $169,246 2003:

Available-for-sale securities:

U.S. Government and agency securities $ 36,778 $1,069 $(218) $ 37,629 Corporate bonds 45,209 818 (182) 45,845 Equity investments 21,763 4,871 0 26,634 Other 50,415 95 (84) 50,426

$154,165 $6,853 $(484) $160,534 Proceeds from the sale of marketable securities were $186,059,000, $254,031,000 and $222,619,000 in 2004, 2003 and 2002, respectively. Related net realized gains (losses) included in income were $1,471,000, $(24,125) and

$607,000 in 2004, 2003 and 2002, respectively.

Page 12

North Carolina Electric Membership Corporation Notes to Financial Statements Dccember 31, 2004, 2003 and 2002 Note D - Investments in Associated Organizations Investments in associated organizations are stated at cost at December 31, 2004 and 2003, and are as follows (in thousands):

2004 2003 TSE Services Inc. preferred stock (Note K) $2,000 $2,000 National Rural Utilities Cooperative Finance Corporation:

Subordinated Term Certificate 4,970 4,970 Capital Term Certificates 314 316 Patronage Capital Certificates 130 122 Other investments 76 61

$7,490 $7,469 The Subordinated Term Certificate bears interest at 6.75% per annum. The Capital Term Certificates bear interest at 3% to 5% per annum. These certificates are required to be maintained under debt agreements with the National Rural Utilities Cooperative Finance Corporation (NRUCFC) in an amount at least equal to 5% of the original debt issued or guaranteed by NRUCFC until maturity of the related debt instruments. These investments in associated organizations are similar to compensating bank balances and are necessary in order to maintain current financing arrangements.

Note E - Special Deposits Special deposits include debt service reserve funds for pollution control bonds as required by the Company's bond agreements and the Company's agreements with Duke. Debt service reserve funds totaled $10,062,000 and

$9,686,000 at December 31, 2004 and 2003, respectively.

In 1994, under the terms of its Catawba ownership agreements with Duke as discussed in Note B, the Company entered into an Amended Depository Agreement with Duke under which the Company wvas required to establish a Special Reserve Fund depository account in an amount equal to the greater of $750,000 or 1% of the Company's estimated payments to Duke under the terms of the Interconnection Agreement plus one-sixth of the Company's estimated payments to Duke under terms of the Operating and Fuel Agreement during the current fiscal year. The depository account totaled $21,651,000 and $20,969,000 as of December 31, 2004 and 2003, respectively.

A portion of these deposits has been classified as short-term investments at December 31, 2004 and 2003.

Page 13

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 Note F - Long-term Debt Long-term debt consists of mortgage notes payable to the United States of America acting through the Federal Financing Bank (FFB) and the RUS, Pollution Control Revenue Bonds and promissory notes to NRUCFC.

Substantially all assets of the Company are pledged as collateral for the debt. The terms of the mortgages, notes and bonds are as follows (in thousands):

2004 2003 FIB mortgage and RUS note advances, maturing at various dates through 2019 wxith fixed interest rates ranging from 5.00% to 8.06% at December 31, 2004 and 2003 $802,498 $836,176 Pollution Control Revenue Bonds, Series 2000, with principal payments due in 2020 through 2024, guaranteed by NRUCFC, three series with interest payable monthly at varying rates (average of 1.92% at December 31, 2004, and 1.2% at December 31, 2003) 99,400 99,400 NRUCFC note, interest payable semi annually at 9.05%, principal payments due in 2024 4,970 4,970 NRUCFC note advances, interest and principal payable quarterly through June 14, 2023, interest rate of 3.6% at December 31, 2004 and December 31, 2003 605 627 907,473 941,173 Less - Current maturities (59,062) (45,113)

$848,411 $896,060 In July 1998, the Company refinanced substantially all FEB notes with an outstanding principal balance of

$1,015,104,000. The interest rates on these notes were reduced from rates ranging from 7.69% to 10.52% to a fixed rate of 5.61%. This rate will remain in effect for a 10-year period ending in 2008, at which time the Company has the option to reprice the outstanding principal for the remaining term. In conjunction xvith the refinancing, the Company paid a penalty of $2,861,000 and financed an additional premium of $114,435,000 over the term of the original debt. The Company individually assessed the refinanced notes to determine whether each transaction should be accounted for as an extinguishment. As a result, $253,148,000 in debt wvas extinguished and replaced by $271,391,000 in new debt, representing the fair value of the related notes. In addition, the Company wrote off $713,000 and $2,108,000 of related refinancing penalties and original debt issuance costs, respectively. The resulting loss on extinguishment of $21,064,000 was recorded as a deferred charge to be amortized in accordance wvith the recovery period established by the Board of Directors. Likewise, the remaining unrecorded premium of $96,192,000 will be recognized as interest expense over the term of the debt. The unamortized balance of the refinancing premium was $74,312,000 and $77,321,000 at December 31, 2004 and 2003, respectively. This transaction will result in a net economic gain of approximately $68,647,000 over the term of the notes.

In September 2000, the Company issued Series 2000 Pollution Control Revenue Bonds, guaranteed by NRUCFC, in the amount of $99,400,000. The bonds were issued in three series, with principal payments due in 2020 through 2024. Interest on the bonds is payable monthly at varying rates. In addition, the Company borrowed

$4,970,000 from NRUCFC to finance the purchase of a Subordinated Term Certificate with NRUCFC, a requirement for NRUCFC to guarantee the pollution control bonds.

Page 14

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 Maturities of the long-term debt described above for the five-year period beginningJanuary 1, 2005, and thereafter, are summarized below (in thousands):

Years Amount 2005 $ 59,062 2006 50,314 2007 53,127 2008 56,185 2009 59,422 Thereafter 629,363

$907,473 The Company also has a $48 million line of credit with NRUCFC, which was unused at December 31, 2004, 2003 and 2002. The interest rate available under this agreement would be determined at the time an advance is made.

This line of credit expires in June 2005 and is subject to an annual renewal process. Borrowings on the line of credit are made on a revolving basis as needed.

Note G - Employee Benefit Plans All employees of the Company participate in the National Rural Electric Cooperative Association (NRECA)

Retirement and Security Program (the Program), a defined benefit pension plan qualified under Section 401 and tax exempt under Section 501(a) of the Code. In this multiemployer plan, which is available to all member cooperatives of NRECA, the accumulated benefits and plan assets are not determined or allocated separately by individual employer. The Company makes annual contributions to the Program equal to the annual pension expense, except during a period when a moratorium is in effect. Payments to the Program for current period service cost were $1,902,000 in 2004, $1,816,000 in 2003 and $1,725,000 in 2002.

All employees of the Company are eligible to participate in the NRECA Savings Plan, a defined contribution plan qualified under Section 401 () and tax exempt under Section 501 (a) of the Code. Eligible employees may make contributions to the plan of up to 15% of their salary. The Company matches employee contributions to the plan up to 3% of the employee's salary. Total company contributions to the NRECA Savings Plan were $308,000 in 2004, $304,000 in 2003 and $301,000 in 2002.

Page 15

North Carolina Electric Membership Corporation Notes to Financial Statemcnts December 31, 2004, 2003 and 2002 Note H - Other Postemployment and Postretirement Benefits The net postretirement benefit liability recognized by the Company, included in other noncurrent liabilities on the accompanying balance sheets, is summarized as follows (in thousands):

2004 2003 Retired plan participants $ 1,101 $ 978 Active plan participants 3,947 3,888 Unrecognized actuarial loss (1,085) (1,494)

Accumulated postretirement benefit obligation $3,963 $3,372 Net postretirement benefit cost for 2004, 2003 and 2002 is included in administrative and general expenses and consists of the following components (in thousands):

2004 2003 2002 Service cost - Benefits attributed to service during the period $359 $325 $256 Interest cost on accumulated postretirement benefit obligation 274 288 225 Amortization of actuarial gain 43 76 42 Net postretirement benefit cost $676 $689 $523 Disclosures required by SPAS No. 132, "Employers' Disclosure about Pensions and Other Postretirement Benefits," with regard to the Company's postretirement benefits are as follows (in thousands):

2004 2003 Benefit obligation at December 31 $3,963 $3,372 Fair value of plan assets at December 31 0 0 Funded status -Accrued benefit cost recognized in the balance sheet $3,963 $3,372

'Weighted average assumptions as of December 31:

Discount rate 6.25% 6.75%

Rate of compensation increase N/A N/A H-lealth care trend rate (decreases annually to 5.0% by 2014) 12% 14%

Benefit cost $ 676 $ 689 Employer contribution 85 81 Plan participants' contributions N/A N/A Benefits paid 134 116 Page 16

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 Projected future benefit payments are as follows:

Years Amount 2005 $ 157 2006 161 2007 197 2008 240 2009 277 2010 to 2014 1,877 The Company has revised certain assumptions related to the computation of the accumulated postretirement benefit obligation, resulting in a net actuarial loss of $1,085,000 in 2004. Increasing the assumed health care cost trend by one percentage point would increase the accumulated postretirement benefit obligation for 2004 by

$872,000.

Note I - Commitments and Contingencies Department of Energy Assessment The Energy Policy Act of 1992 gave the Department of Energy (DOE) the authority to assess utilities for the decommissioning of its facilities used for the enrichment of uranium included in nuclear fuel costs. In order to decommission these facilities, the DOE estimates that it would need to charge utilities a total of $150,000,000, adjusted for inflation, annually, for 15 years based on enrichment services to date. Based on preliminary estimates from Duke, the Company recorded its share of the liability. A corresponding asset wvas recorded as nuclear fuel and is being amortized to nuclear fuel expense over the 15-year assessment period. The estimated remaining liability of $2,546,000 and $3,078,000 is included in the accompanying balance sheets in deferred credits and other liabilities at December 31, 2004 and 2003, respectively.

Power Coordination Agreements and Purchased Power Commitments In 1996, the Company began receiving 205 megawatts fie\X) of capacity from AEP. The agreement provides fixed capacity and energy prices through 2010.

In 1998, the Company negotiated a power supply agreement (PSA) and a network service agreement with CP&rL which became effectiveJanuary 1, 1999. Also in 1998, the Company entered into a purchased power agreement with CP&L for 800 MW of peaking capacity beginning in 2001 and extending through 2003. The Company also exercised the option to extend 800 I\IW through 2004. The Company has the option to extend 500 hM\W1 through 2005. The agreement provides fixed capacity and indexed energy prices.

Page 17

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 In 2001, the Company entered into PSA's with AEP, VEPCO and South Carolina Electric and Gas Company (SCE&G) to supply a total of 970 MW of capacity. The term of these agreements is from 10 to 25 years. In 2003, the VEPCO PSA, which provided 570 IAIE of capacity from January 1, 2005, through December 31, 2029, was terminated and replaced with a 150 MWXV PSA with VEPCO from January 1, 2005, through December 31, 2014. In 2003, the Company also modified its PSA with CP&L to increase the amount of capacity purchased and to extend the terms for three of the capacity blocks it purchases from CP&L. The AEP agreement provides for fixed pricing. The VEPCO and SCE&G agreements provide for fixed capacity and indexed energy prices.

In 2002, the Company signed agreements with VEPCO, SCE&G and Southern Power Company (Southern) to purchase a total of 250 MW of peaking capacity and energy with load following capability for a two-year period beginningJanuary 1, 2004. The agreements provide for fixed capacity and indexed energy prices.

In 2003, the Company negotiated a network service agreement with VEPCO which became effective January 1, 2004.

In 2004, the Company signed another agreement with CP&L for the purchase of 500 MW of capacity and energy in 2005,750 Ml\Xf in 2006, 450 MV(' in 2007 and 300 MIIW from 2008 through 2024. Also in 2004, the Company began taking transmission service from PJM Interconnection (PJM), due to the integration of the AEP transmission system into the PJM footprint. The Company expects that in 2005, its transmission service from VEPCO svill become transmission services from PJM upon Virginia Power's integration into PJM1.

In 2005, the Company signed an agreement with CP&L for the purchase of 100 NMW of capacity from February 2005 through January 2006. The Company signed agreements with Progress Ventures and AEP each for the sale of 50 MWI for the same period.

Plant Construction Agreement During the mid-1990s, the Company purchased property, incurred licensing and architect fees and entered into an agreement to build a combined-cycle natural gas-fired electric generating plant. Construction of the plant was scheduled to begin in 1998. Due to changing power supply market conditions in 1996, the Company decided to delay the construction of the generating plant indefinitely. The Company has capitalized these preliminary project costs of $9,418,000 through December 31, 2004, in the accompanying balance sheets. The Company entered into an agreement with Dominion Davidson, Inc. to sell the property for approximately $12,000,000 conditional upon achieving certain milestones. In accordance wxith the agreement, the Company received $2,000,000 in 2002. In 2003, Dominion Davidson, Inc. terminated the agreement and forfeited the $2,000,000 previously paid to the Company. The Company has recorded this as a reduction to preliminary project costs at December 31, 2004, in the accompanying balance sheets.

Peaking Capacity Project In 2004, the Company entered into an agreement with Pratt and Whitney Power Systems (PTPS) to build 620 MR\X' of peaking capacity to be operational in 2007. In 2004, the Company submitted a loan request to RUS for an amount not to exceed $320,000,000 to finance the cost of the project. The Company expects the RUS loan to be approved and proceeds to be available in 2006.

Page 18

North Carolina Electric Membership Corporation Notes to Financial Statemcnts December 31, 2004, 2003 and 2002 In 2005, the Company entered into an agreement with NRUCFC for $75,000,000 of interim financing to fund the costs of the project prior to the time permanent financing is received from RUS. In addition, the Company requested a lien accommodation from RUS for interim financing for the project.

At December 31, 2004, the Company had capitalized $8,814,000 in costs associated with this project. These amounts are included in construction work-in-progress in the accompanying balance sheets. The Company is obligated to make payments of $12,700,000 in 2005 to PXTPS per the terms of the contract.

Note J - Nuclear Insurancc Duke, acting on behalf of the joint owners of Catawba, maintains insurance coverage for public liability claims resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and a mandatory industry-wide excess secondary insurance program of risk pooling. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, the joint owners of Catawba could be assessed retroactive premium adjustments. The maximum assessment per reactor under the program for each nuclear accident is approximately $101 million, subject to an annual limit of $10 million per incident. Based on the Company's interest in Catawvba, its maximum potential assessment per incident is approximately $28.3 million, with an annual payment limitation of approximately $2.8 million.

Duke maintains a Business Interruption Insurance Policy. This policy provides business interruption and/or extra expense coverage resulting from an accidental outage of a nuclear unit. Each unit is insured for up to $3.5 million per week.

Duke is a member of Nuclear Electric Insurance Limited (NEIL), which provides $500 million in primary property damage coverage for Catawba. If NEIL's losses ever exceed its reserves, the joint owners of Catawvba wtill be liable for additional assessments. The potential maximum assessments are: Primary Property Insurance -

$35 million, Excess Property Insurance - $44 million and Business Interruption Insurance - $29 million. Based on the Company's interest in Catawba, its maximum potential share of this assessment is approximately $10.9 million.

Duke also maintains insurance coverage for property damage to, and decontamination and decommissioning of, property at Catawvba in the aggregate amount of approximately $2.3 billion. Duke has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of Catawba. The joint owners of Catawba are obligated to assume their pro rata shares of any liability for retrospective premiums and other premium assessments resulting from policies applicable to the joint ownership agreements.

Page 19

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 Note K - Related-party Transactions In accordance with a management agreement, the Company provides staff services to the North Carolina Association of Electric Cooperatives, Inc. (NCAEC), the Tarheel Electric Membership Association, Inc. and subsidiary (TEMNIA), TSE Services Inc. (TSE), EMIC Technologies, LLC (EMCT) and the CEC Self Insurance Fund, Inc., (CECSIIF, which are all related parties through common ownership. The management agreement provides that charges for these services include a component for general corporate expenses and an assessment for office space and computer equipment. The Company also charges the ElecTel Cooperative Credit Union (ElecTel), a related party, a fee for office space and use of the Company's copy machines. Charges to NCAEC were $4,947,000 in 2004, $3,876,000 in 2003 and $4,238,000 in 2002. Charges to TE MA were $2,579,000 in 2004,

$2,429,000 in 2003 and $2,356,000 in 2002. Charges to TSE were $2,721,000 in 2004, $3,098,000 in 2003 and

$3,784,000 in 2002. Charges to EMCT were $6,180,000 in 2004, $6,363,000 in 2003 and $7,636,000 in 2002.

Charges to the CECSIF were $65,000 in 2004 and $40,000 in 2003 and 2002. Charges toElecTel were $27,000 in 2004, $38,000 in 2003 and $30,800 in 2002.

The Company purchases various services from TSE, NCAEC and EMCT. Expenses related to services purchased from TSE totaled $1,315,000 in 2004, $1,269,000 in 2003 and $1,289,000 in 2002. Expenses related to services purchased from NCAEC totaled $2,953,000 in 2004, $2,086,000 in 2003 and $2,309,000 in 2002.

Expenses related to services purchased from EMCT totaled $6,040,000 in 2004, $6,118,000 in 2003 and

$7,620,000 in 2002.

In 2003, the Company reclassified $8,605,000 of the receivable from TSE to noncurrent receivables.

The Company has accounts receivable net of accounts payable xvith related parties at December 31, 2004 and 2003, as follows (in thousands). These amounts do not bear interest.

2004 2003 Current:

NCAEC $ 168 $ 149 TE MA 219 417 TSE 166 144 EMCT 37 531 CECSIF 5 3 595 1,244 Noncurrent:

TSE 8,605 8,605

$9,200 $9,849 Page 20

North Carolina Electric Membership Corporation Notes to Financial Statements December 31, 2004, 2003 and 2002 The Company has designated $27,000,000 for loans to members for economic development and construction of customer-owned generation. At December 31, 2004 and 2003, outstanding loans totaling $8,436,000 and

$9,605,000, respectively, have been included in accounts receivable and noncurrent receivables in the accompanying balance sheets. Economic development loans (totaling $8,433,000 and $9,569,000 at December 31, 2004 and 2003, respectively) do not bear interest and have repayment terms of up to seven years with an initial payment deferral of up to four years available under certain circumstances. Customer-owned generation loans (totaling $3,000 and $36,000 at December 31, 2004 and 2003, respectively) accrue interest at fixed and variable rates ranging from 1.9% to 8.3%. The repayment terms for these loans range from 1 to 7 years. The contractual maturities of the economic development loans and customer-owned generation loans described above are as follows (in thousands):

Years Amount 2005 $1,758 2006 1,586 2007 1,483 2008 1,238 Thereafter 2,371

$8,436 Page 21

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ment Letter joay is a progressive time in the electric industry. Important decisions facing the industry are being considered by the United States Congress and the Federal Energy Regulatory Commission (FERC). During this time, PMPA is monitoring cur-rent issues in the electric industry and responding with solutions to the challenges we face. PMPA is empowering our Participants to be a force in these changes and help shape the future of the Agency. Likewise, PMPA is delivering results, through our partnerships with Members and our business partners, to ensure our future is secure.

Although a federal Energy Bill did not pass in 2004, and FERC was not able to implement major restructuring affecting transmission of electric power, the debate continues. PMPA is committed to ensuring that any changes made through restructuring efforts are in the best interests of our Members. Our continuing primary goal is to provide our Members and their customers with reliable electric power at prices that are affordable. Economic development in our cities is dependent upon having adequate, reliable and cost effective electric Lebete'rgh power. PM PA's ownership share in the Catawba Nuclear Station provides that

)on .Ou~leyreliable power source - for now and well into the future. We have begun a comprehensive program directed at stabilizing electric rates so that our Members may continue to grow and prosper in the years ahead.

In late 2004, recognizing the need to mobilize community leaders on a grassroots level to work with the South Carolina Congressional delegation, PMPA formed a Rate Reduction Team. The Team is comprised of city leaders and utility staff in our Member cities, along with state and federal legislators. The Team's purpose is to identify and pursue initiatives to accomplish PMPA's goals, specifically issues related to an amendment in the Department of Agriculture's Appropriations Bill.

The amendment will allow PMPA to be fully eligible for grant and loan programs administered by the Rural Utilities Service (RUS). I am happy to report that the Team was successful, achieving approval of the amendment and making PMPA fully eligible for RUS loan and grant programs.

The Rate Reduction Team was formed around the idea of mobilizing community

-A leaders in our Member communities to generate new ideas and achieve positive results. To date, new ideas and initiatives have been identified and are being pur-sued on an ongoing basis. Many of these initiatives involve federal agencies and require the support of our federal delegation to be successful. Among those ideas are requests to Congress for Members to receive federal appropriations for a variety of projects, including water treatment facilities, wastewater plants and highway projects. PMPA Members have been empowered to shape the future of our organization.

As a follow up to the license extension for the Catawba Nuclear Station in December 2003, PMPA seized the opportunity to extend and restructure our debt. This debt restructuring was a significant milestone in our rate stabilization initiative. While more work must be done to further stabilize rates, be assured that PMPA staff will deliver results in rate stabilization efforts.

We continue to progress toward our strategic goals, including our most important goal - keeping power supply both reliable and cost effective. With a resurgence of interest in nuclear power generation, our future is promising. The recent license extension at Catawba Nuclear Station offers a reliable, cost effective power supply for years to come.

Change is inevitable in the electric power industry. While all outcomes cannot be known; be assured that PMPA will continue to respond to emerging issues, empower city officials and staff to influence change and, ultimately, deliver quality leadership and reliable, cost effective power to our Member cities.

PMPA Westmjgnster-.: 'Unign Nc Clno - PM

'. AbeiW PMPA Participants Year Electric Percent Participants Established Revenues Customers Ownership Abbeville Public Utilities 1905 $5,829,000 3,604 2.68%

City of Clinton 1907 $9,862,000 4,238 7.84%

Easley Combined Utilities 1911 $22,806,000 12,541 13.24%

Gaffney Board of Public Works 1907 $16,255,000 7,273 10.05%

Greer Commission of Public Works 1913 $22,787,000 15,308 9.34%

Laurens Commission of Public Works 1922 $8,578,000 5,194 6.49%

City of Newberry 1896 $13,341,000 4,866 10.47%

City of Rock Hill 1911 $59,276,000 29,677 28.04%

City of Union 1898 $12,674,000 7,046 10.01%

Westminster Commission of Public Works 1921 $2,908,000 1,592 1.84%

Total $174,316,000 91,339 100.00%

.Iin of C wer

, SC Ma-1r i Rtix

risslor of Rock I ty, of Rock Box 11 7C 0 B6x-117

'AH(il, ISC ock Hii lS

.329551' fl ,,n Box 399

,tminster,

PMPA Since its inceptionin 979, PMA memberf cities have shown consistentgrowh, Having weathered the national manufacturing recession of 2001 -2003, the regional economy exerienced more rapid expansion in2004.: Wth capital Total Par*4nt

invetet in the state growing in 2004 at  ;

twice the rate of the previous year, Auptate South Carolina continued to diversi its ec and fill th emlment gapscreatedi by the contration in traditional indutries such as 777 teiles. Accss to an excellent transpoaon network and proxirity to such rpidly log hubs of commerce as Greenville, n burg and Charlotte place member cities in a favorable jW ii::An0h; 33:. j 1. 'w .w 2N' position to continue to achieve thir economic growth and development potential.pAlable, reliable and affordable elrc r Total Participant Electric Customers to the attractiveniess of tese locations.0 In cobination 2000 2001 2002 2003 2004 Total Participant with a progressive business environment, dly Electric Customers 82,443 85,224 87,565 89,840 91,339 and productive people a n unexcellediqalit Total Participant of life, the stage is setfor thefuture suocess f Wholesale Purchases:

PMPA memhbrs. PMPA Purchases MWh) 1,992,616 1,944,545 2,059,950 1,935,037 2,047,661 SEPA Purchases (MWh) 75,831 76,965 80,140 156,301 136,674 Total Purchases (M) 2,068,447 2,021,510 2,140,090 2,091,338 2,184,335 Availability Factor Catawba 1 89.3% 99.6% 94.2% 81.8% 98.0%

Catawba 2 90.3% 85.7% 100.0% 92.7% 87.4%

McGuire 1 99.5% 88.0% 91.8% 100.0% 83.4%

McGuire 2 88.3% 99.3% 90.7% 91.6% 100.0%

Net Capacity Factor Catawba 1 90.0% 100.9% 95.9% 82.7% 97.9%

Catawba 2 90.6% 86.7% 102.9% 94.2% 89.1%

McGuire 1 103.4% 90.1% 94.4% 102.9% 85.3%

McGuire 2 87.5% 102.5% 92.5% 93.7% 103.4%

6i 2004 Anual repot

-PMI;'A meme cities fprovide elrctricsevc to; 0 moreithan 91t 0 re~sidential,. commercial and:

industrial cut rnr. These l}ocal powr systems Ube~lon to. t'he ;p p they serve and reprent local consumers:wor r togeth to meeto1 need.

Suppy o electrie a :reliablet and sufficient C:ts plan fo lcity to its members, sek viable0000 lower members' jpower suppy 2: 0 tue pwer supply requirements,.

whilestrivingfor maximum is, .manag the Agnc fficiently 0 At,PrMPA', or rid be pociein influen~cing000 chagesinthe elecric indutry.; 0t the qualit ofli Total PMPA Coincident Peak MW PM-P0A is her b4ii 2000 2001 2002 2003 2004 Total PMPA bea: S.,that.,rnral goalisservi of to the ten Coincident Peak (MW) 441 440 471 453 442 knowing ha W mnt. PMPA is dedica t improvng toh i -.nSX. an i:a-2004 Data Revenues MWH's Customers Jin ech municipality as well as Residential $80,596,412 855,668 79,369 oterigdev t and grwh Commercial $83,264,744 1,022,113 11,806 iause of tese ten cities, and Industrial $8,091,491 130,855 47 Other $2,363,246 34,391 117 their ci:hiens have the comfo oft0 Total $174,315,893 2,043,027 91,339 are alwaysjutst around the co ner d every wvay we possib can."-

2004 Annua i:eport 7

A b b e ville eitage of Abbeville evident in ' Historic reptation as the birthplaceand eathbed fthe .

Confederacy. Th e tree s dt u ri ia Charestoftye architectura fatures accommo'date the AbbevileOraHu,

- PT~Aitiy he'County Courthouse and avariety of bsinesses catering to t di ofdowntown ts district h as nation.a -freo iti received o.

"'Together with its emphasis on history anl recreation the cit has contemporary business a diversifie economic bse with and industry. In 'addition to the quality of ination of aditional and life factors, the area offen a low cost of aiving, an abundant water Supply, Modem telecommunications access, an attractive labor market, a vari of -served, reasonablytpie business si es 9 -~and a dependable and affordable supply of electrical energy.

6 Quality schools and health care facilities rud ut a complete complement of community services Proidig eecticservic to the comuiysneteary 0 Abbevl*econ s t es tomatain on expan it electric service capabilities to et the-nees of the community. In 2004, 2 -

srvi t_:was extlndd to anew hospital ahd wel: ess center under construction oni property annexed by the' city and to a new

""~7,,"baseball omp~lex adjacent to anewly coihstructed middle school..:~

Te medical centei project is expected tc beo6n66f the largest employers in the county. and will be the'catalyst for the location of nmbreath eric buinsss.System enhancements af nw during the year iclude continuation of ilhe'Streetscape.,~

Improvement Project and improvements'along the Highway 72 C6rridor. ~Highway 72 is in the proces's of being widened from the state line nesae2 to tCinton to offer an alternatives route to Atlanta.

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g;To~~~~~~~~etene tomeas neTA ,3 if363 '356 36 .'

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-Abbeville Electric Customer Data j 2000 2001 2002 2003 2004 Total Customers 3,619 3,634 3,643 3,596, 3,604 2004 Data: Revenues Customers - I I

Residential . 315003;10b3 I Commercial T,-~tIFtR)qflf

$2,704 000 noni4 501 Non Coincident Peak Coincident Peak System Demand (KW)A . 11,628 14,556 City Manager, David Krumwiede, (left) and Director of Public Utilities, '

Mark Hall, stand outside the historic Abbeville Opera House.

Internet visitors can view events in the'town square via web-cam , .

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city of Clinton, with appro 0ents,; is the second largest city' in Laurens County. Bec se of its intersta .) C ,, ff .X. ..... . f ,0 .; . ... .. . ..

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connections and railroad access to industrial clusters ,'research  : >; . .  ! t centers, suppliers and markets, Laurens County has-had consider-;I able success in attracting investmentin manufacturing and distribution activities to replace a deteriorating textile sector. i$2ff.,;, i' Jiow__

Strategically positioned at the intersection of Interstate Highways

-I385 and I-26, Clinton is a progressive, growing communty within'an easy drive of the metropolitan centers of Columbia and .:

Greenville/Spartanburg. 'A promising industrial park, ClintonPark

'CorporateCenter, at the intersection of SC 72 and Interstate 26, 1 serve as an attractive economic gateway to the city The local economy continues to become more moderm and diversified as evidenced by new jobs and plant investment during 2004 min high-tech automotive bearings and plastics products for the home At the same time, the city is working to preserve and enhance the many features that exemplify its traditional, small-coimmunity atmosphere by continuing to breathe new life into its historic '

-downtown business district arid surrounding njeighborhoods..

The city serves over 4,000 electricalscustomers through its' Combined Utility System.. The system has a long and distinguished:

,record for service quality and reliability. Dating back to 1907, the system has been an integral part of the growth and development of the community. Its commitment to progress and serice is reflected in its role in Clinton's business and economic develop.'

'ment, downtown revitalization, neighborhood restoration and:

cultural preservation. In 2004, the main investments of resources were focused on system upgrades and maintenance. 'New service extensions and upgrades were accomplished in residential areas-:-.

-~ -as well as for new retail and serce sector customerst.. The system is -.-I

-constantly anticipating and preparing for changes by maintaining system infrastructure andequipment, ensuring adequate capacity

'and dependability, and implementing operational efficiencies to provide quality services. ., -

Clinton Electric Cu sto er Data 2000 ;2001 2002 2003 2004" Total Customers 4,243 4,398. 4,532 :4,189 '4,238 2004 Data -'Revenues - Customers Residential $3,689,000 3,615-.'

'- Commercial - $3,927,000 -::617 Industrial $2246 000 6 6-Total $9,862,000 4,238.

Coincident Peak No'n-Coincident Peak 1' System Demand (KW) 24,254 25,315 Downtown Clinton is destrian friendly.

A replica of the roofline of the original depot serves as the focal point for.

dow activities and events.-

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A few7 years after the railroad rote betw~een Ch'arlotte, NC and Atlanta, GA was decided in 1870, t he legislature ratified

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n of Pickensville, in Pi'kens C In1901; Charter was.

changed to create the City Of Easley. Located in the northwestern corner of the -tate in the foothills of the Blue Ridge Ntains,

-- - =' corner;fthe state in'the fohls of teBuRigMountains, 0 Pickens County encompasses numerous lakes and streams, beautiful mountain vistas ,and a fine 'quality of life with a rich-heritage. Easley is now'the largest city in ihe county with a '-

- population

= of approximately 18,000. Less than 1i nilesi from

'the I-85 corridor,' Greenville and Clerson'lie within a 30-minute drive and Charlotte and Atlanta are only two hours away. :""'

-As the presence of the textilemindustry has declined 6ver'the years,

- Easley economy has become more modern and diversified.

-the -

-The city has benefited by'the growth and attraction from the-new and expanded industry attracted to the ",upstate" 'area's business .';.

-' climate and quaiity of life. Abandoned mills along Main Street

-have been converted to small business and warehouse 'space. Other renovations, such as the conversion of the old high school building into condominiums, are creating new residential units and new

'neighborhoods are emerging.- Retail services are expanding along

- the highwy corridors in and near the ct

'- '...Providing a reliable supply of water, wastewater and electric '

.service at the best possible price has beenra community tradition since 1911. The first elctricityg'enerated'was ussd to supply

- power to the water treatment plant and the initial distribution systern supplied electricity to the city's dow ntown area. The

• Combined Utility System was created in the'ear y 1950's, bnnging togethergthe the expanding electrical network

'administrationof

'with the city's water system. Sewage collection beame partof'

.the combined system a fewmyears later. -Today,th'&ele'ctric' system-has a base of over 12,500 customers, 87 percent of which are

residential. Apeak 'shaving generation facility constructed '

.in Easley takes pride in maintaining its conmitment to' p reliable and affordable services to maintain the city's vitality

'.and the quality of life enjoyed by its present and future citizens.

-Easley Electric Customer Data :

' . 2000 . 2001 202 2003 . 2004.;.

m Total Customers 11,910 -12,340 -12,535 12,368 -12,541 2004 Data - Revenues Customers Residential J $12,302,000 . 10,850

-,:.Commercial/Ind - $10,504000 ' 1,691 Total ' -22,806000 - 12,541 Coincident Peak :Nor-Coincident Peak

'System Demand (KWV) ' 59163 . 63,202 Kip' Deck, ECU Purchasing Agent,standsin Easley's new high-service pumping station.,

Easley Combined Utilities began serving customers from its new -

office in November 2002.;:

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1 affney is te county seatofCherokee C~inoted' historically as the site of the Battle of Cowpens -in;1781, an I. important victor for the revolutionary forces. In -the foo1thills*

-of the Appalachian Mountains in northwestern South Carolina,.

Cheiokee County borders North Carolina in a region where iron,1

.mining wasimportant until the time of the Civil War ~In the mid__-

19th century, the Gaffney area was the location of the Limestone Srngs resort, apopular retra frLwcutry planters.,A the town grew, the resort hotel was converted into a school for women, now Limestone College. Gaffney was incorporated in 1857, arid named for pioneer merchant Michael Gaffney. IGrowth was given O ;RrABU~RG JNCOLLEE a boost with the introduction of the railroad in 1873 and the town

-developed around an' econonmy based on textiles and cotton.

Currently home ~tonearly'13,000 residlents, Ga~ffneylies beside--- ITI WITHSICEEAPPRECIATIE.

-THATINEACKNOWLIOE UTHP

-Intersta~te85, strategically position~e'dbetween Ch-arlotte, NC a'n-d','~~

the Greenville/Spiartantburg area. 'It is ideally situated for individu-als and businesses seeking a sbrbnsetting~ with quick and easy--

~access to largejarban development and metropolitan markets. -The ecnmyhs nergone significan caniges as traditional goods and services have given way to a more diversified business and industry base. IPeaches have becoIme the area's primary~agriciltufal commodity and Gaffney. has hosted this annual South Carolina~

Peach Festival, now a two-we event, sinc 1961. New retailan

.industrial grow~th has brought new job opportunities, particularly along the 1.85 corridor. The commercial and industrial develop.:

enhabeen floebygrowth in retail, educational services,-

government, and health services. To support current and potential development in the area, a new technical taining facility is Planned to equip the local workforce with the skills necessary toattract and sustain the new and emerging business activity.-

-Since 1907, the Public Works Board has'sup ported the c~omm runity and' itevelopment through reliable, efficient and affordal waeswr, and electrical servce'to Gaffney nd the surrounding areas.of Cherokee Counhtyi.Throuigh the tears, the Bo'ard ha-s'

-expanded and upgraded its systems and services, and currently.

'provides electricity to nearly 7,300 customers through approxi-mately 130 miles of lines., y. ~

-Gafney,Electric Customer Data

-. 2000 2001 2002 2003 ~2004

-Total Customers 7,3467 7,342 7,296 7,260 7,273 2004 Data ReeusCustomers Residential~ $5,721,000 6,044 Commercial $7,569,000 ~ 1,1179'

-Industrial - $1i,491,000 .27 other $1,474,000 23 otl$16,255,000, 7,273 7, coinicdenit Peak Nori-Coin'cident Peak System Demand (KW: , 41,958 42,643 Mike Bolin,'GBW Salfety oordinator,stanids at the entrance tothe nrew Cherokee County campus of Spartanburg Technical College.-

The new Towne Sho'ppes retail center is,the venture of a-lcleternu with remarkable Succes Inthe'shoe business. e~u

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'~..reer resides inGreenville County, in the nocthwestern corner,

' ' ,'-or.I ,..'Atate",s ti of'r of Ca'.lNee' -d

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stled in the foothills'of theiBlue RdMountains theIi hills'with ain abundance of

• lakes, streamns and rivers were part of the Chero)kee Nation prior to the Revolutionary War. Te land was ac ie yteSaesoty after the war and sparsely settled until the arrival of the railroad in

183.>Asthi ara f iitrnsc natural beauty developed over the' deca desinto amajor transportation corridorit became a hub of>

• commerc. .Major air, rail and highway r'outes between Cha.lotte; North Carolina and A Gergia traversed the area, and travel to the Port of Charleston was facilitated by the fonsotr Is onof an interstate to the southeast With ready access to the mar ets of the nation and the world, the region has ransformed from i an economy originally dominated by farming ald textile madnufac tuinng into aegoprviding headquarter locatios for various industries', a center for a va riety of high-tech ma"nufacuring enter-j- .::..' d pnes, and aware ousing center or te - utiori ct grown into a vibrant cityw itha booming econfmy. Reco '

one7of the State's fastest growing cities over the past~ decade, Greer has a current population in exces f 000. between the t 'll11 t@lt} 2\' - .................;dinustributio cities of Greenville a'ctivties. Spartanburg,of therceity and fora'variety is located hightschindufsturiii nd inenter-a region -.a- -

ing growth. As a result,' Greer has been'successful in attracting a

_highiy-diversified manufacturing and industrial base with a stro'ng

-intemnational influence. Its excellent transportation infastructure has made it an ideal location for services, Wie:.thusing And growth has created a major expansion in thedretail sector. The city

, has been strategicallynsitine d to capitalize on'the hsurrounding devlopmento yet it strives to maintaint e and q o f lif"e that hsdistinguished it froin other larger ut b areas. Greer ' ' 1]

-Partnership for Tomorrow focuses oindd6wrtowni revitalization anid l b--:,-,halancuesnistoia pieservation ecithsfnei'r ential antd com her-: ',

el..;-"opGreent around the community -oriented plazas and parks. Ftirst-rate schools, h thicie'and recreation anfacit ies round out the community services that help build a strong

__ nertiown influencivic pride and ansexeptional qialisty f life.

Greer Electict Customer Data 2000- 2001: 2002 2003 2004 jotal Customer su 9 11544d 12,33 g14,34115,3 08-2004 Data Revenues- urban areaCustomers Residential $12 917,000 13,584 Commercial $9,196,000 1 692 lakei

• Other '-tnd $674,000 by a" mete 32 nerwaa0D0.

with -'Greer'EetrcCsto

-- . *Total $22 787 000 15,308 Coincident Peak N~on-CoincidentPa System Demand (KV) '59,861 61,299 Anew outpatient surgicalc~enter offers Greer's esidents additional otion for quali medical care. .' . i ,

,autom ,ed readingprogram wh1h, nderwent2 a1maj meter e3xpa1nsion in 24

-of a less intrusive and more cast efficient ' eterreading process. i

La urens L aurens is home to 10,000 'residents who take pride in, their communifty and its heritage, diversity and potnilfor grwh and development. In the city and surrounding areas,-

textile dominace has been dsp a~ced bya wide vaitfidustri-al activity that includes plastics, ceramics, automotive and other'

'advanced manufacturing/metalworking operations. The-city has been successful in attracting its share of the area's manufactrn growth with resources such as the Hunter Industrial Park, at the intersection of I-385 and US 221, which had two'plant exansions_~

announce in20.Wt hs industrial growth has come epninin the retail and srvices sectors.7 The Laurens Comis'sion of Public Works (CPW), apublicly-,,-

owned, no-t-for-profit utility providing reliable and afforal electric service to the~cnmtmuity, has been-operating since 1922.

,TheiLaurens CPW is a major player 'in the city's grocwth and devel iopment and is well-respected for its role'in support of commnunity aacivities. J n. 2004, the CPW provided essnillgsia upr to the production 'of a nationally-televised project to revitalize the downtown district. It joined with television network production crews and vol Unteers from ario~und the coimnunity'to en'surefthe success of the renovation efforts that have brought a great deal of national attention to the city and its people. Six episodes' of the series featuring Laurens,,"Town Haul", a-re -sche'duled to run for six,.

wes on The Learning Channel in early 2005. In addition to the gitclinvolvemnt and hours of voluintee work on this impor-tant project, the CPW staf invested considerable tinme and oue

-.'during the year onsystem upgrades to affedt cost savin'gsanhd even-1 greater systemf dependability. UJpgraides in the comiputer system- to monitor and control system operations across muincipa1lfunctions-,..

,have improved telecommunications capabilities and added Intern et access..

With the many appealing featues that characterize'the city as an attractive place to live an 'work and the atoal expoure gained via its media attention; Lauren's is in position to receive an in'cre'as-.

ing number of business,inquiries and interested visitors.

Laurens Electric' Customer Data 2000:'2001 2002 2003 204 iTotal Customer's _5,313 5,297 5,290 5,216' 5 194.

j2004 Data 'Revenues Customers Rsdentia I- $,9100I 4,352' Co-m-mlercial/ind. $3,987,000 ' 842.

Total '~$8,578,000 5,194 Coincident Peak _Non-Coincident Peak System Demand (KMA 2,4 23,081

'A new children's park wa n ftemjr prjctscompleted -aspart of the V televised "Town Haul"'series. . - -

The TV production workers repainted s'ome old, faded signs to retain their sense hitry in the downtown revitalization effort. -

WVo

Newberry mmansions" ad tree-linedsseets wit aprogressive attitude for econoi de7lmn, ebrry cnbechaiacterized 8S a dynaik blend 6f the odadtenw with appltoovr 10,000, it listhe Iags ctinhe county and is~recognized as oneoth aetpasolien the tt The cit leadjacen'tto' Initerstate 26 which has served athe catalyst for invet nmoidein, hiore d1iver'se industrial and int comercal ctivity. The mhain highway co~nnectors linking the interstate with the cent ral bususnsh' ess' districthiiveaeperienced

-significant commrercial devel66pme'nt. The downtio-w'narea w'ith"'

its hIstoric buildings and architectural features, remains a vital focus of business, education, government and cultural activity.

The result is a mi~x of active retail and service centers intersp~ersed`

with qiet, qu aint neighborhoods contaiihng many beautiful, i7 historic homes.' The city serves as the coulnty's'service center for.

health care,, education, culture and recreation.

The community's business and resietaeleti oe ed

- - a ~re bythect'ys utility department. In 204 thiecity's sppied utility crews and staff continued to' improve th-eav'ailabilit-y and reliability of high quality, dependable, an~d affordable electrical poer.In addition to the'routine s'ys'tem upgrades and mainte-

~~ nance, a number of new investment projects have required their attenion, inclag a new city conference center, downtown

'lightinig and service improvements, new retail development along the SC 29corridor, and therenoaton told e hospital to craehuing for the low-inoeedrl h xansion o the city's fiber optic network to provide high spe~d cornnecivity!

between municipal buildings has' faciititk the delivery of city,

~services, quickened response times; andp, J~ied cost savings The utility~departfi~ent 'con"iue todo its part in the growth' and development of the cmumity, and in the preservation

-and enhancement of the qualityobflife

- ~ Tkn l fismany attractions andt resources into account;~it's,

-~siinple to understahd Newberiy's high nationa raiinsolst of the most appealing and livable 'small to~wns inAmierica.

Newerr EecticCustomer Data,.

"'J

-2000 2001 -2002 2003 2004 Total Customers 4,800-- 4,789 - 477 4,790 4,866 204Data -Revenue - Customers Residential - $3,908,000 - 400 Commercial - .$5,079,000 850 Industrial  ;$4, 354,000 - 4

-.. Total $13,341,000 4,866 Coincident Peak Non-Coincident Peak System Demand (KVW) - .26 076 t 36,393; Ne~wberry's Opera House isa focal point of the downtown restoration eff~orts.-'

-;..C i ..K -... .:

~~e it an' ;idea; I locati .100 t EV090t0

, iCL:, ff-0: F taX .-.-  :-. , ' -fff . , 0:'

Fm its modest beginnings,Rock Hill has become the largest city  : -... 0;DS - '-:.1:-- -I: f*

4  ;:

i York county and South Carolina's fifth largest with a population of more than 56,000.' The city's close proximity to the I-77 corridor-and the Charlotte, NC metropo litan area makes it an ilcon develpment . Accessible to the country's fifth largest for dvl

- area, approximately five miillion people are wit-hin a'100-mile_._,

-radius. High-amfenity industrial parks facilitate thielocatio'n anda~ 7 '

i- pa.:frdeeomet'Acssbet p aition of diverse, mode business -The city isofd:

and industry.lareart h onry's 0.'

also noted foruits service and retail develfptenht, ges dical facilities, arks and recreation areas, and,cultural attractions. The

-meritiuHihaeitidsrilakf t': ciltae the octov~atind t the city is undergoingmatrenaissance centered on a'mixed-use activity center surrounded by linked neighborhoods.> Inblenfdingj te old with the new, the redevelopm t inldsterenovto

-of abandoned mills, the preservation of historic housing, and the res ation and reuse oote historic structures. The plan -

'-- encompasses the campus'of Winthrop, now a University of.' =... -

more than 5,500 students.

The city owned and operated 'combined utility system has been providing electric service since 1911. Rock Hill Utilities serves.l its customers with a focus on community responsibility, resource

'adequacy and reiiability. .Through a comprehensive planning and

budgeting program, system administrators fund and execute the maintenance and new capital investments necessary to ensure that f

{ these 'objectives are met. Indcuded in the expansions and upgrades 4 for 2004 were multiple projects, including: the widening of Cherry Road to convert overhead lines to underground, improving appear-, -

ance and reliability; expansion of the fiber optic network for better l communication and control; replacement of dated equipment to.

f 0 .. match modern standards of operational efficiency; various lighting projects, including those at I-77 intersections;'modernization of traffic signals arid controls; and new service connections at loca-tions such as the Rock Hill Tennis Center and the Highland Park Mills senior housing project. '

All the ingredients are in place for continued growth and -

- developmient'in Rock Hill, and for further enhancements of its'.

exceptional quality of life. Care in the planning and development of the electric infrastructure will help support the realization of',

the high expectations for the future.

Rock Hill Electric Custo'mer Data';

.2000 2001 2002 2003 2004

'Total Customers 25,463 27,117 28,417 29,347 29,677

Data

,2004 - Revenues Customers I Residential - $26,081,000 26,458 Commerciailnd. - $33,194,000 -. ; 3,219 Total $59,275,000 -29,677 SystemDemandd(K) 161,345 163,620 r Rock Hill's new tennis center provides recreation opportunities for dtizens.

Highland Park Mills, a new community for seniors, creates an effcient new use for

-anold textile mill. -.

i  !

3 - z f

U~-nion i - .1 .1 I i - VI T,

I .

1-

i : 1,  :" , :7; Ihough'residents of Union enjoy the environmental benefits, leisurely pace,; and sall-town appeal affor by the area, they aed are within an hour's drive of three major metropolitah areas:-

Greenville, Spartanburg, and Charlotte. Since 1991, US highway - i

.4176 has provided a four-lane connection to Spartanburg and the

'rapid developnent'along Interstate 85 SC highway 49 links Union

-'to 1-26 and 1-385 providing access to Greenville, Columbia, and the, --

' port of Charleston.' These economic corridors provide new indus-' '

trial prospects a connection with the city of Union and the coun-

"ty'shundreds of acresof greenfield sites,; ridustrial parks,'and available buildings. With the decline' in textile employment, the

' area has an ample supply of skilled labor noted for their strong 4 -I s~~~work ethic. -As a progressive community w~ith a high quality of:.  ;

-- life and a low cost of living, Union has all 'the resources necessary..

' -to attract and sustain new growth and development..-:-' '

"<-Union is the largest city in Union County itapopulion '

--. 'ofapproximately 8,500. The local economy has suffered some l :i'setbacks from the de'cline in textile employment. 'However, the..

-outlook has improved with the announcement that a private company has purchased, and plans to reopen, a closed finishing-plant. More new investment is likely since current economic..

conditions qualify the city, and the county,' to 'offer the full' rane of available state and local industrial location incentives.

Theelectric division of the Utility Department operates and main-

-' tains the city's 'electric distribution system and serves over 7,000 -

customers effectively and efficiently bothinside and outside the

'corporate limits: With minimal expansion pressure in 2004, sys-

'term activities were focused on'operations and maintenance. Plans

'for a new generator were finalized to help meet peak load demands

.--'andhelp controlcosts. New lighting and wiring projects were '

undertaken in the downtown area as part of a major revitalization effort. Equipment replacement, and substation and right-of-way maintenance projects were accomplished to improve the quality -'

.- nddependability of the electic power infrastructure. Family .' e-apartments, under construdtion at the 'site ofd Union Mill, and newretail development created new service opportunities. -T l The city of Union and its utility services continue to uphold the "

service commitments and quality operations that have served the' in community so well in'the past. They also look foiward to the "

.' promise of the future with confidence,'strength of purpose, and reewdoptimism.' "

'UnionEle riC 'Customer Data""

':2000 2001. 2002

' 2003 20 -04

i' Customers'7,057 ' 7,092 .'7,097 Souta 7 071 7,046 Data ' -Revenues '-.atCustomers:'

Residential '. ' $6,785,000 5,968

- ' Commercial/ nd. --. ' $5 674 000 ' -1016 "Other $215000 '62 Total $12,674,000 046 Coincident Peak Non-Coincident Peak' System Demand (KM' i .29,154 '29419

'Ted Adams, Electrical Supervisor, stands at the site ofnewfamily apartments.

IThe strikingarchitecture of the countycourthouse anchors the historicdowntown t _area.

-Westminster eere inthelargest apple-producing area of the state,  :: - .. -

Westminster was selected as the site of the South Carolina Apple F_ estival which has drawn thousands of visitors to the area since f 1961. Westmiinster has over 100 homes-that reflect turn-of the-century architecture..

The Westminster Commission of Public s began serving thie community in the early 1920's and provides a reliable and '

affordable complimient of electrical services to residences and businesses., While recent employment losses have proven to-'

--be a challenge to -maintaining system demand, the economy has -

-remained resilientwvith-usage'stabilizing0. Mnaintenance and sys,._

ter improvements have continued as the structure of the town's 1 .-

utility services has been undergoing a significant realign-ieni.

-The organization of the utility function isunder review and will

--likely be changed to accommodate a'new 'management and lead -

ership structure.Renewed emphasis isbeingaedon definig .

coie valuis,'program'direction -and strategies followed b a reformulation of poicies and proceduresf This restructuring i expected to result in a service mechanism better suit to meet

- he currentneeds of the-comm and the challengessof the tunity . i .i 4 en~essef'moeii itoiprojects, suchi asi the conivesion ~ ~

K of mercury vapor street lights to high-pressure sodium lights, are ei conducted. New poplicies, programs and poducts will .

result in greater innovation and improved efficiency ofoperation as the town prepares to seek new avenues to support growth.2 0 an -

development. Strategic la cu on emerging areas of-Dcustomerdexand such as the potential offered by the growingW area of heritage and natunre-based tourism.' In an are so bssed wtattractive natural resources and an outstanding0 qualty of life the future lo'oks bright indeed., .

'Westminste:rEElec'tri c Customer Data 2000 2001 2002: 2003' 2004 Total Customers 170 1,671 .,1,648 1,662 1,9

- 2004 Data ReeusCustomers Resideritial '$1,477,000 1,393 Commercial $1410015929ib

-Total '$2,908,000 59 Coincident Peak - Non-Coincident Pea'k 11111 S.__ystem Demand (KW) .6,165 6,831 IDavi~dStnith, CPW Utility Director, explains changes that are underwvay in Westminster:.

Renovation efforts hope to preserve Ihe vitalityof te dwntown retail district. ... ____ 17 71i~~

.. .,.per.> ationa t t >U. .i .\ zm;Zit UX >S. . ; s~S' FS~4 EP.-1 H igh Iights

- - - - S - - v S ' - -~~~< --. 1-i--/-

PLANT INFORMATION Plant License Extensions Capacity Availability Duke requested License Extensions from the Factor Factor

• Nuclear Regulatory Commission (NRC) for both Catawba Unit 1 97.9% 98.0%

the McGuire and Catawba Stations in June 2001.

t.ZwrtM t - i-t-o Catawba Unit 2 89.1% 87.4% The NRC issued new operating licenses for the Li _ - .:.-.--- ;,=,_ _. ..:5=;I McGuire Unit 1 McGuire Unit 2 85.3%

103.4%

83.4%

100.0%

McGuire and Catawba Units on December 5, 2003. The operating licenses are extended as fol-E.s.,

,;;.>.,.re;. := - ._ ., 4: , ,' >3S ,,-'q5>: '-- t . 1

,,,, ,w, 5: . ~: E

_,X,_t,0s@ $'is~- v 5}59

w ,;> IR,, -,;t T numbers are reported by Duke Power Company to the These Nuclear Regulatory Commission inthe Units' December 2004 Operating Data Report.

lows:

Catawba Unit 1 December 2043 Catawba Unit 2 December 2043 Catawba Unit 1 was running for all of 2004 with McGuire Unit 1 June 2041 no scheduled refueling outage. The next refueling McGuire Unit 2 March 2043 outage for Unit 1 isscheduled to begin inMay 2005.

Security Catawba Unit 2 began a refueling outage on Following the 2001 terrorist attacks on the World September 11, 2004 that ended on October 24. Trade Center and the Pentagon, the nation's The unit completed a record continuous run of nuclear power plants came under scrutiny as 531 days - the longest for any nuclear unit on the potential targets. As a result, nuclear power plants Duke Power system. The next refueling outage is upgraded security measures. Under the contractual scheduled for March 2006. arrangement with PMPA, all issues of security are McGuire Unit 1 began a refueling outage on handled by Duke Energy. Duke coordinates closely March 6, 2004 that ended on April 12. The unit with federal, state and local authorities and contin-completed a continuous run of 512 days. The next ues to take appropriate steps to ensure safety and

• s -j-. .'ri5,- , , , ,r _ .:S- -' i- .b

= ' 4_,,j:t6 1b.'.'..

refueling outage isscheduled for September 2005. security at Catawba Nuclear Station.

,*;'i'-<'t McGuire Unit 2 began a refueling outage on March 1,2005 that isprojected to end on April 7.

The unit completed a continuous run of 506 days.

tY _;naiyyis in the .f;ollowing independent INVESTMENT PORTFOLIO STATISTICS DEBT OUTSTANDING (Dollars in $O00s) (Dollars in $000s)

Bonds Outstanding Earnings Information 12/31/03 $ 1,241,044 Income Rate of Return Matured 1/1/04 (20,860) 2004 $ 14,582 4.07% Refunded Bonds (447,043) 2003 $ 15,225 3.91% Refunding Bonds 446,370 5 S t i- l . -

Bonds Outstanding _ '.4 IjT<*_ ,:.'-

Market Value/Average Maturity as of 12, /31 12/31/04 $1,219,511 Market Average -. : t 4 0 3,',, ;r ',i' Value Maturity DEBT OUTSTANDING AS OF 12/31/04 2004 $ 356,173 2.1 Weighted 2003 $ 422,459 2.6 Bonds Average 5o ~~-

t5.> '-,'-=!2;sA Outstanding Interest Cost .5_:,. ,--- ; ,'*-*-

Fixed Rate Bonds*

2004 2003

$ 788,580

$ 950,215 5.32%

5.48% -1;-5 4.-

1

>.SvzrI.'-. . 4°...

-'- ;4_i, '<;

Variable Rate Bonds 5.;i ,, , @f, '-.I 2004 $ 320,200 1.21%

2003 $ 278,800 0.99%

Capital Appreciation Bonds 2004 $ 110,731 5.55%

2003 $ 12,029 7.53%

Total 2004 $1,219,511 4.35%

2003 $1,241,044 4.56% %1~'4-'-5' =5-'

,k

• 1

• Includes $60 million variable rate bonds

.~

~, ~ ~ ~.

~ i-i.. 20$ Anua

, ?4!_7 19:

Reor .Fta ndr .;.ii. .

synthetically swapped to fixed in 2004

- I Financial Highlights PMPA revenue comes from three SCHEDULE OF REVENUE AND EXPENSE PER THE primary sources: operating revenues; BOND RESOLUTION AND OTHER AGREEMENTS (Dollars in $000s) interest income; and withdrawals REVENUE from other funds. Expenses are catego- Sales to Participants $ 128,469 71%

rized by: debt service; operations and Sales to Other Utilities 17,796 10%

Withdrawal from Other Funds 19,701 11%

maintenance, purchased power; and Interest Income 14,582 8%

other deposits and expenses. Total $ 180,548 100%

EXPENSE Debt Service $ 89,991 50%

Operations & Maintenance 32,1 70 18%

Purchased Power 32,331 18%

General & Administrative 14,648 8%

Transmission & Distribution 5,848 3%

Payment in Lieu of Taxes 4,400 2%

Other Deposits 1,160 1%

Total $ 180,548 100%

REVENUE Sales to Other Utilities 10%

Interest Withdrawals Sales to from Other Participants Funds 71 Y 11%

EXPENSE Transmission General & & Distribution 30 Administrative  %

8% / - Payment in Lieu of Taxes Other npr8 \/ 2%

1%

Purchased Power 18% Debt Service 50%

Operationso f:

& Maintenance

. \.

18%

A.

0

\:

00208: 2004 Annual Repott C ,-3

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Independent Auditors' Report The Board of Directors Piedmont Municipal Power Agency W have audited the accompanying financial statements of Piedmont Municipal Power Agency (the Agency) as of and for the years ended December 31, 2004 and 2003, as listed in the table of contents. These financial statements are the responsibility of the Agency's man-agement. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material mis-statement. An audit includes consideration of internal control over financial reporting. As a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Agency's internal control over financial reporting. Accordingly, we express no such opinion. 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, the financial statements referred to above present fairly, in all material respects, the financial position of the Agency, as of December 31, 2004 and 2003, and the changes in its financial position and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in note 2(N) to the financial statements, the Agency adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting forAsset Retirement Obligations, effective January 1, 2003.

The management's discussion and analysis on pages 23 through 27 is not a required part of the financial statements but is supplementary information required by accounting prind-ples generally accepted in the United States of America. We have applied certain limited proce-dures, which consisted principally of inquiries of management regarding the methods of measurement and presentation of the required supplementary information. However, we did not audit the information and express no opinion on it.

Our audits were conducted for the purpose of forming an opinion on the Agency's finan-cial statements taken as a whole. The supplementary information included in schedules 1 and 2 is presented for purposes of additional analysis and is not a required part of the financial statements. The accompanying schedules have been prepared in accordance with the Bond Resolution. Such information has been subjected to the auditing procedures applied in the audits of the financial statements and, in our opinion, is fairly stated in all material respects in relation to the financial statements taken as a whole.

March 25, 2005 22 2004 Annual Report

Management's Discussion & Analysis Overview of the Financial Statements This section of Piedmont Municipal Power Agency's (PMPA) annual financial statements presents our analysis of PMPA's financial performance during the fiscal year that ended December 31, 2004. Please read this discussion and analysis in conjunction with the financial statements which follow this section.

Financial Highlights PMPA's total assets as of December 31, 2004 increased by $10.7 million over the prior year. This increase primarily consists of additions to noncurrent assets including net costs recoverable from future Participant billings offset by decreases in investments.

A portion of the aforementioned increases were offset by a decrease in current assets where funds were used to meet 2004 operating expenses as well as to fund equity contributions relating to a restructuring of our outstanding debt portfolio completed in 2004.

Total liabilities at December 31, 2004 decreased by $6.4 million co 'ntents when compared with December 31, 2003. A portion of this decrease is the result of the 2004 debt restructuring where bond-related liabilities were reduced by $18.8 million when compared to the prior year. Miscellaneous current liabilities and reserves for Independent Auditors'. Report. 22 decommissioning increased by $4.9 million and PMPA recognized Maaemn' Disusio a $7.5 million liability for derivative instruments at December 31,

: 5;r.Management's Discusso ;...........0:. .  :- E

and Analysis 23-27 2004.

As a direct result of the Nuclear Regulatory Commission's Financial Statements' approval of the Catawba Nuclear Station's license extension from 2024 and 2026 for units one and two, respectively, to 2043 for

- Statements of Net Assets 28 both units, the Agency restructured a portion of its outstanding debt by extending the final maturity of its bonds an additional Statements of Revenues, Expenses, - nine years to 2034. This debt extension, completed in August and Changes in Net Assets - 29 2004, is expected to reduce debt service by an average annual

. nS amount of $15 million per year through January 1, 2025. In

-Statements of Cash Flows 30 order to complete this restructuring, debt issuance expense was funded with $23 million in equity contributions and the net Notes to Fiancial Statements 31-44 A. effect on bonds payable was a decrease of $673,000.

Supplementary Information Overview of the Financial Statements The following is an overview of the financial activities of PMPA

- - Schedule of Revenue and Expenses Actual and Budget for the years ended December 31, 2004 and 2003.

Per the Bond Resolution PMPA's financial statements, which include the statements of net and Other Agreements 46 assets, the statements of revenues, expenses and changes in net assets, and the statements of cash flows, are presented to display Schedule of Revenue . information about the reporting entity as a whole in accordance

~ ~~~n

-p¢se

-~ Per;', -'

Dadxpne~e-~~

-. with GASB No. 34. The statements are prepared using the eco-

-- theBondResolution -a--S.- nomic resources measurement focus and the accrual basis of and Other Agreements 47 . accounting.

2004 Annual Report 23 A

Management's Discussion & Analysis FINANCIAL INFORMATION The following summarizes the activities of PMPA for the years 2004 and 2003:

2004 (I____2003 Revenues: (In thousands)

Sales of electricity to Participants $127,393 $ 123,479 Sales of electricity to other utilities and other operating revenues 18,872 17,249 Total operating revenues 146,265 140,728 Interest income 14,582 15,225 Other 4,232 4,222 Total revenues 165,079 160,175 Expenses:

Operation, maintenance, and nuclear fuel amortization 29,452 29,067 Purchased power, transmission, and distribution 38,179 32,092 Administrative, general, and property taxes 19,048 17,399 Depreciation 6,834 18,969 Interest and amortization expense 70,726 73,422 Net decrease infair value of investments and derivative instruments 16,826 8,165 Other 7,408 8,134 Total expenses 188,473 187,248 Net expenses recoverable from future Participant billings 40,545 40,009 Income before cumulative effect of a change inaccounting principle 17,151 12,936 Cumulative effect of a change inaccounting principle - 4,068 Change in net assets 17,151 17,004 Netassets-beginning 65,184 48,180 Net assets-ending $ 82,335 $ 65,184 RESULTS OF OPERATIONS Revenues Sales of Electricity to Participants. PMPA's primary source of revenue increased in 2004 by over 3% or approximately $3.9 million.

A2.08% rate increase implemented on May 1, 2004 coupled with a 5.8% increase in energy sales are the primary components of the revenue increase.

Surplus energy sales to third parties contributed to a 9% increase in sales of electricity to other utilities due to an 11% increase in available energy and improved market pricing. High competitive market pricing for oil and gas generation boosted the PMPA market rate charged for surplus energy from 25 mills in 2003 to 29 mills in 2004, a 16% increase in price.

Expenses Purchased power expenses increased by 19%, or approximately $6.1 million, in 2004. PMPA purchases supplemental capacity and energy through an Interconnection Agreement with Duke Power. These purchases are tied to contractual formulas which are tied to generation of other Catawba owners. Due to the fact that certain Catawba owners have cancelled portions of their Interconnection Agreements with Duke Power, their generation strategies have changed as a result, thus causing PMPA's contrac-tual formula rates charged by Duke to increase in 2004. PMPA has given notice to Duke of its intent to cancel PMPA's Interconnection Agreement with Duke on January 1, 2006, at which time we expect to begin purchasing supplemental power from Southern Company, and removing much uncertainty from purchased power pricing.

24 2004 Annual Report

Management's Discussion &Analysis Depreciation of PMPA's ownership share of the Catawba Nuclear Station has declined as a result of the Nuclear Regulatory Commission's approval of the Catawba license extension. The remaining undepreciated plant value is depreciated over the remaining plant life, which is forty years.

PMPA entered into a floating to fixed rate step-coupon swap as part of the 2004 debt restructuring that helped to produce level debt service without issuing more capital appreciation debt and increased the benefits of the restructuring through January 1, 2025. Under this step-coupon swap, PMPA will pay a below market rate of interest for the first twenty years and an above market rate for the last ten years resulting in an approximate market rate over the entire term of the swap. This swap was designed to minimize the amount of Capital Appreciation bonds PMPA needed to issue as part of the 2004 restructuring. By paying an artificially low rate for the first twenty years, should the swap terminate during this period, it is likely that PMPA would owe a payment to the swap counterparty. This negative valuation comprises the majority of the increase in the net decrease in the fair value of investments for 2004.

In 2003 the cumulative effect of a change in accounting principle resulted from the Agency's adoption of SFAS No. 143 on January 1, 2003, regarding Accounting for Asset Retirements. Generally, this rule requires asset retirement obligations which are legally enforceable to be accrued as additional plant costs and amortized over the life of the related asset. In accordance with the transition provisions, the Agency recorded an obligation and corresponding asset of $22.9 million as of the date the liability was incurred. Concurrently, the Agency recorded accretion of the obligation and depreciation expense of $32.2 million and $6.8 mil-lion, respectively, for the period from the date the obligation was incurred throughJanuary 1, 2003. This resulted in a net cumu-lative-effect-type adjustment of $4.1 million in the statement of revenues, expenses, and changes in net assets for the year ended December 31, 2003.

Assets, liabilities, and net assets are summarized as follows:

2004 2003 Assets: (inthousands)

Capital assets $ 294,146 $ 292,982 Current unrestricted assets 188,569 246,166 Current restricted assets 188,246 198,983 Other noncurrent assets 725,797 647,891 Total assets $ 1,396,758 $ 1,386,022 Liabilities:

Long-term liabilities $ 1,230,961 $ 1,238,232 Current liabilities 83,462 82,606 Total liabilities 1,314,423 1,320,838 Net assets:

Invested in capital assets, net of related debt (900,454) (908,243)

Restricted for debt service 58,453 62,308 Restricted for other 14,924 15,087 Unrestricted 909,412 896,032 Total net assets 82,335 65,184 Total liabilities and net assets $ 1,396,758 $ 1,386,022 Changes in PMPA's current unrestricted assets include decreases in the Rate Stabilization Account balance of approximately $20 million to fund operations, as well as $23 million to fund equity contributions to the 2004 bond restructuring. These $20 million funds were used as part of 2004 planned budget withdrawals to stabilize annual rate increases to the Participants, and the $23 million was used to implement a debt restructuring designed to show significant reduction in debt service in future years through 2024. The remaining decrease in unrestricted assets involve decreases in working capital funds used for operations, reductions in working capital funds required to be on hand by Duke Power and decreases in the market valuation of investments.

Restricted assets decreased primarily as a result of the resizing of the required balances of PMPA's debt service reserve accounts due to the 2004 debt restructuring.

2004 Annual Report 25

Management's Discussion & Analysis Noncurrent assets increased as revenues collected from prior periods were recognized due to the use of Rate Stabilization Funds. Other noncurrent asset increases include increase in debt issuance costs and costs on advance refunding of debt related to the 2004 debt restructuring.

As bonds matured on January 1, 2004, long-term repayment obligations that were funded in the prior year were retired, resulting in a decrease in debt outstanding.

CAPITAL ASSETS PMPA's capital assets include structures and improvements, reactor plant equipment, turbo generator units, other equipment and nuclear fuel. Such amounts are detailed as follows:

2004 2003 (Inthousands)

Structures and improvements $ 157,609 $ 154,690 Reactor plant equipment 247,572 247,572 Turbo generator units 69,270 69,270 Other equipment 76,655 75,467 Nuclear fuel 33,901 36,611 Other 29,384 30,167 Construction in progress 9,873 7,578 Total 624,264 621,355 Less accumulated depreciation (330,118) (328,373)

Total, net $ 294,146 $ 292,982 PMPA's capital assets include generation facilities, nuclear fuel, equipment and buildings as detailed above. PMPA's investment in capi-tal assets at December 31, 2004 totaled $294.1 million (net of accumulated depreciation), a $1.2 million increase over 2003. Major capital transactions during the year included the following:

• Additions, net of retirements, to Catawba Plant of approximately $2.9 million.

• Transmission plant additions of $1.2 million.

a Decrease in nuclear fuel of $2.7 million ($7.6 million was added to fuel and $10.3 million of fully amortized fuel was written off).

• Construction work in process representing $2.3 million of capital additions at Catawba.

• Depreciation and amortization expense of $13.1 million.

Duke Energy Corporation, acting on behalf of the owners of the Catawba Nuclear Station (Station), in June 2001, filed an application for a 20-year extension of the license for Units 1 and 2 with the NRC. Following extensive reviews of this request, on December 5, 2003, the NRC approved the issuance of renewed operating licenses that will allow the Station to operate and produce electricity to 2043. Catawba's original licenses for each unit were scheduled to expire in 2024 and 2026, respectively. Due to this extension, the Catawba Nuclear Station will be depreciated on a straight line basis over the remaining expected and extended useful life of the Station, through December 2043.

DEBT MANAGEMENT Following the favorable results on the relicensing application discussed above, PMPA, in August of 2004, undertook a major debt restructuring and extension of its debt portfolio to restructure a portion of its outstanding bonds to reduce debt service through January 1, 2025 by extending debt service over a portion of the extended license period.

PMPA offered two refunding issues, as follows. The first issue, Electric Revenue Bonds 2004A Refunding Series, aggregated

$205,970,042 and consisted of $103,300,000 of federally taxable bonds and $102,670,042 of Capital Appreciation Bonds (CABs).

The second issue, Electric Revenue Bonds, 2004B Refunding Series, totaled $240,400,000 and consisted of Variable Rate Demand Obligations (VRDOs). In conjunction with the VRDO issue, PMPA entered into a floating to fixed rate step coupon swap to convert some of its variable payment to a synthetic fixed rate. This step-coupon swap, which is designed to emulate a CAB structure at a lower 26 2004 Annual Report

Management's Discussion & Analysis (DOLLARS IN $OOOs) cost while reducing the amount of CABs that had to be issued in the open market, is structured so that PMPA would pay an artifi-cially low fixed rate of interest through January 1, 2025 and an artificially high rate of fixed rate interest from January 1, 2025 through January 1, 2034, while receiving a variable rate equal to the Bond Market Association Municipal Swap Index on a notional amount of $60 million.

The overall effect of these restructuring actions is to:

• Extend a portion of PMPA's debt service to January 1, 2034, nearing the full term of the Catawba Project Power Sales Agreements (which terminate August 1, 2035).

• Decrease annual costs during the existing debt service period (through 2024) by extending debt service over a portion of the extended license period. Expected average annual savings of $15 million are projected through 2024.

• Produce substantially level annual debt service.

• More closely match debt service to the useful life of the Catawba Project, thus effectively spreading the related revenue requirement ratably over the period expected to benefit from the use of the assets.

PMPA's total debt decreased $21.5 million during the year of which $20.9 million was paid January 1, 2004 in accordance with debt service schedules and $0.6 million was paid as part of a debt restructuring described above.

In July 2004 PMPA's bond ratings were raised by Standard and Poor's Corporation from BBB- to BBB with the outlook remaining at stable. Moody's Investors Service changed its outlook from positive to stable while maintaining its Baa3 rating and FitchRatings remained unchanged at BBB with a stable outlook.

ECONOMIC FACTORS & NEXT YEAR'S RATES PMPA Participants have weathered the relocation of textile manufacturing facilities to overseas competition and have seen improve-ments in economic development in 2004. The fiscal year 2005 budget allows for a 1.8% growth in demand and energy and a 1.26%

rate increase to Participants.

Increases in market rates for generating fuel have had a positive effect on PMPA as we collect more for surplus energy sales and are somewhat isolated from the swings in oil and gas fuel prices as we are dependent on nuclear fuel sources.

REQUEST FOR INFORMATION This financial report is provided as an overview of PMPA's finances. Questions concerning any of the information in this report or requests for additional information should be directed to the office of Suzanne Armendariz, Director of Finance, Piedmont Municipal Power Agency, 121 Village Drive, Greer, South Carolina 29651.

2004 Annual Report 27

Statements of Net Assets DECEMBER 31, 2004 AND 2003 (DOLLARS IN $OOOs)

ASSETS 2004 2003 Capital assets (note 5):

Utility plant assets being depreciated $ 614,055 $ 613,441 Accumulated depreciation and amortization (330,118) (328,373)

Total utility plant assets being depreciated, net 283,937 285,068 Utility plant assets not being depreciated 10,209 7,914 Total capital assets, net 294,146 292,982 Current assets (note 7):

Cash 11,293 12,353 Marketable debt securities 155,502 208,381 Accrued interest receivable 1,132 2,742 Participant accounts receivable 9,475 10,069 Other accounts receivable 5,446 3,573 Materials and supplies 5,721 6,110 Derivative financial instruments (note 15) 2,938 Total current unrestricted assets 188,569 246,166 Restricted assets (note 6):

Restricted for debt service 123,694 136,226 Restricted for decommissioning 49,628 47,670 Restricted for other 14,924 15,087 Total current restricted assets 188,246 198,983 Total current assets 376,815 445,149 Noncurrent assets:

Unamortized debt issuance costs 35,989 16,305 Net costs recoverable from future Participant billings (note 8) 525,138 484,593 Costs on advance refunding of debt, net 162,632 144,790 Other 2,038 2,203 Total other assets 725,797 647,891 Total assets $ 1,396,758 $ 1,386,022 LIABILITIES AND NET ASSETS Long-term liabilities (notes 9 and 10):

Bonds payable, net $ 1,170,200 $ 1,180,365 Reserve for decommissioning (note 11) 60,761 57,867 Total long-term liabilities 1,230,961 1,238,232 Current liabilities:

Accounts payable and accrued liabilities 10,707 8,688 Derivative financial instruments (notes 7 and 15) 7,514 18,221 8,688 Current liabilities payable from restricted assets:

Accrued interest payable 40,841 53,058 Current installments of bonds payable 24,400 20,860 Total current liabilities payable from restricted assets 65,241 73,918 Total current liabilities 83,462 82,606 Total liabilities 1,314,423 1,320,838 Net assets:

Investment in capital assets, net of related debt (900,454) (908,243)

Restricted for debt service 58,453 62,308 Restricted for other 14,924 15,087 Unrestricted 909,412 896,032 Total net assets 82,335 65,184 Total liabilities and net assets $ 1,396,758 $ 1,386.022 See accompanying notes to financial statements.

28 2004 Annual Report

Statements of Revenues, Expenses, and Changes in Net Assets YEARS ENDED DECEMBER 31, 2004 AND 2003 (DOLLARS IN $00s) 2004 2003 Operating revenues:

Sales of electricity to Participants $ 127,393 $ 123,479 Sales of electricity to other utilities 17,796 16,173 Other 1,076 1,076 Total operating revenues 146,265 140,728 Operating expenses:

Operation and maintenance 23,158 22,800 Nuclear fuel amortization 6,294 6,267 Purchased power (note 4) 32,331 26,023 Transmission 4,652 4,678 Distribution 1,196 1,391 Administrative and general 14,648 13,164 Depreciation (note 5) 6,834 18,969 Decommissioning 2,894 2,756 Payments in lieu of property taxes 4,400 4,235 Total operating expenses 96,407 100,283 Operating income 49,858 40,445 Nonoperating revenues (expenses):

Interest income 14,582 15,225 Net decrease infair value of investments and derivative instruments (16,826) (8,165)

Interest expense (58,859) (61,070)

Amortization expense (11,867) (12,352)

Other expense, net (282) (1,156)

Total nonoperating expenses, net (73,252) (67,518)

Loss before deferred items and cumulative effect of a change in accounting principle (23,394) (27,073)

Net expenses recoverable from future Participant billings (note 8) 40,545 40,009 Income before cumulative effect of a change inaccounting principle 17,151 12,936 Cumulative effect of a change inaccounting principle (note 2(N)) 4,068 Change in net assets 17,151 17,004 Net assets at beginning of year 65,184 48,180 Net assets at end of year $ 82,335 $ 65,184 See accompanying notes to financial statements.

2004 Annual Report 29

Statements of Cash Flows YEARS ENDED DECEMBER 31, 2004 AND 2003 (DOLLARS IN $009s) 2004 2003 Cash flows from operating activities:

Receipts from customers $ 127,318 $ 123,698 Payments for operations and maintenance (23,158) (22,800)

Payments for purchased power, transmission and distribution (19,289) (14,159)

Payments for administrative and general (18,024) (17,542)

Net cash provided by operating activities 66,847 69,197 Cash flows from investing activities:

Purchase of investment securities (487,758) (334,524)

Proceeds from sales and maturities of investment securities 545,748 348,416 Interest received on investments 15,167 15,480 Interest received on Duke working capital 277 491 Interest received on derivative instruments 4,143 4,189 Net cash provided by investing activities 77,577 34,052 Cash flows from capital and related financing activities:

Proceeds from issuance of bonds 446,308 Refunding of bonds (469,830)

Payments of bond principal (20,860) (21,965)

Interest payments on bonds (56,553) (55,782)

Debt issuance costs (25,855)

Payments for arbitrage liability (137)

Expenditures for electric plant inservice (6,686) (4,362)

Expenditures for nuclear fuel (7,606) (10,421)

Payments to Duke for other charges (3,233) (4,899)

Other (1,032) (869)

Net cash used incapital and related financing activities (145,484) (98,298)

Net increase (decrease) in cash (1,060) 4,951 Cash at beginning of year 12,353 7,402 Cash at end of year $ 11,293 $ 12,353 Reconciliation of operating income to net cash provided by operating activities:

Operating income $ 49,858 $ 40,445 Adjustments to reconcile operating income to net cash provided by operating activities:

Depreciation and fuel amortization 13,128 25,236 Reserve for decommissioning 2,894 2,756 Decrease (increase) in:

Participant accounts receivable 594 (339)

Other accounts receivable (1,536) 669 Materials and supplies :389 (137)

Increase in:

Accounts payable and accrued liabilities 1,520 567 Net cash provided by operating activities $ 66.847 $ 69.197 Noncash investing, capital, and financing activities:

Net decrease infair value of investments and derivative instruments $ (16.826) $ (8.165)

Recording of reserve for decommissioning and corresponding asset upon adoption of SFAS No. 143 $ $ 22,900 See accompanying notes to financial statements.

30 2004 Annual Report

Notes to Financial Statements December 31, 2004 and 2003 (DOLLARS IN $0Os)

1. DESCRIPTION OFTTHE ENTITY, INDUSTRY RESTRUCTURING DEVELOPMENTS, AND RELATED UNCERTAINTIES A. Description of the Entity Piedmont Municipal Power Agency (Agency) was incorporated in 1979 under the South Carolina Joint Municipal Electric Power and Energy Act. The Act, adopted April 1978, enabled the formation, by South Carolina municipalities and municipal commissions of public works, of a joint agency to plan, finance, develop, own, and operate electric generation and transmission facilities. Ten municipal utility systems (Participants) comprise the Agency's membership. The Participants, located in northwest-ern South Carolina, are the cities of Abbeville, Clinton, Easley, Gaffney, Greer, Laurens, Newberry, Rock Hill, Union, and Westminster.

The Agency and Duke Power Company (Duke) are parties to agreements giving the Agency a 25% undivided ownership interest in Catawba Nuclear Station Unit 2 (Project). Duke is the operating owner of the Project. The Agency's Project power output entitlements (approximately 286 MW) come from Catawba Nuclear Station Units 1 and 2; subject to the terms of the Interconnection Agreement containing the "Catawba Reliability Exchange" provision under which the Agency pays 12.5% of the costs and receives 12.5% of the power output associated with each of these 1,145 MW units. Additionally, the terms of the Interconnection Agreement containing the "McGuire Reliability Exchange" provision which allows transfers of energy between the Agency's resulting entitlements from the Catawba Units and Duke's two nuclear units at McGuire Nuclear Station. The operating licenses for Catawba Unit 1 and Unit 2 expire on December 5, 2043.

B. Industry RestructuringDevelopments and Related Uncertainties The Agency has developed a strategic plan to help guide it through the potential industry changes. The plan includes periodic reviews of the recoverability of regulatory assets and the impact of such recovery on the Agency's rates. The Agency's manage-ment is participating in the deregulation debate, both on the national and state level.

In the event that the electric utility industry is restructured, the Agency and the Participants can expect to have as their major competition the investor-owned utilities and rural electric cooperatives presently operating in South Carolina and independent power producers, power marketers and others that may offer retail and wholesale services in South Carolina after restructuring.

The Participants' present retail electric rates are higher, on average, than the present retail electric rates of the area's investor-owned utilities.

The Agency's present charges to the Participants, together with planned withdrawals from the Rate Stabilization Account, are suf-ficient to recover all of the Agency's current costs of supplying the Participants' bulk power supply. Currently each Participant is able, and under its Power Sales Agreements is required, to set its rates at levels necessary to pay all the costs of its electric utility system, including the Agency's charges for supplying power to the Participants. However, studies by the Agency indicate that, in a deregulated electric utility industry, anticipated market-based retail rates would be lower than those that the Participants would need to charge to pay the Agency's costs and the expenses of their electric utility systems. These circumstances could give rise to stranded investments of the Agency and the Participants and the need for stranded investment recovery by the Agency and the Participants.

For the Agency and the Participants to be competitive in a deregulated retail electric utility industry, the Agency and the Participants must recover the Agency's substantial stranded investments in the Project. The Agency expects the methods by which it and the Participants may recover some or all of these stranded investments would come from legislative initiatives. As a result of the foregoing described uncertainties, including the inability to predict the outcome of the legislative process, no assur-ance can be given that the Agency and the Participants would be able to recover, in whole or in part, these stranded investments in the event of deregulation of the retail electric utility industry.

2.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES A. Basis of Accounting The financial statements have been prepared in accordance with the provisions of GASB Statement No. 34, Basic Financial Statements - and Managemenit's Discussion and Analysis - for State and Local Governments as amended by GASB Statement No. 37, Basic FinancialStatements - andManagement's Discussion and Analysis - for State andLocal Governments: Omnibus and GASB Statement No. 38, CertainFinancialStatement Disclosures. Statement No. 34 requires as supplementary information Management's Discussion and Analysis, which includes an analytical overview of the Agency's financial activities.

The Agency's accounting records are maintained on an accrual basis in conformity with accounting principles generally accepted in the United States of America and substantially in conformity with the Federal Energy Regulatory Commission's Uniform System of Accounts.

The Agency follows the accounting practices set forth in Statement of Financial Accounting Standards No. 71 (SFAS No. 71),

Accounting for the Effects of Certain Types of Regulation, as amended. This standard allows the Agency to capitalize or defer certain costs or revenues based on the Agency's ongoing assessment that it is probable that such items will be recovered through future revenues based on the rate-making authority of the Agency's board of directors (Board). The criteria require consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized cost.

2004 Annual Report 31

Notes to Financial Statements (continued)

(DOLLARS IN $OOOs)

The Agency's General Bond Resolution requires that its rate structure be designed to produce revenues sufficient to pay operating, debt service, and other specified costs. The Agency's Board, which is comprised of representatives of the Participants, is responsi-ble for reviewing and approving the rate structure. The application of a given rate structure to a given period's electricity sales may produce revenues not intended to pay that period's costs, and conversely, that period's costs may not be intended to be recovered in period revenues. The affected revenues and/or costs are, in such cases, deferred for future recognition. The ultimate recognition of deferred items is correlated with specific future events, primarily payment of debt principal.

Under Governmental Accounting Standards Board (GASB) Statement No. 20, Accounting and FinancialReporting for Proprietary Funds and Other Governmental Entities that Use ProprietaryFund Accounting, the Agency has adopted the option to apply Financial Accounting Standards Board (FASB) statements and interpretations that do not conflict with or contradict GASB pronouncements.

B. Unamortized Debt Issuance Costs Unamortized debt issuance costs at December 31, 2004 and 2003 of $35,989 and $16,305, respectively, (net of accumulated amor-tization of $9,012 and $18,225, respectively) are being amortized over the term of the related debt.

C. Costs on Advance Refundings of Debt Costs on advance refundings of debt at December 31, 2004 and 2003 of $162,632 and $144,790, respectively, (net of accumulated amortization of $171,492 and $159,914, respectively) have been deferred in accordance with SFAS No. 71 and are being amor-tized over the term of the debt issued on refunding.

D. Discounts on Bonds Payable The discounts on bonds payable at December 31, 2004 and 2003 of $25,476 and $40,620, respectively, (net of accumulated amor-tization of $18,505 and $37,631 respectively) are being amortized on the bonds outstanding method, which approximates the effective interest method.

E. Premiums on Bonds Payable The premiums on bonds payable at December 31, 2004 and 2003 of $565 and $801, respectively, (net of accumulated amortiza-tion of $838 and $2,333, respectively) are being amortized on the bonds outstanding method, which approximates the effective interest method.

F. Income Taxes The Agency is recognized as a public utility for federal income tax purposes. As such, gross income of the Agency is excluded from federal income taxes under Internal Revenue Code Section 115.

G. Cash Flows For purposes of the statements of cash flows, the Agency considers deposits with banks and Duke to be cash.

H. Marketable Debt Securities As authorized by the General Bond Resolution, investment securities at December 31, 2004 and 2003 consist only of direct obliga-tions of the United States government and obligations of United States government agencies. These investments are uninsured and unregistered and are held by the Agency's trustee in the Agency's name.

Marketable debt securities are recorded at fair value. Unrealized holding gains and losses on marketable debt securities are includ-ed in income. Interest income is recognized when earned.

1. Capital Assets Electric plant in service, including unclassified assets, is stated at cost and is depreciated on a straight-line basis at rates calculated to depreciate the composite assets over their respective estimated useful lives. Depreciation begins when assets are placed into service. The Agency's annual provision for depreciation expressed as a percentage of the average balance of depreciable utility plant was 1.1% for 2004 and 3.3% for 2003.

1. Materials and Supplies Materials and supplies inventories are stated at lower of cost or market using the average cost method.

K. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

L Net Assets Net assets are categorized as invested in capital assets, net of related debt, restricted and unrestricted.

Net assets invested in capital assets, net of related debt, is intended to reflect the portion of net assets which are associated with nonliquid, capital assets less outstanding capital asset related debt.

32 2004 Annual Report I Ul

Notes to Financial Statements (continued)

(DOLLARS IN $000s)

Restricted net assets are assets that have third-party (statutory or bond covenant) limitations on their use. When both restricted and unrestricted resources are available, restricted resources will be used first for incurred expenses, and then unrestricted as needed.

Unrestricted assets consist of all other net assets not included in the previous categories.

M. Revenue Recognition The Agency recognizes revenue on sales when the electricity is delivered to the customers. Accounts receivable are recorded at the invoiced amount and do not bear interest. The Agency has not recorded an allowance for doubtful accounts as it historically had not had any collection problems or write-offs.

N. Recently Adopted Accounting Standards On January 1, 2003, the Agency adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires an entity to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets.

In accordance with the transition provisions of SFAS No. 143, on January 1, 2003, the Agency recorded an obligation and corre-sponding asset of $22,900 as of the date the liability was incurred. Concurrently, the Agency recorded accretion of the obligation and depreciation expense of $32,211 and $6,793, respectively, for the period from the date the obligation was incurred through January 1, 2003, and removed its existing reserve for decommissioning of $43,072 as of January 1, 2003. This resulted in a net cumulative-effect-type adjustment of $4,068 in the statement of revenues, expenses, and changes in net assets for the year ended December 31, 2003.

0. Derivative Financial Instruments All derivatives are recognized on the statements of net assets at their fair value. The Agency has not designated any of its derivatives as hedges. Changes in the fair value of derivative instruments are reported in current-period revenues and expenses.

3. POWER SALES AGREEMENTS A. Catawba Project PowerSales Agreements The Agency and each Participant are parties to Catawba Project Power Sales Agreements (Sales Agreements). These Sales Agreements oblige the Agency to provide each Participant a share of Project power output and, in turn, each Participant must pay its share of Project costs. Participants make their payments on a "take-or-pay" basis whether or not the Project is operable or operating. Such payments are not subject to reduction or offset and are not conditioned upon performance by the Agency or any given Participant.

The Sales Agreements are in effect until the earlier of August 1, 2035, or the completion of payments on the bonds and satisfaction of obligations under the Project agreements.

The Participants' Shares of the Agency's Catawba Project Output are as follows:

City of Abbeville 2.68%

City of Clinton 7.84%

City of Easley 13.24%

City of Gaffney 10.05%

City of Greer 9.34%

City of Laurens 6.49%

City of Newberry 10.47%

City of Rock Hill 28.04%

City of Union 10.01%

City of Westminster 1.84%

100.00%

B. Supplemental Power Sales Agreements The Agency and each Participant are also parties to Supplemental Power Sales Agreements (Supplemental Agreements) under which each Participant has agreed to pay, in exchange for supplemental bulk power supply, its share of supplemental bulk power supply costs. A Participant may terminate its Supplemental Agreement with ten years advance notice.

4. PROJECT AGREEMENTS Project Agreements between the Agency and Duke consist of the Catawba Nuclear Station Purchase, Construction and Ownership Agreement (the Purchase Agreement), the Catawba Nuclear Station Operating and Fuel Agreement (the Operating Agreement), and the Catawba Nuclear Station Interconnection Agreement (the Interconnection Agreement).

A. Purchase Agreement This agreement between the Agency and Duke provides for the purchase of the Catawba Project by the Agency. It also details Duke's responsibilities, as engineer-contractor, for construction, initial fueling, and placing the Catawba Nuclear Station into com-mercial operation.

B. OperatingAgreement This agreement, between the Agency and Duke, provides for Duke, as operator for the Agency, to be responsible for the operation, 2004 Annual Report 33

Notes to Financial Statements (continued)

(DOLLARS IN $000s) maintenance, and fueling of Catawba and for making of renewals, replacements, and capital additions. In addition, the Operating Agreement provides for decommissioning of Catawba at the end of its useful life pursuant to the terms of a decommissioning agreement, separate from the Operating Agreement.

C. InterconnectionAgreement This agreement, between the Agency and Duke, provides for interconnection of the Agency's ownership share of Catawba Unit 1 with the Duke system. As part of the Interconnection Agreement, the Agency is allowed to exchange capacity and output of four nuclear units. The agreement also provides for sale by the Agency of surplus energy to Duke and third parties. It also makes provi-sion for the purchase of supplemental capacity and energy, transmission services, and reserve purchases. Amounts due from Duke for surplus energy and exchange capacity sales are netted against amounts payable to Duke for the operation of the Catawba plant.

The agency has notified Duke of its intent to cancel the Interconnection Agreement effective January 1, 2006, and has contracted with Southern Power Company and Southern Company Services, Inc. to purchase supplemental capacity and energy and reserve purchases until December 31, 2010.

5. CAPITAL ASSETS The following is a summary of capital asset activity for the years ended December 31, 2004 and 2003:

December 31, 2004 Beginning Ending Utility plant being depreciated: balance Increase Decrease balance Structures and improvements $ 154,690 $ 3,745 $ (826) $ 157,609 Reactor plant equipment 247,572 247,572 Turbo generator units 69,270 69,270 Accessory electric equipment 50,586 50,586 Miscellaneous plant equipment 18,131 18,131 Station equipment 5,508 21 5,529 Transmission equipment 1,242 1,167 2,409 Other 24,846 48 (6) 24,888 Unclassified 4,985 (825) 4,160 Nuclear fuel 36,611 7,606 (10,316) 33,901 Total utility plant assets being depreciated 613,441 12,587 (11,973) 614,055 Less accumulated depreciation and amortization (328,373) (13,128) 11,383 (330,118)

Total utility plant assets being depreciated, net 285,068 (541) (590) 283,937 Utility plant assets not being depreciated:

Land 336 - - 336 Construction work-in-progress 7,578 6,639 (4,344) 9,873 Total utility plant assets not being depreciated 7,914 6,639 (4,344) 10,209 Total capital assets, net $ 292,982 $ 6,098 $ (4,934) $ 294 146 December 31, 2003 Beginning Ending Utility plant being depreciated: balance Increase Decrease balance Structures and improvements $ 155,689 $ 7 $ (1,006) $ 154,690 Reactor plant equipment 247,777 (205) 247,572 Turbo generator units 69,270 69,270 Accessory electric equipment 50,602 (16) 50,586 Miscellaneous plant equipment 16,749 1,386 (4) 18,131 Station equipment 5,508 5,508 Transmission equipment 1,242 1,242 Other 1,925 22,974 (53) 24,846 Unclassified 4,910 75 4,985 Nuclear fuel 31,870 10,421 (5,680) 36,611 Total utility plant assets being depreciated 585,542 34,863 (6,964) 613,441 Less accumulated depreciation and amortization (303,385) (32,029) 7,041 (328,373)

Total utility plant assets being depreciated, net 282,157 2,834 77 285,068 Utility plant assets not being depreciated:

Land 336 336 Construction work-in-progress 4,835 4,351 (1,608) 7,578 Total utility plant assets not being depreciated 5,171 4,351 (1,608) 7,914 Total capital assets, net $ 287,328 $ 7,185 $ (1,531) $ 292,982 34 2004 Annual Report I hat

Notes to Financial Statements (continued)

(DOLLARS IN $000s)

Unclassified assets are in service but not yet classified to specific plant accounts.

Nuclear fuel represents costs associated with acquiring and processing reload fuel assemblies as well as the cost of nuclear fuel in the reactor. Nuclear fuel is amortized based on bum rates using a unit of production basis. The Agency regularly writes off fully amortized nuclear fuel costs when fuel batches are replaced during core refueling operations. Fully amortized fuel costs of $10,316 and $5,680 were written off during 2004 and 2003, respectively.

A summary of accumulated depreciation and amortization at December 31, 2004 and 2003 are as follows:

2004 2003 Accumulated depreciation of electric plant in service $ 313,178 $ 307,412 Accumulated amortization of nuclear fuel 163940 20,961

$ 330,118 $ 328,373 The depreciation charge for 2004 on the Agency's generation plant has been determined based on revised estimated useful lives for these assets. The estimated useful lives were revised to recognize a 19-year extension of the operating license for Catawba Unit 1 and a 17-year extension of the operating license for Catawba Unit 2 through 2043 which Duke received in December 2003. The effect of the change in 2004 was to decrease depreciation expense by approximately $11,800 with a corresponding decrease in depreciation expense deferred to be recovered in future participant billings.

6. RESTRICTED ASSETS The General Bond Resolution and Project agreements restrict the use of bond proceeds, Agency revenues, and Agency funds on hand.

Certain restrictions define the order in which available funds may be used to pay costs; other restrictions require minimum balances or accumulation of balances for specific purposes. At December 31, 2004 and 2003, management believes the Agency was in compli-ance with all such restrictions and held the following restricted assets:

2004 2003 Fair value Amortized cost Fair value Amortized cost Debt service - bond principal $ 24,400 $ 24,400 $ 20,860 $ 20,860 Debt service - bond fixed rate interest 18,568 18,568 27,317 27,317 Debt service reserve 73,394 73,249 80,044 78,974 Reserve and contingency 7,332 7,325 8,005 7,897 Decommissioning 49,628 49,257 47,670 46,539 Special reserve 14,924 15,000 15,087 15,000

$ 188,246 $ 187,799 $ 198,983 $ 196,587 Funds are comprised of:

Marketable debt securities $ 186,153 $ 185,706 $ 197,638 $ 195,242 Accrued interest receivable 2,093 2,093 1,345 1,345

$ 188,246 $ 187,799 $ 198,983 $ 196,587

7. CURRENT UNRESTRICTED ASSETS AND CURRENT LIABILITIES Current unrestricted assets and current liabilities are used in the Agency's day-to-day operations. The assets are allocated for the following purposes:

2004 2003 Fair value Amortized cost Fair value Amortized cost Working capital $ 88,949 $ 88,908 $ 94,495 $ 93,360 Derivative financial instruments asset (liability) (7,514) 2,938 Fuel acquisition 27,249 27,249 28,561 28,561 Bond retirement fund 186 186 1,869 1,874 Rate stabilization 72,185 70,898 118,303 113,680

$ 181,055 $ 187,241 $ 246,166 $ 237,475 Current unrestricted assets include $11,293 and $12,353 of uninsured and uncollateralized cash at December 31, 2004 and 2003, respectively. Accounts payable and accrued liabilities of $10,707 and $8,688 at December 31, 2004 and 2003, respectively, will be paid from working capital assets.

2004 Annual Report 35

Notes to Financial Statements (continued)

(DOLLARS IN SC00s)

8. NET EXPENSES RECOVERABLE FROM FUTURE PARTICIPANT BILLINGS As described in notes 1 and 2, rates charged to Participants are structured to systematically provide for debt requirements and operat-ing costs of the Agency. The expenses and revenues excluded from rates are deferred to such periods as they are intended to be included in rates.

Net expenses recoverable from future Participant billings:

2004 2003 Change Items to be recovered in future Participant billings: (Cumulativ totals)

Interest expense $ 339,936 $ 336,172 $ 3,764 Depreciation expense 323,186 317,585 5,601 Amortization of redemption and defeasance losses 172,961 161,246 11,715 Amortization of bond discounts and premiums and debt issuance costs 73,755 70,586 3,169 Nuclear fuel expenses 873 873 Letter of credit fees 5,649 5,649 Other 2,392 2,392 -

918,752 894,503 24,249 Items reducing future Participant billings:

Investment income (76,528) (76,528) -

Decrease (increase) in fair value of investments and derivative instruments 5,739 (11,087) 16,826 Rate stabilization (revenue received to reduce future billings to Participants) (533,913) (528,593) (5,320)

Reserve and contingency deposits (50,076) (44,275) (5,801)

(654,778) (660,483) 5,705 Revenues (expenses) recognized:

Interest, depreciation, amortization expense included in Participant billings for debt principal payments (210,153) (171,869) (38,284)

Rate stabilization draws applied to expenses 463,015 414,913 48,102 Reserve and contingency revenue applied to expenses 8,302 7,529 773 Net costs recoverable from future Participant billings $ 525,138 $ 484,593 $ 40,545 The following expenses will be recognized in future periods when rates charged to Participants produce revenues sufficient to retire the debt that funded those costs:

• Interest expense on the Agency's bonds and variable rate demand obligations along with associated letter-of-credit, banking and re-marketing fees (except interest and fees related to Capital Appreciation Bonds) paid from bond proceeds during a defined "Construction Period," (net of income earned on the temporary investment of those bond proceeds);

• Interest expense on Capital Appreciation Bonds accrued but not paid until maturity;

• Amortization of debt issuance expenses, bond discounts and premiums, defeasance losses, redemption losses, and organization costs paid from or included in bond proceeds;

• Depreciation on utility plant constructed with bond proceeds and amortization of nuclear fuel acquired with bond proceeds; and

• Certain other project costs paid from bond proceeds.

The Agency has also deferred Participant revenues that, during the Construction Period, were established at levels to cover Project costs not paid from bond proceeds, as well as scheduled deposits to a Rate Stabilization account. The revenue associated with those scheduled deposits and the interest income thereon will be recognized when those funds are drawn upon to pay Project costs. Also, certain settlement revenues and excess revenues in certain funds have been transferred to the Rate Stabilization account and have been deferred for recognition until the time the funds are applied to the payment of Project costs.

Revenues or costs associated with increases or decreases in the fair value of investments have been deferred until such time the securities have matured or are sold.

Additionally, the Agency's General Bond Resolution requires Participant revenues to be established at levels sufficient to provide specified deposits into a Reserve and Contingency fund. Monies in that fund are used for the construction or acquisition of utility plant. The recognition of such revenues is deferred until such time as the depreciation is recorded on the assets constructed or acquired with those monies.

36 2004 Annual Report

Notes to Financial Statements (continued)

(DOLLARS IN $000s)

9. LONG-TERM LIABILITIES Long term liabilities at December 31, 2004 and 2003 consist of the following:

Due within 2003 Additions Reductions 2004 one year 1986 Refunding Series Electric Revenue Bonds, payable in 2025 with interest at 5% $ 33,620 - $ (11,745) $ 21,875 1986A Refunding Series Electric Revenue Bonds, refunded in 2004 103,815 - (103,815) -

1988 Capital Appreciation Electric Revenue Bonds, payable annually and from 2010 to 2013 with interest at 7.75% 7,745 _ (2,934) 4,811 1988A Capital Appreciation Electric Revenue Bonds, payable annually from 2006 to 2015 with interest ranging from 7.5% to 7.65% 4,284 _ (1,034) 3,250 1991 Refunding Series Electric Revenue Bonds, payable annually from 2019 to 2023 with interest ranging from 4%to 6.75% 133,110 - (21,620) 111,490 1991 A Refunding Series Electric Revenue Bonds, payable in2007 and from 2013 to 2018 with interest ranging from 5%to 6.5% 100,175 _ (39,940) 60,235 1992 Refunding Series Electric Revenue Bonds, refunded in2004 19,940 _ (19,940) 1993 Refunding Series Electric Revenue Bonds, payable annually from 2007 to 2025 with interest ranging from 5.375% to 5.6% 72,175 (8,700) 63,475 1996A Refunding Series Electric Revenue Bonds, refunded in2004 67,645 - (67,645) 1996B Refunding Series Electric Revenue Bonds, payable annually from 2007 to 2013 with interest ranging from 5.25% to 6.0% 113,185 _ (15,305) 97,880 1996C Refunding Series Electric Revenue Bonds, refunded in2004 50,000 - (50,000) 1996D Refunding Series Electric Revenue Bonds, payable in2025 with variable interest rates (1.21 % and 1.01 % at December 31, 2004 and 2003, respectively) 50,000 _ (39,000) 11,000 1997A Refunding Series Electric Revenue Bonds, payable in2024 with variable interest rates (1.17% and 1.0% at December 31, 2004 and 2003, respectively) 31,700 - 31,700 1997B Refunding Series Electric Revenue Bonds, payable in2016 to 2019 with variable interest rates (1.17% and 1.0% at December 31, 2004 and 2003, respectively) 63,000 - 63,000 2004 Annual Report 37

Notes to Financial Statements (continued)

(DOLLARS IN $000s)

Due within 2003 Additions Reductions 2004 one year 1997C Refunding Series Electric Revenue Bonds, payable annually from 2016 to 2019 with variable interest rates (1.21 % and 1.01% at December 31, 2004 and 2003, respectively) 34,100 - 34,100 1998A Refunding Series Electric Revenue Bonds, payable annually from 2006 to 2025 with interest ranging from 4.4% to 5.5% 161,380 - 161,380 1999A Refunding Series Electric Revenue Bonds, payable annually from 2014 to 2016 and 2020 to 2021 with interest at 5.25% 97,510 _ 97,510 2002A Refunding Series Electric Revenue Bonds, payable annually from 2007 to 2008 and 2010 with interest ranging from 3.9% to 4.5% 47,660 - (36,225) 11,435 2002B Refunding Series Electric Revenue Bonds, refunded in 2004 50,000 - (50,000) 2004A Refunding Series Electric Revenue Bonds, Payable annually from 2005 to 2006 and 2010 to 2014 with interest ranging from 2.65% to 5.20% - 103,300 - 103,300 24,400 2004B Refunding Series Electric Revenue Bonds, payable anually from 2031 to 2032 and 2034 with variable interest rates (1.46°% at December 31, 2004) - 240,400 - 240,400 2004A Capital Appreciation Electric Revenue Bonds, payable annually from 2022 to 2024, 2026 to 2032 and 2034 102,670 102,670 Total bonds payable 1,241,044 446,370 (467,903) 1,219,511 24,400 Less unamortized discount (40,620) (62) 15,206 (25,476)

Plus unamortized premium 801 (236) 565 Bonds payable, net $ 1,201,225 $ 446,308 $ (452,933) $ 1,194,600 $ 24,400 Due within 2002 Additions Reductions 2003 one year 1986 Refunding Series Electric Revenue Bonds, payable in 2025 with interest at 5% $ 33,620 - - $ 33,620 1986A Refunding Series Electric Revenue Bonds, payable in 2023 and 2024 with interest at 5.75% 103,815 - 103,815 1988 Capital Appreciation Electric Revenue Bonds, payable annually and from 2010 to 2013 with interest at 7.75% 7,745 7,745 1988A Capital Appreciation Electric Revenue Bonds, payable annually from 2004 to 2015 with interest ranging from 7.3% to 7.65% 4,284 4,284 540 1991 Refunding Series Electric Revenue Bonds, payable annually from 2005 to 2023 with interest ranging from 4% to 6.85% 133,110 - 133,110 1991 A Refunding Series Electric Revenue Bonds, payable annually from 2002 to 2007 and from 2013 to 2018 with interest ranging from 5%to 6.5% 112,385 _ (12,210) 100,175 1992 Refunding Series Electric Revenue Bonds, payable annually from 2010 to 2014 with interest at 6.3% 19,940 _ 19,940 1993 Refunding Series Electric Revenue Bonds, payable annually from 2002 to 2025 with interest ranging from 4.9% to 5.6% 74,840 - (2,665) 72,175 515 1996A Refunding Series Electric Revenue Bonds, payable annually from 2013 to 2021 with interest ranging from 6.55% to 6.6% 69,140 _ (1,495) 67,645 1 38 2004 Annual Report Rhea

Notes to Financial Statements (continued)

(DOLLARS IN $000s)

Due within 2002 Additions Reductions 2003 one year 1996B Refunding Series Electric Revenue Bonds, payable annually from 2002 to 2013 with interest ranging from 4.8% to 6.0% 117,580 - (4,395 ) 113,185 3,375 1996C Refunding Series Electric Revenue Bonds, payable annually in 2021 to 2022 with variable interest rates (0.98% and 1.55%

at December 31, 2003 and 2002, respectively) 50,000 - 50,000 1996D Refunding Series Electric Revenue Bonds, payable annually from 2022 to 2025 with variable interest rates (1.01% and 1.5% at December 31, 2003 and 2002, respectively) 50,000 - 50,000 1997A Refunding Series Electric Revenue Bonds, payable in 2024 with variable interest rates (1.0% and 1.6% at December 31, 2003 and 2002, respectively) 31,700 - 31,700 1997B Refunding Series Electric Revenue Bonds, payable annually from 2002 to 2003 and 2016 to 2019 with variable interest rates (1.0% and 1.55% at December 31, 2003 and 2002, respectively) 63,770 (770) 63,000 1997C Refunding Series Electric Revenue Bonds, payable annually from 2002 to 2003 and 2016 to 2019 with variable interest rates (1.01 % and 1.6% at December 31, 2003 and 2002, respectively) 34,530 (430) 34,100 1998A Refunding Series Electric Revenue Bonds, payable annually from 2006 to 2025 with interest ranging from 4.4% to 5.5% 161,380 - 161,380 1999A Refunding Series Electric Revenue Bonds, payable annually from 2014 to 2016 and 2020 to 2021 with interest at 5.25% 97,510 - 97,510 2002A Refunding Series Electric Revenue Bonds, payable annually from 2004 to 2010 with interest ranging from 3.5% to 5.0% 47,660 - 47,660 16,430 2002B Refunding Series Electric Revenue Bonds, payable annually 2010 to 2018 with variable interest rates (0.98% and 1.6% as of December 31, 2003 and 2002, respectively) 50,000 50,000 Total bonds payable 1,263,009 - (21,965) 1,241,044 20,860 Less unamortized discount (43,099) - 2,479 (40,620)

Plus unamortized premium 1,418 _ (617) 801 Bonds payable, net $ 1,221,328 - $ (20,103) $ 1,201,225 $ 20,860 The bonds are special obligations of the Agency and are secured by future revenue and pledged monies and securities as provided by the bond resolution.

The bonds generally provide for early redemption beginning ten years after issuance at prices ranging from 100% to 103% of the bond principal amounts.

The Agency has advance refunded certain bond issues as described in note 10. The Agency is in compliance with its covenants under the bond indenture.

2004 Annual Report 39

Notes to Financial Statements (continued)

Notes to Financial Statements (continued)

(DOLLARS IN $000s)

The following is a summary of total debt service deposit requirements for bonds outstanding at December 31, 2004:

Year Principal Interest Total 2005 $ 27,943 $ 53,861 $ 81,804 2006 29,607 52,905 82,512 2007 31,208 51,306 82,514 2008 32,746 49,767 82,513 2009 34,387 48,086 82,473 2010 30,180 52,267 82,447 2011 28,673 53,836 82,509 2012 28,745 53,753 82,498 2013 40,207 42,211 82,418 2014 52,590 40,030 92,620 2015 48,820 35,785 84,605 2016 48,440 33,333 81,773 2017 50,710 31,064 81,774 2018 53,070 28,704 81,774 2019 55,790 25,981 81,771 2020 58,865 22,909 81,774 2021 50,659 31,113 81,772 2022 50,345 31,426 81,771 2023 53,766 28,008 81,774 2024 68,230 13,545 81,775 2025 23,229 58,54:3 81,772 2026 33,012 48,759 81,771 2027 33,198 48,577 81,775 2028 33,532 48,241 81,773 2029 33,912 47,860 81,772 2030 34,415 47,360 81,775 2031 38,758 43,016 81,774 2032 67,500 11,123 78,623 2033 22,574 4,397 26,971

$ 1,195,111 $1,137,766 2,332,877 The debt service deposit requirements for principal differ from total long-term debt outstanding at December 31, 2004, because the principal payment of $24,400, which is due January 1, 2005 was deposited during 2004. All principal payments are due on January 1 of the year subsequent to the deposit requirement.

10. IN-SUBSTANCE DEBT DEFEASANCE In prior years, the Agency defeased in-substance certain Electric Revenue Bonds by placing the proceeds of new bonds in an irrevoca-ble trust fund to provide for future debt service payments on the old debt. Accordingly, the trust account asset and the liability for the defeased bonds are not included in the accompanying financial statements. On December 31, 2004, $221,690 of the bonds are considered defeased in-substance.

11. RESERVE FOR DECOMMISSIONING The Agency has an obligation for decommissioning the Catawba Nuclear Station after the expiration of its operating licenses. The Agency is in compliance with Nuclear Regulatory Commission requirements for funding future decommissioning costs. Since 1985, the Agency has been making regular deposits to segregated decommissioning accounts. Deposits pertaining to contaminated portions of the Project are held by a trustee. The Agency has custody of funds set aside to decommission noncontaminated portions of the project. As of December 31, 2004 and 2003, the fair values of the Agency's assets that are legally restricted for purposes of settling the decommissioning obligation are $49,628 and $47,670, respectively.

During 2003, Duke received a 19-year extension of the operating license for Catawba Unit 1 and a 17-year extension of the operating license for Catawba Unit 2 through 2043. In connection with the license extensions, the Agency received an updated decommission-ing study. The study estimates total decommissioning costs of $999,313 in 2003 dollars and presumes the Catawba Nuclear Station 40 2004 Annual Report I H'

Notes to Financial Statements (continued)

(DOLLARS IN $OOMs) will be decommissioned as soon as possible following the expiration of its operating licenses in 2043. The Agency used the estimates from this study to determine its decommissioning liability to be recorded in accordance with SFAS No. 143.

The Agency used the following assumptions in determining its reserve for decommissioning:

Period inwhich decommissioning liability was incurred 1985 Agency's share of decommissioning costs per study (in2003 dollars) $ 124,914 Estimated inflation 3%

Credit adjusted risk-free interest rate 5%

Estimated life of corresponding asset 59 years On January 1, 2003, the Agency recorded an obligation and corresponding asset of $22,900 as of 1985, the date the liability was incurred. Concurrently, the Agency recorded accretion of the obligation and depreciation expense of $32,211 and $6,793, respective-ly, for the period from the date the Agency incurred the liability through January 1, 2003, and removed its existing reserve for decommissioning of $43,072 as of January 1, 2003. This resulted in a net cumulative-effect-type adjustment of $4,068 in the state-ment of revenues, expenses, and changes in net assets.

Following is a rollforward of the reserve for decommissioning for the year ended December 31, 2004 and 2003:

2004 2003 Reserve for decommissioning at January 1 $ 57,867 $ 55,111 Accretion expense (decommissioning) 2,894 2,756 Reserve for decommissioning at December 31 $ 60,761 $ 57,867 Depreciation expense on the corresponding asset was $388 for both the years ended December 31, 2004 and 2003, and is included in depreciation expense in the accompanying statements of revenues, expenses, and changes in net assets.

12. EMPLOYEE BENEFIT PLANS The Agency maintains a defined contribution money purchase plan in compliance with Section 401(a) of the Internal Revenue Code.

On behalf of all full-time employees, the Agency contributes 10% of base salary into the money purchase plan. Agency contributions totaled $91 and $82 in 2004 and 2003, respectively. Employee contributions may also be made to the Plan, providing combined employer and employee annual contributions do not exceed 25% of eligible employee compensation, or $30, whichever is less.

The Agency also maintains a deferred compensation plan under Section 457 of the Internal Revenue Code. From time to time, on behalf of selected employees, the Agency contributes to the deferred compensation plan. Employee contributions may also be made to the deferred compensation plan providing combined employer and employee annual contributions do not exceed certain limita-tions.

Assets of the money purchase and deferred compensation plans are held by Prudential Financial, administrator and trustee for the Agency, for the exclusive benefit of the employees.

13. DISCLOSURES REGARDING FAIRVALUE OF FINANCIAL INSTRUMENTS Statement of Financial Accounting Standards No. 107 (SFAS No. 107), DisclosureAbout Fair Value ofFinancialInstnuments, requires dis-closure of fair value information about financial instruments whether or not recognized in the balance sheet, for which it is practica-ble to estimate fair value. Fair value estimates are made as of a specific point in time based on the characteristics of the financial instruments and the relevant market information. Where available, quoted market prices are used. In other cases, fair values are based on estimates using present value or other valuation techniques. These techniques involve uncertainties and are significantly affected by the assumptions used and the judgments made regarding risk characteristics of various financial instruments, discount rates, pre-payments, estimates of future cash flows, future expected loss experience and other factors. Changes in assumptions could signifi-cantly affect these estimates. Derived fair value estimates cannot be substantiated by comparison to independent markets and, in many cases, may or may not be realized in an immediate sale of the instrument.

2004 Annual Report 41

Notes to Financial Statements (continued)

(DOLLARS IN $ooos)

Under SPAS No. 107, fair value estimates are based on existing financial instruments without attempting to estimate the value of anticipated future business and the value of the assets and liabilities that are not financial instruments. Accordingly, the aggregate fair value amounts presented do not represent the underlying value of the Agency.

The following describes the methods and assumptions used by the Agency in determining carrying value and estimated fair value of financial instruments:

A. Cash Carrying value equals estimated fair value.

B. Marketable Debt Securities Estimated fair value, which is the carrying value, of all marketable debt securities is derived from quoted market prices.

C. Derivative Financial Instruments Estimated fair value of derivative financial instruments is derived from current market pricing models.

D. Participant Accounts Receivable, and Other Accounts Receivable Carrying amount approximates fair value due to the short-term nature of these instruments.

E. Long-term Debt Carrying value of long-term debt coupon securities includes par, less unaccreted discounts, plus unamortized premiums, plus accrued interest payable. Carrying value also includes Capital Appreciation Term Bonds valued at original price plus accrued interest payable.

Estimated fair value of all long-term debt securities is derived from quoted market prices and includes accrued interest.

The estimated fair values of the Agency's long-term debt with carrying values are different from their estimated fair values at December 31, 2004 and 2003 as follows:

ESTIMATED FAIR VALUE 2004 2003 Carrying Estimated fair Carrying Estimated fair amount value amount value 1986 Electric Revenue Refunding Bonds $ 18,505 $ 21,875 $ 28,138 $ 30,729 1986A Electric Revenue Refunding Bonds - - 96,616 106,881 1988 Electric Revenue Refunding Bonds 17,245 23,389 25,695 53,260 1988A Electric Revenue Refunding Bonds 10,815 13,063 13,115 24,667 1991 Electric Revenue Refunding Bonds 104,045 123,074 125,746 151,482 1991A Electric Revenue Refunding Bonds 59,628 67,413 99,896 114,553 1992 Electric Revenue Refunding Bonds - - 20,468 20,821 1993 Electric Revenue Refunding Bonds 64,123 71,602 72,947 82,339 1996A Electric Revenue Refunding Bonds - - 69,685 70,058 1996B Electric Revenue Refunding Bonds 99,644 104,393 115,271 127,057 1996C/D Electric Revenue Refunding Bonds 11,015 11,000 100,086 100,086 1997A Electric Revenue Refunding Bonds 31,745 31,700 31,727 31,727 1997B/C Electric Revenue Refunding Bonds 97,252 97,100 97,200 97,200 1998A Electric Revenue Refunding Bonds 161,293 167,425 161,066 171,335 1999A Electric Revenue Refunding Bonds 97,950 99,648 97,787 100,078 2002A Electric Revenue Refunding Bonds 11,680 11,435 48,735 49,449 2002B Electric Revenue Refunding Bonds - - 50,105 50,049 2004A-1 Electric Revenue Refunding Bonds 104,848 93,087 - -

2004A-2 Electric Revenue Refunding Bonds 104,918 114,674 - -

2004B Electric Revenue Refunding Bonds 240,735 240,400 - -

$ 1.235,441 $ 1,291,278 $ 1,254,283 $ 1,381,771

14. NUCLEAR INSURANCE Nuclear Insurance. Duke Energy owns and operates the McGuire and Oconee Nuclear Stations with two and three nuclear reactors, respectively, and operates and has a partial ownership interest in the Catawba Nuclear Station with two nuclear reactors. Nuclear insurance coverage is maintained in three program areas: liability coverage; property, decontamination and decommissioning cover-age; and business interruption and/or extra expense coverage. Certain expenses associated with nuclear insurance premiums paid by Duke Energy are reimbursed by the other joint owners of the Catawba Nuclear Station.

Pursuant to the Price-Anderson Act, Duke Energy is required to insure against public liability claims resulting from nuclear incidents to the full limit of liability of approximately $10.8 billion.

Primary LiabilityInsurance. Duke Energy has purchased the maximum available private primary liability insurance as required by law.

As of January 1,2003, $300 million in private primary liability insurance became available and Duke Energy purchased that amount along with a like amount to cover certain worker tort claims.

42 2004 Annual Report

Notes to Financial Statements (continued)

(DOLLARS IN $000s)

Excess Liability Insurance. This policy currently provides approximately $10.5 billion of coverage through the Price-Anderson Act's mandatory industry-wide secondary insurance program of risk pooling. The $10.5 billion of coverage is the sum of the current poten-tial cumulative retrospective premium assessments of $101 million per licensed commercial nuclear reactor. This $10.5 billion would be increased by $101 million as each additional commercial nuclear reactor is licensed, or reduced by $101 million for nuclear reac-tors that are no longer operational and may be exempted from the risk pooling insurance program. Under this program, licensees could be assessed retrospective premiums to compensate for damages in the event of a nuclear incident at any licensed facility in the nation.

If such an incident should occur and public liability damages exceed primary insurance, licensees may be assessed up to $ 101 million for each of their licensed reactors, payable at a rate not to exceed $10 million a year per licensed reactor for each incident. The $101 million amount is subject to indexing for inflation and may be subject to state premium taxes. If retrospective premiums were to be assessed, the Agency and each other joint owner of Catawba would be obligated to assume its pro rata share of such assessment.

Duke Energy is a member of Nuclear Electric Insurance Limited (NEIL), which provides property and business interruption insurance coverage for Duke Energy's nuclear facilities under the following three policy programs:

Primary Property Insurance. This policy provides $500 million of primary property damage coverage for each of Duke Energy's nuclear facilities.

Excess Property Insurance. This policy provides excess property, decontamination, and decommissioning liability insurance in the fol-lowing amounts: $2.25 billion for the Catawba Nuclear Station and $2.0 billion each for the Oconee and McGuire Nuclear Stations.

Business Interruption Insurance. This policy provides business interruption and/or extra expense coverage resulting from an accidental outage of a nuclear unit. Each unit of the McGuire and Catawba Nuclear Stations is insured for up to $3.5 million per week and the Oconee Nuclear Station units are insured for up to $2.8 million per week. Coverage amounts per unit decline if more than one unit is involved in an accidental outage. Initial coverage begins after a 12-week deductible period and continues at 100% for 52 weeks and 80% for the next 110 weeks.

If NEIL's losses ever exceed its reserves for any of the above three programs, Duke Energy will be liable for assessments of up to ten times its annual premiums. The current potential maximum assessments are as follows: Primary Property Insurance - $35 million; Excess Property Insurance - $44 million; Business Interruption Insurance - $29 million.

The other joint owners of the Catawba Nuclear Station are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the Price-Anderson Act's excess secondary insurance program of risk pool-ing or the NEIL policies.

15. DERIVATIVE FINANCIAL INSTRUMENTS The Agency has only limited involvement with derivative financial instruments.

The Agency is party to four interest rate swap agreements. Two of the interest rate swap agreements were originally scheduled to ter-minate in January 2024. The Agency's objective for entering into these interest rate swap agreements was to maximize income. Under these fixed to variable interest rate swaps, PMPA received a fixed rate of 5.93% through December 31, 2004, while paying a variable rate based on the BMA Municipal Swap Index. The notional amount of each of these agreements was $51,908. In January 2003, the Agency amended the agreements to lock in at 2.09% the variable interest rate paid by the Agency until December 31, 2004. The agreements were cancelled on January 1, 2005.

The Agency is party to a third interest rate swap agreement with a termination date of January 1, 2021. This swap is designed to miti-gate interest rate risk of outstanding variable rate debt during rising interest rate periods and augment expected income during falling interest rate periods. PMPA receives a floating LIBOR rate and pays a floating variable rate based on the BMA Municipal Swap Index.

The notional amount of this agreement is $100,000. The Agency posted marketable debt securities with par value of $2,300 as collat-eral on this swap at December 31, 2004.

The Agency is also party to a fourth interest rate swap agreement with a termination date of January 1, 2034. The objective of this swap is to achieve a lower fixed rate of interest on PMPA's debt. Under this floating to fixed transaction, PMPA receives a variable interest rate based on the BMA Municipal Swap Index on a notional amount of $60 million and pays a low rate of 3% for the first twenty years and a higher rate of 16% for the last ten years of the swap life. The average rate that PMPA will pay over the life of the swap will be 4.84%. The swap is designed to push debt service out in later years to produce overall level debt service.

The fair value of the four interest rate swap agreements was approximately $8,286 (liability) and $1,009 (asset) at December 31, 2004 and 2003, respectively. Current market pricing models were used to estimate fair value of interest rate swap agreements. The fluctua-tion in the fair value of the interest rate swaps was a decrease of $9,295 and $1,459 in 2004 and 2003, respectively, and is included in net decrease in fair value of investments and derivative instruments in the statements of revenues, expenses, and changes in net assets. Total net income from the interest rate swaps was $3,539 and $3,951 in 2004 and 2003, respectively, and is included in other expense, net, in the statements of revenues, expenses, and changes in net assets.

2004 Annual Report 43

In October 2000, the Agency entered into a forward delivery agreement with a term of five years. The Agency's objective for entering into this forward delivery agreement is to maximize investment income. The agreement entitles the Agency to receive interest at a fixed rate of 6.4825% on scheduled monthly deposits into certain debt service principal and interest accounts. The fair value of the forward delivery agreement was approximately $772 and $1,929 at December 31, 2004 and 2003, respectively. The fluctuation in the fair value of the forward delivery contract was a decrease of $1,157 and $741 in 2004 and 2003, respectively, and is included in net decrease in fair value of investments and derivative instruments in the statements of revenues, expenses, and changes in net assets.

Total income from the forward delivery agreement was $1,158 and $1,165 in 2004 and 2003, respectively, and is included in interest income in the statements of revenues, expenses, and changes in net assets.

By using derivative instruments the Agency exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of the derivative contract is positive, the counterparty owes the Agency, which creates repayment risk for the Agency. When the fair value of a derivative contract is negative, the Agency owes the counterparty and, therefore, does not possess repayment risk. The Agency minimizes the credit or repayment risk in derivative instru-ments by entering into transactions with high-quality counterparties.

Market risk is the adverse effect on the value of financial instruments that results from a change in interest rates. The market risk asso-ciated with interest rate contracts is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken.

44 2004 Annual Report

u, .- - 7!

F

Schedule of Revenue and Expenses Schedule 1 PERTHE BOND RESOLUTION AND OTHER AGREEMENTS

• YEAR ENDED DECEMBER 31, 2004 * (DOLLARS IN $0005)

Actual revenues Budgeted revenues Actual over and expenses and expenses (under) budget Revenue:

Sales of electricity to Participants $ 127,393 $ 130,690 $ (3,297)

Sales of electricity to Duke 9,102 8,743 359 Sales of electricity to others 8,693 6,166 2,527 Interest income 14,582 15,829 (1,247)

Other 1,076 1,078 (2)

Total revenue $ 160,846 $ 162,506 $ (1,660)

Expenses:

Catawba operating expenses:

Operation and maintenance $ 23,158 $ 23,000 $ 158 Nuclear fuel 6,294 7,000 (706)

Purchased power - Duke 8,663 8,434 229 Payments in lieu of taxes 4,400 3,988 412 Interconnection services:

Purchased power:

Duke 14,822 10,886 3,936 Participants 8,601 8,327 274 Other 244 288 (44)

Transmission services 4,652 5,144 (492)

Distribution services 1,196 1,274 (78)

Administrative and general:

Agency 4,069 4,227 (158)

Duke 10,579 11,178 (599)

Other 282 892 (610)

Special funds deposits (withdrawals):

Bond fund:

Deposits from revenues 88,999 88,353 646 Liquidity facility fees 992 819 173 Reserve and Contingency fund:

Deposits from revenue 9,629 8,772 857 Capital additions (5,801 ) (4,986) (815)

Transfer excess funds (3,828) (3,786) (42)

Decommissioning fund:

Deposits from revenue 861 1,725 (864)

Interest income (1) 1,857 2,190 (333)

Revenue fund:

Working capital (6,471 ) (1,126) (5,345)

Fuel (7,606) (6,473) (1,133)

Rate stabilization:

Interest income (1) 5,320 5,234 86 Deposits (draws) (25,021 ) (25,021)

Supplemental power reserve:

Interest income (1) 365 300 65 Transfer excess funds (365 ) (300) (65)

Other capital transactions:

Bond proceeds (446,307) - (446,307)

Bond payments 455,836 - 455,836 Debt issuance 37,302 - 37,302 Excess funds (46,168) - (46,168)

Plant additions:

Reserve and contingency fund 5,801 4,986 815 General plant 47 101 (54)

Transmission plant 838 383 455 Distribution plant - 224 (224)

Fuel acquisitions 7,606 6,473 1,133 Total expenses $ 160.846 $ 162.506 $ (1.660)

(1) Included in 'Revenue: Interest Income.'

See accompanying independent auditors' report.

46 2004 Annual Report

Schedule of Revenue and Expenses Schedule 2 PER THE BOND RESOLUTION AND OTHER AGREEMENTS

• YEAR ENDED DECEMBER 31, 2004 * (DOLLARS IN $000s)

Funds Revenue Operann Bond Principal Reserve Workinz Rate Fuel interest and Dc

i. Supplemental capita stabilization account retire Reserve contingency Decommissiion power Balances at beginning of year:

Assets $ 93,360 $ 113,680 $ 28,561 $ 50,051 $ 78,974 $ 7,897 $46,539 $ 15,000 Liabilities (8,688)

Net 84,672 Project revenues:

Participants - electric (1) 127,393 Participants - facilities rent (1) 1,043 Participants - other (1) 34 Duke Power - electric (1) 9,102 Other - surplus electric (1) 8,693 Interest income (1) 7,040 5,320 1,857 365 Project costs (see note):

Operations and maintenance (2) (23,158)

Fuel (3) (6,294) 6,294 Purchased power - Duke (2) (8,663)

Decommissioning (3) (861) 861 General and administration (2) (13,095)

Payments in lieu of taxes (2) (4,371)

Other (2) (282)

Debt service (3) (87,782) 87,782 Liquidity facility fee (3) (992) 992 Bond retirement (3) (1,217) 1,217 Reserve and contingency (3) (9,629) 9,629 Supplemental power costs:

Purchased power - Duke (2) (14,822)

Purchased power - Participant (2) (8,601)

Purchased power - Other (2) (244)

Transmission services (2) (4,652)

Distribution services (2) (1,196)

General and administration (2) (1,554)

Payments in lieu of taxes (2) (29)

Other fund changes:

Transfers in (out):

Rate stabilization (3) 25,021 (25,021)

Excess funds (3) 4,193 (3,828) (365)

Reimbursement (3) 5,801 (5,801)

Payments:

Debt retire/interest (2) (80,098)

Capital additions (2) (6,686) (7,606)

Debt refunding:

New issue proceeds 446,307 Excess funds 46,168 (23,081) (16,790) (5,725) (572)

Old issue proceeds (455,836)

Cost of issue (37,302)

Balances at December 31, 2004 $ 78,201 $ 70,898 $ 27,249 $ 43,154 $ 73,249 $ 7,325 $49,257 $ 15,000 Assets 88,908 Liabilities $ (10,707)

(1) Deposited in appropriate fund (2) Paid to third parties from Revenue Fund (Working Capital) to the Operating Fund and actual disbursements are made from the Operating Fund.

(3)Transfers between funds See accompanying independent auditors' report.

2004 Annual Report 47

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PIEDMONT MUNIGHPAL POW ER AGENCY