ML13249A166
| ML13249A166 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 12/31/2012 |
| From: | Salt River Project |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML13249A163 | List: |
| References | |
| 102-06760-TNW/RKR/KAR | |
| Download: ML13249A166 (69) | |
Text
Enclosure PALO VERDE NUCLEAR GENERATING STATION 2012 ANNUAL FINANCIAL REPORTS Salt River Project Southern California Public Power Authority Los Angeles Department of Water and Power
4 I
CONTENTS Letter to Electri Customers, Water Shareholders and Bondholders ............. 2 Letter from General Manager 4 4....
Power Supply.......... 6 Water Stewardship 8 Sustainability 10 Customer Experience 12 Community Commitment . ... 4.
Management's Financial and Operational Summary .... 16 CombinedF .............. ... 20 Notes to Combined Financial Statements ........... 2 ReportoIndependentAud A s - ....... 61 SRP Boards and Coun~cils- ....62 Corporate Information .... 64
Serving customers and managing resources -
these two fundamentals define SRP's past, present and future, and reflect our mission of improving the quality of life in the Valley and throughout Arizona.
LETTER TO ELECTRIC CUSTOMERS, WATER SHAREHOLDERS AND BONDHOLDERS David Rousseau John R. Hoopes President Vice President We are pleased to report that this past year has been one of significant change, and significant progress, for SRP.
In addition to achieving positive financial performance, we, working with the SRP Board, oversaw a major management transition during the fiscal year. While this was a challenging time to chart a new course, given continued uncertainty resulting from a weak economy, financial market volatility and complex environmental issues, it also was a time of opportunity - and SRP emerged in a strong position.
The management change was much more than an announcement of a new executive team. Since being named General Manager and Chief Executive Officer in April 2011, Mark Bonsall has spent significant effort realigning the organization to increase its focus on serving SRP customers and managing the resources to accomplish this mission.
Mark is a 35-plus-year veteran of SRP, having served as Treasurer and as Chief Financial Executive. He brings a wealth of experience, including being an engineer and a graduate of the Wharton Business School.
Together with SRP's elected Board and Council, we have worked closely with the new management team and are pleased by its vision, competence and professionalism. In pursuing a vision for the future, we also commend the team for executing an aggressive new sustainability target and thank our Board and Council members for their support of this important goal.
By 2020, SRP plans to meet 20% of its expected retail energy requirements with sustainable resources, such as wind, solar, geothermal and biomass energy; hydropower; conservation; and energy-efficiency measures.
This is an achievable target, one we are on pace to meet or exceed.
Financially, a strong effort to control costs was one factor helping to deliver positive results in a slow-growth environment this year. SRP's net revenues, before fair-value accounting adjustments, for the fiscal year ended April 30, 2012, totaled $163 million, compared with $202.4 million for the previous year. Operating revenues were $2.8 billion for FY12, which was the same total as FY11.
While financial results may change year to year based on a number of factors, one thing does not: SRP's culture of commitment to customers and the community. Reflecting that culture, residential and commercial customers again recognized SRP for our service, rating us "Best in the West" in annual studies conducted by J.D. Power and Associates.
J.D. Power also recognized SRP with something new this year, its prestigious "Service Excellence Award." The honor compared SRP brand strength with 800 companies in different sectors of the economy, not just utilities.
SRP's recognition in this arena is unprecedented for a utility.
This sense of service is one that originated with the visionary pioneers who founded SRP more than a century ago when they committed their limited resources to improve the quality of life in the Valley and throughout Arizona. That mission remains similar in our second century - striving to serve water shareholders and power 3
customers with affordable, reliable water and power.
We and the other elected leaders of SRP are proud of the direction this organization is headed, and we remain committed to working with management to reinforce these principles of stewardship, service and community responsibility in the years ahead.
David Rousseau President VJohn R. Hoopes Vice President
We can't simply wait and expect that previous levels of economic growth and prosperity will return. SRP is taking a more active role in managing our future more assertively.
LETTER FROM THE GENERAL MANAGER Mark B.Bonsall General Manager& CE0 4
The significant accomplishments of the past year led by positive financial results and national recognition for superior customer service - would not have been possible without support from all levels within SRP and the leadership of the new senior management team. This team possesses a blend of experience, vision, creativity and a proven collaborative style. These qualities will serve SRP very well in the next decade and beyond.
Our focus is very squarely on our customers and the resources necessary to provide them with exceptional service and value.
The customer value objective is about extending our industry lead through innovative programming and operational excellence.
For instance, we expanded programs that provide customer interaction via telephone, voice and text message, mobile devices, email, social media and the Web. Also, nearly all our customers now have smart meters, giving them access to important information and tools that provide them with a greater understanding of and control over their energy usage. Additionally, we introduced SRP EZ-3"T, our newest variation of time-of-day pricing, which has more than 50,000 customers participating and continues to grow.
Our resource objective is to supplement water supplies and develop new power generation options to prepare for multiple possible outcomes during the next decade.
To address the water supply, we began planning a new underground water storage facility in the Queen Creek area.
We also developed an innovative new partnership with the Gila River Indian Community (GRIC) to provide water resource expertise in exchange for access to a portion of the GRIC water supply for use in certain projects and in short supply years. On the power side, we added the 20-megawatt (MW) Copper Crossing Solar Ranch in Florence to our portfolio, which supports our customer-centric Community Solar program.
We increased our stake in renewable baseload energy through the Hudson Ranch 1 geothermal project in California.
The 575-MW, gas-fired Coolidge Generating Station came online and is supplying flexible dispatch energy to SRP both during peak times and when renewable sources, such as wind and solar, are unavailable.
As the operator of Navajo Generating Station (NGS), we have taken the lead for the plant's five owners in important negotiations. These include a lease renewal with the Navajo Nation as well as fuel contracts with NGS suppliers.
Both are essential to ensure this important coal resource continues to operate beyond 2019. As SRP works toward these agreements, we're also engaged in the discussion over potential new environmental rules that have an impact on NGS and costs. All these issues affect the plant's future.
We're taking a proactive approach to economic development in the Valley. We supported the expansion of high-tech manufacturing at Intel's Chandler site and have taken an active role in the development of First Solar's new manufacturing facility in Mesa. We also have been involved in planning for the future water needs of Superstition Vistas, a 275-square-mile tract of land in the far Southeast Valley that represents significant growth opportunity for SRP in the decades to come.
5 Finally, our commitment to the communities we serve remains stronger than ever.
We continue to support the important work being done by Arizona nonprofits, with $3.2 million in corporate contributions. So do our employees. They gave $1.3 million directly through our employee-led Boosters campaign, volunteered more than 22,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> through an SRP program called Dollars for Doers, and occupy leadership roles in many community organizations.
The dedication of our employees extends beyond volunteering. At work, they demonstrated their commitment to each other with an outstanding safety record that surpassed rigorous internal targets and was recognized for excellence by the American Public Power Association.
I'm optimistic that SRP is well positioned for the future and feel privileged to lead such an outstanding organization.
Mark B. Bonsall General Manager & CEO
The Hoopes Substation reflects SRP's important role in the state economy. This new substation will serve Intel Corp.'s latest expansion in Chandler as well as future growth at the site.
POWER SUPPLY With quick-response backup capacity now in place from Coolidge Generating Station (above),
SRP has moved forward with plans to add new sustainable and renewable energy sources. The 575-megawatt (MW)natural-gas plant, owned by TransCanada Corp., is supplying power to SRP during periods of peak demand and supporting the addition of intermittent renewable resources, such as solar and wind. 7 The Coolidge plant works well to back up renewable sources. Its 12 turbines can run independently, each coming to a full 48-MW load in 10 minutes. This allows SRP to call on it to produce energy in small increments when, for example, wind turbines at the Dry Lake Wind Power Project in northern Arizona stop spinning.
Most of our existing portfolio of gas-fired generation is not designed with the same amount of operating flexibility as the Coolidge units, which power up quickly, run at various output levels and then power down - over and over. The plant can produce anywhere from a minimum of 25 MW to a maximum of 575 MW.
Natural Gas/Other 14%
Hydra and Renewable 5%
Nuclear 16%
N SRP Fuel Mix (by %of total energy production)
Coal 47%
A diverse power supply ollows SRP to fake advantage of favorable fuel markets and provide electricity to customers at the lowest possible cost.
Purchased/Other 18%
The automated GateKeeper system operates water delivery gates remotely. By reducing repetitive trips and manual I
work, GateKeeper improves operating efficiency and safety, V and enables us to spend more time helping water customers.
WATER STI EWARDSHIP For more than 100 years, SRP has carefully managed a limited water supply. We are working to ensure there will be enough for today and tomorrow.
Our water management efforts were recognized and reaffirmed by congressional leaders through the passage of legislation that clarified jurisdictional issues involving C.C. Cragin Dam and 9
Reservoir, located about 25 miles north of Payson.
The measure, signed into law by President Barack Obama, cleared the way for SRP to assume full operational control of the Cragin facility and helped jumpstart pipeline projects involving the Town of Payson. The town is scheduled to start receiving water from Cragin during the next several years, which will more than double the town's existing water supply.
After two years of below-average runoff (this year was the 22nd driest on record), SRP has stepped up its efforts to promote water conservation and to remind Valley residents that drought is a way of life in the desert.
Bartlett 6% Cragin < 1%
Horseshoe <1 %
Saguaro4 %
Canon~,
A% kl Apache 15%
SRP Water Storage (by % of total reservoir acre-feet as of April 30, 2012)
At fiscal year-end, SRP's reservoir system was two-thirds full - Roosevelt 71%
and working as designed: capturing runoff in wet years and storing it for dry years.
Copper Crossing Solar Ranch in Florence provides power to the SRP Community Solar program. Instead of installing panels on their roofs, 1 Community Solar customers pay a little more each month to "adopt" utility-scale solar.
SUSTAINAEBILITY Supporting the development of solar energy is at the heart of SRP's Community Solar initiative, which allows customers to purchase blocks of energy attributed to the new 20-megawatt (MW)
Copper Crossing Solar Ranch. The program allotted 2 MW for residential customers and 8 MW for schools. Both sold out, with the remaining energy now earmarked for commercial and additional residential customers. 11 Geothermal is one of the cleanest energy sources. Heat from the Earth is used to create steam that powers a turbine generator. No fuel is consumed. SRP will purchase geothermal energy beginning in mid-2015 from the planned 50-MW Hudson Ranch II plant in Southern California. SRP already receives energy from Hudson Ranch I (above), another 50-MW geothermal plant.
The core sustainability challenge for SRP is to provide reliable, safe and reasonably priced energy to support the future while reducing power plant emissions. That's why SRP is testing the use of coal additives. One additive has the potential to reduce nitrogen oxides emissions, while another has the potential to reduce mercury.
Wind 11%
Landfill Gas 4%
Biomass 2% 4 Solar 4%
SRP Sustainable Portfolio (by % of megawatt-hour) Geothermal 7% r-.
SRP now serves more than 9% of its retail electric load Hydropower 39%
through a sustainableportfolio. Our goat is to serve 20%with sustainable sources by 2020.
Energy Efficiency 38%
Through a rigorous hiring process, we employ great people. We prepare them with thorough training and equip them with advanced technology to provide customers with exceptional service whenever they call on us.
CUSTOMEIREXPERIENCE Excellent customer service is something SRP strives to deliver at every opportunity and encounter.
A new feature on SRP My Account TM , made possible by our use of smart meters, enables customers to find power outage information any place and time from their smartphones or tablets. With our Mobile Bill Pay, customers can make payments by sending a text message from any supported 13 mobile device. Our email, text message and social media communications provide additional convenience and useful information to customers on the go.
We continue to be recognized for exceptional customer service, but this year was special, with four top awards from J.D. Power and Associates.
SRP scored highest for both residential and commercial customer satisfaction in the 2011 national study of electric utilities. Our customer service efforts were recognized for a seventh consecutive year with J.D. Power's prestigious call center certification. We also were honored beyond the utility sector with J.D. Power's prestigious "Service Excellence Award," which compared SRP brand strength with 800 top companies across the broader economy.
EZ-3 6%
M-Power 15%
SRP Price Plans (by %of residential cuswmers)
From time-of-day to prepayment, SRP offers Basic 58%
price plan options to fit various lifestyles. Time-of-Use 21%
We encouragecustomers to select the right plans for their households.
lo I'
A I
SRP supplies educational resources and programming that reach nearly 200,000 Arizona students annually.
For example, SRP hosts more than 30 teacher workshops throughout the year about energy, water and the environment.
COMMUNITY COMMITMENT SRP's community efforts reflect our century-old commitment to improve the quality of life for the people we serve.
For example, water safety is an important part of the SRP Safety ConnectionTM program. We offer advice and reminders, including swimming and pool safety tips (above), to help prevent accidents.
Our employees can now turn their volunteer hours into much-needed funds for local nonprofit organizations through the SRP Dollars for Doers program. The program provides funding to nonprofit agencies when individual SRP employees volunteer time. SRP awarded $116,000 to 109 nonprofit agencies after 164 SRP employees donated more than 22,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />.
Through the long-standing Employee Boosters Association workplace campaign, SRP employees contributed more than $1.3 million in 2011 for nonprofit health and human services organizations inArizona.
SRP EarthWiseTM Energy funds solar photovoltaic systems for nonprofit organizations. This year, Hospice of the Valley, A New Leaf Inc. and the Boys & Girls Clubs of Metropolitan Phoenix received solar energy systems. These agencies were selected by customers who participate in this voluntary program. Environmental 3%
Civic 11% Arts and Culture 20%
SRP Corporate Contributions
~Education(by %of total donations)Edcto25 25%
SRP provided $3 2 million in corporate contributions to support nonprofit organizations that strengthen and serve our community
~and Health Human Services Al1%
MANAGEMENT'S FINANCIAL AND OPERATIONAL
SUMMARY
Oveview of Business The Salt River Project Agricultural Improvement and Power District (the District) owns and operates an electric system that generates, purchases, transmits, and distributes electric power and energy, and provides electric service to residential, commercial, industrial and agricultural power users in a 2,900-square-mile service territory spanning portions of Maricopa, Gila and Pinal counties, plus mining loads in an adjacent 2,400-square-mile area in Gila and Pinal counties.
The District remains a vertically integrated organization. It is developing additional generation, transmission and distribution resources to keep pace with load growth. The District builds and acquires generation resources as needed and makes short- and long-term purchases of wholesale power. For example, on'May 1, 2011, the 575-megawatt (MW)
Coolidge Generating Station went online. The natural-gas plant, owned by TransCanada Corp., is supplying power to SRP during periods of peak demand and supporting the addition of intermittent renewable resources, such as solar and wind.
SRP manages a system of dams and reservoirs, and has responsibility for the construction, maintenance and operation of a supply system to deliver raw water for irrigation and municipal treatment purposes. It provides the water supply for an area of approximately 248,200 acres within the major portions of the cities of Phoenix, Avondale, Glendale, Mesa, Tempe, Chandler, Peoria, Scottsdale and Tolleson; the Town of Gilbert; and the Gila River Indian Community.
The District's subsidiaries include Papago Park Center Inc., which manages a mixed-use commercial development known as Papago Park Center on land owned by the District and adjacent to the District's administrative offices; SRý Captive Risk Solutions Ltd., which is a domestic captive insurer incorporated inJanuary 2004 to primarily access property/boiler and machinery insurance coverage under the federal Terrorism Risk Insurance Act of 2002 for certified acts of terrorism; and New West Energy Corp., which was used to market, at retail, energy available to the District that was surplus to the needs of its retail customers and energy that might have been rendered surplus inArizona by retail competition in the supply of generation but is now largely inactive.
Results of Operations Operating revenues were $2.75 billion for FY12, compared with $2.76 billion for FY1 1.
Retail revenues were $25.9 million, or 1. 1% higher than the previous year. Wholesale revenues were $34.4 million, or 15.9% lower in FY]12 than in FY 11, resulting primarily from lower wholesale demand and prices.
The total number of customers increased by 0.8% from the previous year and totaled 956,757 as of April 30, 2012. Arizona's economy continued to be sluggish during the past year, and SRP expects the slower customer growth to continue until the economy in Arizona recovers.
Operating expenses were $2.5 billion for FY12, compared with $2.4 billion for FYI 1.
Fuel and purchased-power expenses were $100.8 million, or 10.8% higher in FY1 2 than in FYI 1 . SRP's fuel and purchased-power costs include adjustments for the fair value of fuel and purchased-power contracts. Without the fair-value adjustments, fuel and purchased-power costs would have decreased $80 million, or 8.2%, from the previous year. Depreciation and amortization expense decreased by $19 million compared with FYi 1. Taxes and tax-equivalent expense increased by $24.3 million compared with FYI 1.
Investment income resulted in a $1.3 million loss for FYI 2, compared with an $82.4 million gain in FYI 1. Investment income includes adjustments for changes in the fair value of investments. Without the fair-value adjustments, investment income would have been
$7.9 million for FYI 2 and $8.1 million in FY1 1. 17 Financing costs increased by $44. 1 million, or 27.7%, from the previous year The increase was primarily because of the interest expense related to a capital lease for the new Coolidge Generating Station, which began operation May 1, 2011.
The effects of the previously mentioned activities resulted in net revenues for FYi 2 of
$18.1 million, compared with $303.7 million for the prior year. Without the effects of the change in the fair value of investments, fuel and purchased-power contracts, and wholesale positions, net revenues would have been $163 million for FY12, compared with net revenues of $202.4 million for FYI 1.
TOTAL OPERATING REVENUE CAPITAL EXPENDITURES (in $millions) (in $millions)
$2,767 $2,762 $2,753 $1,076$042
$2,702 $780
$583 FY08 FY09 FY10 FYI11 FY12 FY08 FY09 FY10 FY11I FY12
MANAGEMENT'S FINANCIAL AND OPERATIONAL
SUMMARY
Energy Risk Management Program The District's mission to serve its retail customers is the cornerstone of its risk management approach. The District builds or acquires resources to serve retail customers, not the wholesale market. However, as a summer-peakirng utility, there are times during the year when the District's resources or reserves are in excess of its retail load, thus giving rise to wholesale activity. The District has an Energy Risk Management Program to limit exposure to risks inherent in retail and wholesale energy business operations by identifying, measuring, reporting and managing exposure to market, credit and operational risks. To meet the goals of the Energy Risk Management Program, the District uses various physical and financial instruments, including forward contracts, futures, swaps and options. Certain of these transactions are accounted for under Accounting Standards Codification (ASC) 815, originally Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." For a detailed explanation of the effects of ASC 815 on the District's financial results, see Note 5 in the accompanying notes to the Combined Financial Statements.
The Energy Risk Management Program is managed according to a policy approved by the District's Board of Directors (Board) and overseen by a Risk Oversight Committee.
The policy covers market, credit and operational risks and includes portfolio strategies, authorizations, value-at-risk limits, stop-loss limits, and notional and duration limits. The Risk 18 Oversight Committee is composed of senior executives. The District maintains an Energy Risk Management Department, separate from the energy marketing area, that regularly reports to the Risk Oversight Committee. The District believes that its existing risk management structure is appropriate and risks are properly measured, reported and managed.
Ellectrkicuy Pricing The District has a diversified customer base, with no single retail customer providing more than 3% of its retail electric revenues. The District has implemented projects and programs geared toward enhancing customer satisfaction by offering customers a range of pricing and service options. Moreover, the District is one of the low-price leaders in the Southwest.
The District is a summer-peaking utility and has made an effort to balance the summer-winter load relationships through seasonal price differenitials. In addition, the District offers prices on a time-of-use basis for residential, commercial and industrial customers.
SRP's retail electric prices consist of three components: base prices, a Fuel and Purchased Power Adjustment Mechanism (FPPAM) and an Environmental Programs Cost Adjustment Factor (EPCAF). Base prices can be changed only through a formal public price process, while the FPPAM and EPCAF can be changed during a price process or with Board approval outside of a formal price process, but not more than once per quarter.
On March 11, 2010, the District Board approved an overall 4.9% system-average increase effective with the May 2010 billing cycle. There were no further pricing actions taken in FY11 or FY12.
Capital Improvement Program The Capital Improvement Program is driven by the need to sustain the generation, transmission and distribution systems of the District to meet customer electricity needs and to maintain a satisfactory level of service reliability.
FY12 capital spending levels were somewhat below original expectations. Generation projects accounted for 27% of the year's expenditures, including construction costs for Palo Verde Nuclear Generating Station as well as spending on selective catalytic reduction steel and substructure work for the Coronado Emissions Control Project.
Expansion of the electrical distribution system to meet future growth and to replace aging underground cable accounted for 37% of FYI 2 capital expenditures. Slightly less than one-quarter of the distribution system spending was for New Business projects. The addition of new transmission facilities made up 9% of the year's capital expenditures. FY12 transmission spending included support for the Southeast Valley transmission project as well as construction costs for a high-voltage transmission line.
19 DEBT RATIO 52.8% DEBT SERVICE COVERAGE RATIO 51 6 5 2 82" 50 6 5 0 2 78 48 9% 2.59 2 48 2.33 FY08 FY09 FYIO FY11 FY12 FY08 FY09 FYIO FYI 1 FY12
- Includes adjustments for Rate Stabilization Fund transactions
SALT RIVER PROJECT COMBINED BALANCE SHEETS APRIL 30, 2012 AND 2011 (THOUSANDS)
ASSETS 2012 2011 Utility Plant Plant in Service -
Electric $ 11,967,748 $ 10,790,019 Irrigation 351,449 337,748 Common 561,291 540,021 Total plant in service 12,880,488 11,667,788 Less: Accumulated depreciation on plant in service (5,883,430) (5,538,222) 6,997,058 6,129,566 Plant held for future use 40,179 30,434 Construction work in progress 421,240 801,875 Nuclear fuel, net 149,745 133,441 7,608,222 7,095,316 20 Other Property and Investments Non-utility properly and other investments 232,717 255,085 Segregated funds, net of current portion 892,875 1,080,542 1,125,592 1,335,627 Current Assets Cash and cash equivalents 604,563 443,002 Temporary investments 185,729 214,066 Current portion of segregated funds 155,305 317,535 Receivables, net of allowance for doubtful accounts 192,619 231,499 Fuel stocks 74,537 58,339 Materials and supplies 156,018 137,329 Current commodity derivative assets 12,757 8,713 Other current assets 14,272 15,554 1,395,800 1,426,037 Deferred Charges and Other Assets Regulatory assets 1,042,632 768,419 Non-current commodity derivative assets 8,784 11,087 Other deferred charges and other assets 58,866 62,996 1,110,282 842,502
$ 11,239,896 $ 10,699,482 The accompanying notes are an integral part of these Combined Financial Statements.
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SALT RIVER PROJECT COMBINED BALANCE SHEETS APRIL 30, 2012 AND 2011 (THOUSANDS)
CAPITAUZATION AND UABIUTIES 2012 2011 Long-Term Debt and Capital Lease Obligation $ 4,786,995 $ 4,419,099 Accumulated Net Revenues 4,270,426 4,252,310 Total Capitalization 9,057,421 8,671,409 Current Liabilities Current portion of long-term debt and capital lease obligation 155,142 139,635 Accounts payable 151,548 221,895 Accrued taxes and tax equivalents 89,172 77,142 Accrued interest 67,050 73,170 Customers' deposits 85,195 86,461 Current commodity derivative liabilities 50,940 19,551 Other current liabilities 234,477 358,554 833,524 976,408 Deferred Credits and Other Non-current Liabilities Accrued postretirement liability 872,635 673,453 Asset retirement obligations 109,149 100,212 Non-current commodity derivative liabilities 116,485 36,092 Other deferred credits and other non-current liabilities 250,682 241,908 1,348,951 1,051,665 Commitments and Contingencies (Notes 7, 9, 10, 11, 12 and 13)
$ 11,239,896 $ 10,699,482 The accompanying notes are an integral part of these Combined Financial Statements.
SALT RIVER PROJECT COMBINED STATEMENTS OF NET REVENUES FOR THE YEARS ENDED APRIL 30, 2012 AND 2011 (THOUSANDS) 2012 2011 Operating Revenues Retail electric $ 2,488,906 $ 2,463,007 Other electric 67,614 69,355 Wholesale 181,563 216,000 Water 14,868 14,169 Total operating revenues 2,752,951 2,762,531 Operating Expenses Power purchased 268,155 365,500 Fuel used in electric generation 768,272 570,134 Other operating expenses 646,234 599,924 Maintenance 281,049 282,972 Depreciation and amortization 417,924 436,875 22 Taxes and tax equivalents 129,383 105,054 Total operating expenses 2,511,017 2,360,459 Net operating revenues 241,934 402,072 Other Income Investment income (loss), net (1,322) 82,446 Other income (deductions), net (19,028) (21,441)
Total other income (loss), net (20,350) 61,005 Net revenues before financing costs 221,584 463,077 Financing Costs Interest on bonds, net 191,353 193,507 Capitalized interest (21,941) (32,540)
Amortization of bond discount/premium and issuance expenses (15,798) (12,293)
Interest on other obligations 49,854 10,725 Net financing costs 203,468 159,399 Net Revenues $ 18,116 $ 303,678 The accompanying notes are an integral part of these Combined Financial Statements.
SALT RIVER PROJECT COMBINED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED APRIL 30, 2012 AND 2011 (THOUSANDS) 2012 2011 Cash Flows from Operating Activities Net Revenues $ 18,116 $ 303,678 Adjustments to reconcile net revenues to net cash provided by operating activities:
Depreciation and amortization 417,924 436,875 Amortization of nuclear fuel 41,227 35,826 Amortization of bond discount/premium and issuance expenses (15,798) (12,293)
Change in fair value of derivative instruments 110,039 (20,724)
Change in fair value of investment securities 26,475 (18,197)
Other 9,505 28,424 Decrease (increase) in:
Fuel stocks and materials and supplies (34,887) (20,990)
Receivables, net of allowance for doubtful accounts 38,880 (29,274)
Other current assets 1,283 3,556 Deferred charges and other assets 1,193 27,195 Increase (decrease) in:
Accounts payable (95,668) 2,752 Accrued taxes and tax equivalents 12,030 4,803 Accrued interest 23 4,203 8,925 Current liabilities (125,343) 32,490 Deferred credits and other non-current liabilities ... (42,05 1) - _(56,561)
Net cash provided by operating activities 367,128 726,485 Cash Flows from Investing Activities Additions to utility plant, net (430,078) (563,708)
Proceeds from disposition of assets 3,848 1,953 Purchases of investments (1,842,316) (2,009,615)
Maturities of investments 615,941 535,335 Sales of investments 1,451,215 1,389,807 Net change in short-term investments related to segregated funds 145,700 _ (221, 38)
Net cash used for investing activities (55,690) -_ _(868,166)
Cash Flows from Financing Activities Proceeds from issuance of revenue bonds 971 496,834 Capital lease principal payments (11,213)
Repayment of long-term debt, including refundings __ (139635) _ 14Z,180)
Net cash provided by (used for) financing activities (149,877) 349,654 Net Increase in Cash and Cash Equivalents 161,561 207,973 Balance at Beginning of Year in Cash and Cash Equivalents 443,002 235,029 Balance at End of Year in Cash and Cash Equivalents $ 604,563 $ 443,002 Supplemental Information Cash paid for interest $ 225,386 $ 165,929 The accompanying notes are an integral part of these Combined Financial Statements.
SALT RIVER PROJECT NOTES TO COMBINED FINANCIAL STATEMENTS APRIL 30, 2012 AND 2011 (1) BASIS OF PRESENTATION:
The Company - The Salt River Project Agricultural Improvement and Power District (the Districtl is an agricultural improvement district organized in 1937 under the laws of the State of Arizona. Itoperates the Salt River Project (the Project),
a federal reclamation project, under contracts with the Salt River Valley Water Users' Association (the Association), by which it has assumed the obligations and assets of the Association, including its obligations to the United States of America for the care, operation and maintenance of the Project. The District owns and operates an electric system that generates, purchases, transmits and distributes electric power and energy, and provides electric service to residential, commercial, industrial and agricultural power users ina 2,900 square mile service territory in parts of Maricopa, Gila and Pinal counties, plus mine loads in an adjacent 2,400 square mile area inGila and Pinal counties. The Association, incorporated under the laws of the Territory of Arizona in 1903, operates an irrigation system as the agent of the District. The District and the Association are together referred to as SRP.
Principles of Combination - The accompanying Combined Financial Statements reflect the combined accounts of the 24 Association and the District. The District's financial statements are consolidated with its wholly-owned taxable subsidiaries:
SRP Captive Risk Solutions, Limited (CRS), Papago Park Center, Inc. (PPC) and New West Energy Corporation (New West Energy). CRS is a domestic captive insurer incorporated primarily to access property/boiler and machinery insurance coverage under the Federal Terrorism Risk Insurance Act of 2002 for certified acts of terrorism. PPC is a real estate management company. New West Energy was used to market, at retail, energy available to the District that was surplus to the needs of its retail customers, and energy that might have been rendered surplus inArizona by retail competition in the supply of generation, but is now largely inactive. All material intercompany transactions and balances have been eliminated.
Possession and Use of Utility Plant - The United States of America retains a paramount right or claim in the Project that arises from the original construction and operation of certain of the Project's electric and water facilities as a federal reclamation project. Rights to the possession and use of, and to all revenues produced by, these facilities are evidenced by contractual arrangements with the United States of America.
Basis of Accounting - The accompanying Combined Financial Statements are presented inconformity with accounting principles generally accepted in the United States of America (U.S. GAAP). The preparation of financial statements in compliance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and disclosures of contingencies. Actual results could differ from the estimates.
By virtue of SRP operating a federal reclamation project under contract, with the federal government's paramount rights, asset ownership and certain approval rights, SRP is subject to accounting standards as set forth by the Federal Accounting Standards Advisory Board (FASAB). Entities reporting in accordance with the standards issued by the Financial Accounting Standards Board (FASB) prior to October 19, 1999 (the date the American Institute of Certified Public Accountants [AICPA]
designated the FASAB as the accounting standard setting body for entities under the federal government) are permitted to continue to report in accordance with those standards. As permitted, SRP has elected to report its financial statements in accordance with FASB standards.
II I" :;.! ? _,.1. N',, ý JF ý J.ý T (2) SIGNIFICANT ACCOUNTING POLICIES:
Utility Plant - Utility plant is stated at the historical cost of construction. Capitalized construction costs include labor, materials, services purchased under contract, and allocations of indirect charges for engineering, supervision, transportation and administrative expenses and an allowance for funds used during construction (AFUDC). The cost of property that is replaced, removed or abandoned, less salvage, is charged to accumulated depreciation.
The District is the recipient of various federal grants under the American Recovery and Reinvestment Act of 2009 (ARRA) and accounts for the majority of these funds as a reduction to the related assets included in utility property in the accompanying Combined Balance Sheets and as an investing activity in the Combined Statements of Cash Flows. The remaining funds are recorded as a reduction to other operating expenses in the Combined Statements of Net Revenues and as operating activities in the Statements of Cash Flows. During the years ended April 30, 2012 and 2011 the amounts recorded related to federal grants were $170 million and $19.1 million, respectively.
Depreciation expense is computed on a straight-line basis over recovery periods of the various classes of plant assets. The recovery periods are established to recover costs through the District's price plans and may differ from the assets' estimated useful lives. The following table reflects the District's average depreciation rates on the average cost of depreciable assets, for the fiscal years ended April 30:
2012 2011 Average electric depreciation rate ................................................... 3.20% 3.59%
Average irrigation depreciation rate ................................................ 1.73% 1.93%
Average common depreciation rate ................................................ 6.62% 5.51%
In April 2011, the Nuclear Regulatory Commission (NRC) approved a 20-year license extension of the Palo Verde Nuclear 25 Generating Station (PVNGS). In response to the license extension, effective May 1, 2011, the District's Board of Directors (Board) approved the extension of the recovery period for PVNGS resulting in an average depreciation rate change from 2.74% to 0.50%. The Board also approved, effective May 1, 2011, an average depreciation rate change for the Coronado Generating Station (CGS) from 3.07% to 2.10%, for the Navajo Generating Station (NGS) from 4.62% to 0.15% and the Hayden Generating Station (Hayden) from 5.13% to 0.09% to enable the recovery of expected future costs associated with these plants.
For the years ended April 30, 2012 and 2011, there was $25.0 million and $18.5 million of non-cash investing activities related to property, plant and equipment purchases within accounts payable.
Allowance for Funds Used During Construction - AFUDC is the estimated cost of funds used to finance plant additions and is recovered in prices through depreciation expense over the useful life of the related asset. AFUDC is capitalized during certain plant construction and included in capitalized interest in the accompanying Combined Statements of Net Revenue. Composite rates of 4.50% and 4.86%were applied in fiscal years 2012 and 2011 to calculate interest on funds used to finance construction work in progress, resulting in $21.9 million and $32.5 million of interest capitalized, respectively.
Nuclear Fuel - SRP amortizes the cost of nuclear fuel using the units-of-production method. The units-of-production method is an amortization method based on actual physical usage. The nuclear fuel amortization and accrued expenses for both the interim and permanent disposal of spent nuclear fuel are components of fuel expense. Nuclear fuel amortization was
$41.2 million and $35.8 million infiscal years 2012 and 2011, respectively. Accumulated amortization of nuclear fuel at April 30, 2012 and 2011 was $548.8 million and $507.6 million, respectively. (See Note [13] CONTINGENCIES, Spent Nuclear Fuel for additional information.)
Asset Retirement Obligations - SRP accounts for its asset retirement obligations in accordance with authoritative guidance which requires the recognition and measurement of liabilities for legal obligations associated with the retirement of tangible long-lived assets. Liabilities for asset retirement obligations are recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities, due to the passage of time, is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. Retirement obligations associated with long-lived assets are those for which a legal obligation exists under enacted laws, statutes, and contracts, including obligations arising under the doctrine of promissory estoppel.
The District has identified retirement obligations for the PVNGS, NGS, Four Corners Generating Station (Four Corners) and certain other assets. Amounts recorded for asset retirement obligations are subject to various assumptions and determinations, such as determining whether an obligation exists to remove assets, estimating the fair value of the costs of removal, estimating when final removal will occur, and determining the credit-adjusted, risk-free interest rates to be utilized on discounting future liabilities. Subsequent to the initial recognition, the liability is adjusted for any revisions to the estimated future cash flows associated with the asset retirement obligation (with corresponding adjustments to property, plant and equipment), which can occur due to a number of factors including, but not limited to, cost escalation, changes in technology applicable to the assets to be retired, changes in federal, state and local regulations and changes to the estimated decommissioning date of the assets, as well as for accretion of the liability due to the passage of time until the obligation is settled.
During fiscal year 2011, a new decommissioning study with updated cash flow estimates was completed for PVNGS. This study reflects the twenty-year license extension approved by the NRC on April 21, 2011, which extends the commencement of decommissioning to 2045. The new study resulted in a $111.4 million decrease to the liability for asset retirements at April 30, 2011, primarily due to the change in timing of the cash flows.
26 A summary of the asset retirement obligation activity of the District at April 30 is included below (inthousands):
2012 2011 Beginning balance, May 1 $ 100,212 $ 199,348 Revisions in estimated cash flows - (111,405)
Accretion expense 8,937 12,269 Ending balance, April 30 $ 109,149 $ 100,212 Investments in Debt and Equity Securities - SRP invests in various debt and equity securities. Debt securities that SRP has the positive intent and ability to hold to maturity are classified as held-to-maturity securities and reported at amortized cost. Debt and equity securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in investment income, net. SRP has adopted the fair value option for all debt and equity securities other than those classified as held-to-maturity securities. All such securities are reported at fair value, with unrealized gains and losses included in investment income, net.
SRP does not classify any securities as available-for-sale. (See Note [4] FAIR VALUE OF FINANCIAL INSTRUMENTS.)
Securities Lending - During fiscal years 2012 and 2011, SRP's pension plan, NDT and other postretirement benefits plans participated ina securities lending program with the trustee of the investments. The program authorizes the trustee of the particular investments to lend securities, which are assets of the plans, to approved borrowers. The trustee requires borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The loaned securities are required to be collateralized. Under the program, the borrowers deliver collateral having a market value not less than 102% of the market value of the loaned securities. The cash collateral received is invested in a collateral pool made up of fixed income securities. SRP's pension plan, NDT and other postretirement benefits plans bear the risk of loss with respect to unfavorable changes in fair value of the invested collateral.
As of April 30, 2012, SRP exited the securities lending program for the NDT and the other postretirement benefits plans,
- ISIP ANNUA, iFPDý and as such, had no obligation for the collateral received or collateral investment pool investments as of April 30, 2012.
The pension plan's participation in the securities lending program continued as of April 30, 2012 and is contained within the pension plan. (See Note [6] FAIR VALUE MEASUREMENTS and Note [9] EMPLOYEE BENEFIT PLANS AND INCENTIVE PROGRAMS, Fair Value of Plan Assets for more information related to collateral pool investments.)
Segregated Funds - The District sets aside funds that are segregated due to management intent and to support various purposes. The District also has certain segregated funds that are legally restricted. The following amounts are included in segregated funds in the accompanying Combined Balance Sheets at April 30 (inthousands):
2012 2011 Segregated funds - legally restricted Nuclear Decommissioning Trust $ 257,114 $ 252,092 Collateral investment pool - 161,981 Debt Reserve Fund 80,598 80,598 Construction Fund - 182,966 Other 23,656 23,387 Total segregated funds - legally restricted 361,368 701,024 Segregated funds - other Benefits funds 525,715 538,821 Debt Service Fund 109,605 109,854 Rate Stabilization Fund 45,700 45,700 Other 5,792 2,678 Total segregated funds - other 686,812 697,053 27 Total segregated funds, including current portion $ 1,048,180 $ 1,398,077 Nuclear Decommissioning - In accordance with regulations of the NRC, the District maintains a trust for the decommissioning of PVNGS. The Nuclear Decommissioning Trust (NDT) funds are invested in debt and equity securities.
SRP has elected the fair value option for all NDT securities and such securities are reported as trading securities. Changes in fair value related to the NDT securities are included in the nuclear decommissioning regulatory asset or liability with no impact to net income. (See Note [3] REGULATORY MATTERS for additional information about the nuclear decommissioning regulatory asset or liability.) The NDT funds, stated at fair value, as of April 30, 2012 and 2011, were $2571 million and
$252.1 million, respectively. The NDT funds are classified as segregated funds in the accompanying Combined Balance Sheets and are exempt from federal and state income taxes. (See Note [4] FAIR VALUE OF FINANCIAL INSTRUMENTS for additional information about the NDT.)
Cash Equivalents - Cash equivalents include money market funds and highly liquid short-term investments with original maturities of three months or less, excluding those short-term investments included as part of the segregated funds and investments included in non-utility property and other investments in the accompanying Combined Balance Sheets. (For further discussion of financial instruments see Note [6] FAIR VALUE MEASUREMENTS.)
Allowance for Doubtful Accounts - Allowance for doubtful accounts is provided for electric customer accounts and other non-energy receivables balances based upon a historical experience rate of write-offs of accounts receivable as compared to accounts receivable balances. The allowance account is adjusted monthly for this experience rate and is maintained until either receipt of payment or the likelihood of collection is considered remote, at which time the allowance account and corresponding receivable balance are written off. SRP has provided for an allowance for doubtful accounts of $3.2 million and $3.0 million as of April 30, 2012 and 2011, respectively.
Fuel Stocks and Materials and Supplies - Fuel stocks and materials and supplies are stated at lower of weighted average cost or market.
Other Current Liabilities - The accompanying Combined Balance Sheets include the following other current liabilities as of April 30:
2012 2011 --
Securities lending $ $ 162,609 Sick, vacation and holiday (SVHL) accrual 85,098 78,627 Budget billing plan 45,258 51,689 Other 104,121 65,629 Total other current liabilities $ 234,477 $ 358,554 Other Income (Deductions), Net - Other income (deductions), net includes non-operating income and expense items. In fiscal year 2012 and 2011, this line includes a loss on the retirement of mechanical meters of $10.1 million and
$14.7 million, respectively. The mechanical meters were retired early due to the accelerated installation of smart meters funded by the Smart Grid Investment Grant Program established pursuant to the ARRA.
Financing Costs - Bond discount, premium and issuance expenses are deferred and amortized using the effective interest method over the terms of the related bond issues.
Voluntary Contributions in Lieu of Taxes - In accordance with Arizona law, the District makes voluntary contributions each year to the State of Arizona, school districts, cities, counties, towns and other political subdivisions of the State of Arizona, for which property taxes are levied and within whose boundaries the District has property included in its electric system. As a political subdivision of the State of Arizona, the District is exempt from property taxation. The amount paid is computed on the same basis as ad valorem taxes paid by a private utility corporation with allowance for certain water-related deductions. Contributions based on the costs of construction work in progress are capitalized, and those based on plant-in-28 service are expensed.
Revenue Recognition - SRP recognizes revenue when billed and accrues estimated revenue for electricity delivered to customers that has not yet been billed. The estimated revenue for electricity delivered but not yet billed is included in retail electric revenue and receivables, net, and was $74.6 million and $69.6 million at April 30, 2012 and 2011, respectively.
Other operating revenue consists primarily of revenue from marketing and trading electricity.
The electric industry engages in an activity called "book-out" under which some energy purchases are netted against sales and power does not actually flow in settlement of the contract. SRP presents the impacts of these financially settled contracts on a net basis, which resulted in a net reduction to revenue and purchase power expense of $50.2 million and
$34.6 million for fiscal years 2012 and 2011, respectively, but which did not impact net revenues or cash flows.
Sales and Use Taxes - The District is required by various government authorities, including states and municipalities, to collect and remit taxes on certain retail sales. Such taxes are presented on a net basis and excluded from revenues and expenses in the accompanying Combined Financial Statements.
Income Taxes - The District, as a political subdivision of the State of Arizona, is exempt from federal and Arizona state income taxes. The Association, as a private corporation, is not exempt from federal and Arizona state income taxes.
However, the Association is not liable for income taxes on operations relating to its acting as an agent for the District on the basis of a settlement with the Commissioner of Internal Revenue in 1949 which was approved by the Secretary of the Treasury. The Association is liable for income taxes on activities where it is not acting as an agent of the District. The tax effect of the District's wholly-owned taxable subsidiaries' operations is immaterial to the accompanying Combined Financial Statements.
Concentrations of Credit Risk - Financial instruments that potentially subject SRP to credit risk consist of cash and cash equivalents, temporary and other investments, and segregated funds. Certain balances exceed Federal Deposit Insurance Corporation (FDIC) insured limits or are invested in money market accounts with investment banks that are not FDIC insured.
101 2 *-;ýI A,,,,*,A, Rý,Jr SRP's cash and cash equivalents, temporary and other investments, and segregated funds are placed incredit-worthy financial institutions and certain money market accounts invest in U.S. Treasury Securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities.
The use of contractual arrangements to manage the risks associated with changes inenergy commodity prices creates credit risks resulting from the possibility of nonperformance by counterparties pursuant to the terms of their contractual obligations. In addition, volatile energy prices can create significant credit exposure from energy market receivables and mark-to-market valuations. The District has a credit policy for wholesale counterparties, continuously monitors credit exposures, and routinely assesses the financial strength of its counterparties. The District minimizes credit risk by dealing primarily with creditworthy counterparties, entering into standardized agreements which allow netting of exposures to and from a single counterparty, and requiring letters of credit, parent guarantees or other collateral when it does not consider the financial strength of the counterparty sufficient.
Revision - In 2012, SRP identified an error in its historical accounting for paid sick leave. SRP determined that the adjustment to correct the error was not material to any prior period financial results, but the cumulative adjustment to correct the error in the current period would have been material to fiscal year 2012 net revenues and would not appropriately reflect the net revenue impact of the adjustment for fiscal years 2012 and 2011, respectively. Accordingly, SRP revised its April 30, 2011 Combined Balance Sheets, Combined Statements of Net Revenues and Combined Statements of Cash Flows to appropriately reflect the accrual for paid sick leave. This revision resulted in a decrease in beginning of the year accumulated net revenues of $14.1 million and a decrease to April 30, 2011 accumulated net revenues of $15.0 million.
Net revenues decreased by $0.9 million for the year ended April 30, 2011. Utility plant increased by $2.7 million and other current liabilities increased by $177 million as of April 30, 2011. The net increase incash and cash equivalents for the year ended April 30, 2011 did not change; however, net cash provided by operating activities increased by
$0.1 million and net cash used for investing activities increased by $0.1 million.
29 Reclassifications - For comparative purposes, certain prior year amounts within the investing activities section of the Combined Statements of Cash Flows have been reclassified to conform to current year presentations. The reclassifications had no impact on total assets, net revenues or cash flows.
Recently Issued Accounting Standards - InMay 2011, the FASB issued amended guidance to converge fair value measurement and disclosure requirements for GAAP and International Financial Reporting Standards (IFRS). The amended guidance clarifies how certain fair value measurement principles should be applied and requires enhanced fair value disclosures. The guidance is effective for SRP on May 1, 2012. The adoption of this new guidance will result in additional fair value disclosures, but will not impact the accompanying Combined Financial Statements.
Subsequent Events - In February 2010, the FASB issued ASU No. 2010-09, "Subsequent Events (Topic 855):
Amendments to Certain Recognition and Disclosure Requirements," that requires an entity such as SRP to evaluate subsequent events through the date that the financial statements are either issued or available to be issued. The amendment also requires an entity to disclose the date through which the subsequent events have been evaluated and whether that date represents the date the financial statements were issued or the date they were available to be issued. SRP adopted the subsequent event guidance effective May 1, 2010. Subsequent events for SRP have been evaluated through July 2, 2012, which is the date that the financial statements were issued.
(3) REGULATORY MATTERS:
The Electric Utility Industry - The District operates in a highly regulated environment in which it has an obligation to deliver electric service to customers within its service area. In 1998, Arizona enacted the Arizona Electric Power Competition Act (the Act), which authorized competition in the retail sales of electric generation, recovery of stranded costs, and competition in billing, metering and meter reading. While retail competition was available to all customers by 2001, only a few customers chose an alternative energy provider and those customers have since returned to their incumbent utilities. At this
time, there is no active retail competition within the District's service territory or, to the knowledge of the District, within the State of Arizona, and the District's Direct Access Program is suspended.
Since 2006, three retail energy service providers, one meter reading service provider, and one meter service provider have applied to the Arizona Corporation Commission (ACC) for authorization to sell competitive services in Arizona, but the ACC has not ruled on any of the applications. However, effective July 1, 2012, the ACC has approved another major Arizona utility's proposed buy-through pilot program whereby a limited number of large industrial customers will be allowed to purchase generation from other providers. In addition, large industrial customers and merchant power plant owners have been urging state leaders to reinstate some form of retail competition.
The ACC staff issued a report inAugust 2010 indicating that while some form of retail electric competition may be in the public interest, further analysis and discussion of the issue was warranted. The ACC has not yet considered or acted upon the report and no timetable has been established. If the ACC were to decide to reinstitute retail competition, the existing rules would require significant revision.
Regulation and Pricing Policies - Under Arizona law, the District's publicly elected Board of Directors has the authority to establish electric prices. The District is required to follow certain public notice and special Board meeting procedures before implementing any changes in the standard electric price plans. The financial statements reflect the pricing policies of the District's Board.
The District's price plans include a base price component, a Fuel & Purchased Power Adjustment Mechanism (FPPAM) and an Environmental Programs Cost Adjustment Factor (EPCAF). Base prices recover costs for generation, transmission, distribution, customer services, metering, meter reading, billing and collections and system benefits charges that are not otherwise recovered through the FPPAM or the EPCAF. The FPPAM was implemented inMay 2002 to adjust for increases and decreases in fuel costs. The EPCAF was implemented in November 2009 to cover costs incurred by the District to 30 comply with renewable-energy, energy efficiency and climate-change related requirements imposed by mandate. Through a system benefits surcharge to the District's transmission and distribution customers, the District recovers the costs of programs benefiting the general public, such as discounted rates for low income customers and nuclear decommissioning, including the cost of spent fuel storage.
On March 11, 2010, the District Board approved an overall 4.9 percent system average increase effective with the May 2010 billing cycle. This overall increase was comprised of a 10.3 percent base increase and a 1.1 percent EPCAF increase that were partially offset by a 6.4 percent decrease in the FPPAM.
Rate Stabilization Fund - In accordance with Board action taken on March 11, 2010, SRP transferred $45.7 million into the Rate Stabilization Fund (RSF) inJuly 2010. The funds were available to stabilize future prices or for any other corporate purpose approved by the Board. On March 27 2012, the Board approved the release of the entire balance to the General Fund for general corporate purposes, effective May 1, 2012.
Regulatory Accounting - SRP accounts for the financial effects of the regulated portion of its operations in accordance with the provisions of authoritative guidance for regulated enterprises, which requires cost-based, rate-regulated utilities to reflect the impacts of regulatory decisions in their financial statements. SRP records regulatory assets, which represent probable future recovery of certain costs from customers through the pricing process, and regulatory liabilities, which represent probable future credits to customers through the ratemaking process. Based on actions of the Board, SRP believes the future collection of costs deferred through regulatory assets is probable. If events were to occur making full recovery of these regulatory assets no longer probable, SRP would be required to write off the remaining balance of such assets as a one-time charge to net revenues. None of the regulatory assets earn a rate of return.
,0] J *.*:.* Ah;'*JA I*F*D:*r The accompanying Combined Balance Sheets include the following regulatory assets and liabilities as of April 30:
Assets 2012 2011 Pension and other postretirement benefits (Note 9) $ 910,386 $ 646,348 Bond defeasance 103,644 85,668 Mohave Generating Station 28,602 36,403 Total regulatory assets $ 1,042,632 $ 768,419 Liabilities 2012 2011 Nuclear decommissioning $ 45,960 $ 28,991 Total regulatory liabilities $ 45,960 $ 28,991 The pension and other postretirement benefits regulatory asset is adjusted as changes in actuarial gains and losses, prior service costs and transition assets or obligations are recognized as components of net periodic pension costs each year and is recovered through prices charged to customers.
Bond defeasance regulatory assets are recovered over the remaining original amortization periods of the reacquired debt ending invarious years through fiscal year 2035.
The Mohave Generating Station regulatory asset is being recovered on a straight-line basis over a ten-year period ending in fiscal year 2016.
The nuclear decommissioning regulatory asset or liability is being deferred over the life of PVNGS and is being recovered through a component of the system benefits charge. Any difference between current year costs, revenues associated with nuclear decommissioning and earnings (losses) on the NDT is deferred in accordance with authoritative guidance for regulated enterprises and has no impact to SRP's earnings.
(4) FAIR VALUE OF FINANCIAL INSTRUMENTS:
SRP invests in U.S. government obligations, certificates of deposit and other marketable investments. Such investments are classified as cash and cash equivalents, temporary investments, other investments, and segregated funds in the accompanying Combined Balance Sheets depending on the purpose and duration of the investment.
Fair Value Option - SRP adopted authoritative guidance which permits an entity to choose to measure many financial instruments and certain other items at fair value. SRP has elected the fair value option for all investment securities other than those classified as held-to-maturity. Election of the fair value option requires the security to be reported as a trading security.
The fair value option was elected because management believes that fair value best represents the nature of the investments. While the investment securities held in these funds are reported as trading securities, the investments continue to be managed with a long-term focus. Accordingly, all purchases and sales within these funds are presented separately in the accompanying Combined Statements of Cash Flows as investing cash flows, consistent with the nature and purpose for which the securities are acquired.
Realized and unrealized gains and losses on these investments are included in investment income in the accompanying Combined Statements of Net Revenues.
The following table summarizes line items included in the accompanying Combined Balance Sheets at April 30 that include amounts recorded at fair value pursuant to the fair value option:
Measurement (in thousands) Attribute* 2012 2011 Cash and cash equivalents Cash N/A $ 39,043 $ 13,686 Money market funds Fair value 565,520 429,316 Total cash and cash equivalents 604,563 443,002 Non-utility property and other investments Money market funds Fair value 3,085 3,802 Trading investments Fair value 31,477 32,166 Held-to-maturity investments Amortized cost 110,500 136,119 Non-utility property N/A 87,655 82,998 Total non-utility property and other investments 232,717 255,085 Segregated funds, net of current portion Cash N/A 5,792 2,679 Money market funds Fair value 60,654 180,774 Trading investments Fair value 787,234 766,360 Held-to-maturity investments Amortized cost 39,195 130,729 Total segregated funds, net of current portion 892,875 1,080,542 Temporary investments Held-to-maturity investments Amortized cost 185,729 214,066 Total temporary investments 185,729 214,066 Current portion of segregated funds Money market funds Fair value 135,338 95,734 Trading investments Fair value 161,981 Held-to-maturity investments Amortized cost 19,967 59,820 Total current portion of segregated funds 155,305 317,535
- N/A - Asset category not eligible for fair value option.
SRP's investments in debt securities are measured and reported at amortized cost when there is positive intent and ability to hold the security to maturity. SRP's amortized cost and fair value of held-to-maturity securities were $355.4 million and
$358.2 million, respectively, at April 30, 2012 and $540.7 million and $545.2 million, respectively, at April 30, 2011.
At April 30, 2012, SRP's investments in debt securities have maturity dates ranging from May 14, 2012 to July 30, 2024.
SRP evaluates the held-to-maturity securities for other-than-temporary impairment on a quarterly basis considering numerous factors. At April 30, 2012 and 2011, SRP did not hold any impaired securities.
SRP's trading investments are measured at fair value with unrealized trading gains and losses included in investment income, net. The following table summarizes unrealized gains (losses) from fair value changes related to investments still held at April 30 (in thousands):
- , .5.-'A.14,JAIR-P i, I 2012 2011 Segregated funds, net of current portion $ (26, 123) $ 15,757 Current portion of segregated funds - 963 Non-utility property and other investments (352) 2,441 Investment income, net $ (26,475) $ 19,161 (5) DERIVATIVE INSTRUMENTS
Energy Risk Management Activities - The District has an energy risk management program to limit exposure to risks inherent in normal energy business operations. The goal of the energy risk management program is to measure and manage exposure to market risks, credit risks and operational risks. Specific goals of the energy risk management program include reducing the impact of market fluctuations on energy commodity prices associated with customer energy requirements, excess generation and fuel expenses, in addition to meeting customer pricing needs, and maximizing the value of physical generating assets. The District employs established policies and procedures to meet the goals of the energy risk management program using various physical and financial instruments, including forward contracts, futures, swaps and options.
Certain of these transactions are accounted for as commodity derivatives and are recorded in the accompanying Combined Balance Sheets as either an asset or liability measured at their fair value. Derivative instruments and the related collateral accounts, ifapplicable, that are subject to master netting agreements are presented as a net asset or liability on the consolidated balance sheet. Changes in the fair value of commodity derivatives are recognized each period in current earnings and included in the accompanying Combined Statements of Net Revenues and classified as part of operating cash flows in the accompanying Combined Statements of Cash Flows. Some of the District's contractual agreements qualify 33 and are designated for the normal purchases and normal sales exception and are not recorded at market value. This exception applies to physical sales and purchases of power or fuel where it is probable that physical delivery will occur; the pricing provisions are clearly and closely related to the underlying asset; and the documentation requirements are met.
Ifa contract qualifies for the normal purchases and normal sales scope exception, the District accounts for the contract using settlement accounting (costs and revenues are recorded when physical delivery occurs).
See Note (6), FAIR VALUE MEASUREMENTS, for additional information on derivative valuation.
Segregated Funds Investments - During fiscal year 2011, the District restructured the investments within certain of the segregated funds. As part of the restructuring, the District entered into non-commodity derivative transactions either as a way to gain exposure to certain sectors and countries without having to physically buy securities in that sector or country or as a hedge against downside risk. When the District seeks to gain exposure to certain financial market sectors, it may enter into exchange traded futures or forward contracts that provide the desired exposure. The contracts may be long or short term, and serve as a risk management tool for the portfolio. Similarly, the District may enter into option contracts on certain securities or sectors to minimize downside risk in the portfolio.
The District enters into a variety of non-commodity derivative instruments including futures, forwards, swaps and options primarily for trading purposes, with each instrument's primary risk exposure being interest rate, credit, and foreign exchange.
The fair value of these non-commodity derivative instruments is included within the segregated funds, net of current portion in the accompanying Combined Balance Sheets with changes in fair value reflected as investment income, net within the Combined Statements of Net Revenues and are classified as part of investing cash flows in the accompanying Combined Statements of Cash Flows.
Derivative Volumes - The District has the following gross derivative volumes, by type, at April 30, 2012:
Unit of Sales Purchases Commodity Measure Volumes Volumes Natural gas options, swaps and forward arrangements MMBtu 2,685,000 170,403,250 Electricity options, swaps and forward arrangements MWh 3,351,808 2,572,000 Liquefied fuel swaps Gallon 4,095,243 Unit of Sales Purchases Non-commodity Measure Volumes Volumes Fixed income contracts Shares 56,163,038 64,284,290 Foreign exchange contracts Shares 110,408,668 396,228,620 The District has the following gross derivative volumes, by type, at April 30, 2011:
Unit of Sales Purchases Commodity Measure Volumes Volumes Natural gas options, swaps and forward arrangements MMBtu 2,517,500 131,770,000 Electricity options, swaps and forward arrangements MWh 3,393,269 5,137,200 Liquefied fuel swaps Gallon 3,618,643 Unit of Sales Purchases Non-commodity Measure Volumes Volumes Fixed income contracts Shares 21,700,000 28,400,000 Foreign exchange contracts Shares 61,080,413 390,333,983 Presentation of Derivative Instruments in the Financial Statements - The following tables provide information about the gross fair values, netting, and collateral and margin deposits for derivatives not designated as hedging instruments inthe accompanying Combined Balance Sheets (inthousands):
April 30, 2012 Segregated Current Non-current Current Non-current Funds, Net Commodity Commodity Commodity Commodity of Current Derivative Derivative Derivative Derivative Total Assets Portion Assets Assets Liabilities Liabilities (Liabilities)
Commodities $ $ 15,657 $ 12,401 $ (81,045) $ (120,102) $ (173,089)
Fixed income contracts 4,875 4,875 Foreign exchange contracts (4,686) (4,686)
Netting (9,305) (3,617) 9,305 3,617 Collateral and margin deposits 6,405 20,800 27,205 Total $ 189 $ 12,757 $ 8,784 $ (50,940) $ (116,485) $ (145,695)
April 30, 2011 Segregated Current Non-current Current Non-current Funds, Net Commodity Commodity Commodity Commodity of Current Derivative Derivative Derivative Derivative Total Assets Portion Assets Assets Liabilities Liabilities (Liabilities)
Commodities $ $ 17,079 $14,498 $ (28,549) $ (39,503) $ (36,475)
Fixed income contracts (73) (73)
Foreign exchange contracts 7,696 7,696 Netting (8,998) (3,411 ) 8,998 3,411 Collateral and margin deposits 632 632 Total $ 7,623 $ 8,713 $ 11,087 $ (19,551) $ (36,092) $ (28,220)
The following tables summarize the District's unrealized gains (losses) associated with derivatives not designated as hedging instruments in the accompanying Combined Statements of Net Revenues (inthousands):
April 30, 2012 Fuel Used Investment Net Operating Power in Electric Income, Unrealized Revenues Purchased Generation Net Gain (Loss)
Commodities $ 1,259 $ 5,056 $ (143,911) $ - $ (137,596)
Fixed income contracts 4,875 4,875 35 Foreign exchange contracts (4,686) (4,686)
Total $ 1,259 $ 5,056 $ (143,911) $ 189 $ (137,407)
April 30, 2011 Fuel Used Investment Net Operating Power in Electric Income, Unrealized Revenues Purchased Generation Net Gain (Loss)
Commodities $ (12,136)$ 13,875 $ 27,765 $ - $ 29,504 Fixed income contracts (73) (73)
Foreign exchange contracts 7,696 7,696 Total $ (12,136)$ 13,875 $ 27,765 $ 7,623 $ 37,127 Credit Related Contingent Features - Certain of the District's derivative instruments contain provisions that require the District's debt to maintain an investment grade credit rating from each of the major credit rating agencies. If the District's debt were to fall below investment grade, it would violate these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions.
The aggregate fair value of all derivative liabilities with credit-risk-related contingent features as of April 30, 2012, was
$184.6 million for which the District has posted collateral of $20.8 million inthe normal course of business. Ifthe credit-risk-related contingent features underlying these agreements were triggered on April 30, 2012, the District could be required to post an additional $163.8 million of collateral to its counterparties.
(6) FAIR VALUE MEASUREMENTS:
SRP accounts for fair value in accordance with authoritative guidance which defines fair value, establishes methods for measuring fair value by applying one of three observable market techniques (market approach, income approach or cost approach) and establishes required disclosures about fair value measurements. This standard defines fair value as the price that would be received for an asset, or paid to transfer a liability, in the most advantageous market for the asset or liability in an arms-length transaction between willing market participants at the measurement date. SRP determines fair value of its financial instruments based on the market approach, which is defined as a valuation technique that uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
SRP has categorized its financial instruments, based on the priority of the inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices inactive markets for identical assets or liabilities (Level 1)and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are as follows:
Level 1 - Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market.Level 2 - Financial assets and liabilities whose values are based on quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in non-active markets, pricing models whose inputs are observable for substantially the full term of the asset or liabilities and pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means. Level 3 -
Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.
36
7CI) 32:' A N N -. , - ?-:
The following table sets forth, by level within the fair value hierarchy, SRP's financial assets and liabilities that were accounted for at fair value on a recurring basis as of April 30, 2012 (inthousandsl:
Netting and Level 1 Level 2 Level 3 Collateral Total Cash and cash equivalents:
Money market funds $ $ 565,520 $ $ 565,520 Total cash and cash equivalents 565,520 565,520 Non-utility property and other investments:
Money market funds 3,085 3,085 Mutual funds 31,477 - - 31,477 Total non-utility property and other investments 31,477 3,085 34,562 Segregated funds, net of current portion:
Money market funds 60,654 60,654 Mutual funds 101,055 101,055 Commingled funds - 218,290 4,112 222,402 Common stocks 271,357 271,357 Preferred stocks 158 158 37 Corporate bonds - 96,161 96,161 U.S. government securities - 95,813 95,813 Foreign currency 99 99 Fixed income derivative assets - 46,504 46,504 Fixed income derivative liabilities (41,629) (41,629)
Foreign exchange derivative assets 6,998 6,998 Foreign exchange derivative liabilities (11,684) t(11,684)
Total segregated funds, net of current portion 372,669 471,107 4,112 - 847,888 Current portion of segregated funds:
Money market fund 135,338 135,338 Total current portion of segregated funds - 135,338 135,338 Derivative instruments:
Commodities 6,984 11,440 9,634 (6,517) 21,541 Total $ 411,130 $ 1,186,490 $ 13,746 $ (6,517) $1,604,849 Liabilities Derivative instruments:
Commodities $ (7,767)$ (135,617)$ (57,763) $ 33,722 $ (167,425)
Total $ (7,767) $ (135,617) $ (57,763) $ 33,722 $ (167,425)
The following table sets forth, by level within the fair value hierarchy, SRP's financial assets and liabilities that were accounted for at fair value on a recurring basis as of April 30, 2011 (inthousands):
Netting and Level 1 Level 2 Level 3 Collateral Total Assets Cash and cash equivalents:
Money market funds $ - $ 429,316 $ $$ $ 42,1 429,316 Total cash and cash equivalents 429,316 429,316 Non-utility property and other investments:
Money market funds 3,802 3,802 Mutual funds 32,166 _ 32,166 Total non-utility property and other investments 32,166 3,802 - - 35,968 Segregated funds, net of current portion:
Money market funds 180,774 180,774 Mutual funds 98,649 98,649 Commingled funds 221,697 4,043 225,740 Common stocks 273,176 3,353 276,529 Preferred stocks 168 168 38 Corporate bonds 62,986 62,986 U.S. government securities 94,665 94,665 Fixed income derivative assets 116 1 117 Fixed income derivative liabilities (190) (190)
Foreign exchange derivative assets 7,696 45 7,741 Foreign exchange derivative liabilities (2) (43) (45)
Total segregated funds, net of current portion 379,613 563,478 4,043 947,134 Current portion of segregated funds:
Money market fund 95,734 95,734 Collateral pool investments - 161,981 161,981 Total current portion of segregated funds 95,734 161,981 257,715 Derivative instruments:
Commodities 7,926 10,248 13,403 (11,777) 19,800 Total $ 419,705 $ 1,102,578 $ 179,427 $ (11,777) $ 1,689,933 Liabilities Derivative instruments:
Commodities $ (3,761) $ (45,558) $ (18,733) $ 12,409 $ (55,643)
Total $ (3,761) $ (45,558) $ (18,733) $ 12,409 $ (55,643)
.161 ; 'V"u A, .1ý00Q_
Valuation Methodologies Securities Money market funds - Investments with maturities of three months or less when purchased, including certain short-term fixed-income securities, are considered cash equivalents. The fair value of shores in money market funds are priced based on inputs obtained from Bloomberg, a pricing service, whose prices are obtained from direct feeds from exchanges, that are either directly or indirectly observable.
Mutual funds - The fair values of shares in mutual funds are based on inputs that are quoted prices in active markets for identical assets and, therefore, have been categorized in Level 1 in the fair value hierarchy. Equities are priced using active market exchanges.
Corporatestocks - The fair values of shares in preferred and common corporate stocks are based on inputs that are quoted prices in active markets for identical assets and, therefore, have been categorized in Level 1 in the fair value hierarchy. Equities are priced using active market exchanges. Preferred and common corporate stocks are valued based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on exchanges which contain only actively traded securities due to the volume trading requirements imposed by these exchanges. Common stocks that are valued based on quoted prices from less active markets, such as over the counter stocks, are categorized as Level 2 in the fair value hierarchy.
U.S. government securities - The fair value of U.S. government securities is derived from quoted prices on similar assets in active or non-active markets, pricing models whose inputs are observable for the substantially full term of the asset, or from pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means; therefore, these securities have been categorized as Level 2 in the fair value hierarchy.
39 Commingled funds - Commingled funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with SRP's overall investment strategy. For equity and fixed-income commingled funds, the fund administrator values the fund using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities. Where adjustments to the NAV are required with respect to interests infunds subject to restrictions on redemption (such as lock-up periods or withdrawal limitations) and/or observable activity for the fund investment is limited, investments are classified within level 2 or 3 of the valuation hierarchy. If the ability to redeem the investment is unknown or the investment cannot be redeemed in the near term at NAV, the fair value measurement of the investment will be categorized as a Level 3 in the valuation hierarchy.
Collateralpool investments - These commingled funds were maintained and invested by the administrator of SRP's securities' lending program. The pools.were primarily invested in short-term fixed income securities, but may have also been invested in assets with maturities that match the duration of the loan of the related securities. These commingled funds were valued daily by the administrator and the underlying fixed income securities were priced using a primary price source that was identified based on asset type, class or issue for each security. SRP has obtained an understanding of how these prices were derived, including the nature and observability of the inputs used in deriving such prices. The fair values of fixed income securities were based on evaluated prices that reflect observable market information. However, these funds were categorized as Level 3 because the value that SRP would be able to exit at is not the unit value derived from the underlying prices. SRP exited the securities lending program in April 2012; therefore, there were no collateral pool investments as of April 30, 2012.
Corporatebonds - For fixed income securities, multiple prices and price types are obtained from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. SRP has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, SRP selectively corroborates the fair values of securities by comparison to other market-based price sources. The fair values
of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.
Non-commodity derivatives - Non-commodity derivatives include fixed income and foreign exchange contracts that are exchange traded derivatives or over-the-counter (OTC) derivatives. Exchange traded derivatives are priced based on inputs using quoted prices inthe active markets using observable inputs. Observable inputs reflect the assumptions market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the reporting entity. Therefore, these investments have been categorized as Level 1. OTC derivatives are priced based on inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly through corroboration with observable market data. Therefore, these investments have been categorized as Level 2.
Commodity Derivative Instruments The fair values of gas swaps and power swaps that are priced based on inputs using quoted prices of similar exchange traded items have been categorized in Level 1 in the fair value hierarchy. These include gas swaps traded on the New York Mercantile Exchange (NYMEX) and power swaps traded on the Intercontinental Exchange.
The fair values of gas swaps, power swaps, gas options, power options and power deals that are priced based on inputs obtained through pricing agencies and developed pricing models, using similar observable items in active and inactive markets, are classified as Level 2 in the valuation hierarchy.
The fair values of derivatives assets and liabilities which are valued using pricing models with significant unobservable market data traded in less active or underdeveloped markets are classified as Level 3 in the valuation hierarchy. Level 3 items include gas swaps, power swaps, gas options, power options and power deals. These inputs reflect management's 40 own assumptions about the assumptions a market participant would use in pricing the asset or liability (examples include long-dated or complex derivatives).
All of the assumptions above include adjustments for counterparty credit risk, using credit default swap data, bond yields, when available, or external credit ratings.
See Note (5), DERIVATIVE INSTRUMENTS, for additional detail of derivatives.
Investments Calculated at Net Asset Value - As of April 30, 2012, the fair value measurement of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those instruments, are as follows:
Fair Value Unfunded Redemption Redemption (in thousands) Commitments .Frequency Notice Period Mutual funds $ 132,532 None Daily N/A Commingled funds:
Fixed income funds 116,445 None Daily N/A International equity funds 101,845 None Monthly 2 days Domestic long-short equity fund of funds 4,112 None Annual 100 days
As of April 30, 2011, the fair value measurement of investments calculated at net asset value per share (or its equivalent),
as well as the nature and risks of those instruments, are as follows:
Fair Value Unfunded Redemption Redemption (in thousands) Commitments Frequency Notice Period Mutual funds $ 130,815 None Daily N/A Commingled funds:
Fixed income funds 97,427 None Daily N/A International equity funds 124,270 None Monthly 2 days Domestic long-short equity fund of funds 4,043 None Annual 100 days Mutual funds - These are funds invested in either equity or fixed income securities. They are actively managed funds that seek to outperform their respective benchmarks. The equity funds may invest in large and/or small capitalization stocks and/or growth or value styles, as dictated by their prospectuses. The fixed income funds will invest in a broad array of securities including treasuries, agencies, corporate debt, mortgage-backed securities, and some non-U.S. debt.
Fixed income commingled funds - The fund is an actively managed fund used by an investment manager to diversify an overall portfolio of separately managed fixed income securities. The fund may invest in fixed income securities of varying duration, maturity, credit quality, and geographic location. The securities may be non-U.S. securities.
International equity funds - The fund is an actively managed fund that invests in primarily non-U.S. securities. The funds may invest in small and/or large capitalization stocks, as well as developing country securities. The fund seeks to outperform their respective benchmarks.
Domestic long-short equity fund of funds - The fund is an actively managed fund of funds that primarily invests in managers that invest in domestic and some non-U.S. equities. As a long-short fund, the fund's goal is to neutralize market risk by balancing between managers that buy (go long) securities and managers who sell (go short) securities. The fund seeks to outperform a broad equity index over long periods, with less risk.
Collateral and Margin Deposits - Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the positions. SRP presents a portion of its margin and cash collateral deposits net with its derivative position on the accompanying Combined Balance Sheets. Amounts recognized as margin and collateral provided to others are included in derivative assets and/or derivative liabilities in the accompanying Combined Balance Sheets.
The margin deposits included in derivative assets totaled $6.4 million and $0.6 million at April 30, 2012 and 2011, respectively. The collateral posted with trading counterparties included in derivative liabilities totaled $20.8 million at April 30, 2012. There were no collateral deposits with counterparties included in derivative liabilities as of April 30, 2011.
Changes in Level 3 Fair Value Measurements - The tables below include the reconciliation of changes to the balance sheet amounts (inthousands) for the years ended April 30 for financial instruments classified within Level 3 of the valuation hierarchy; this determination is based upon unobservable inputs to the overall fair value measurement:
Segregated Current Funds, Net Portion of Commodity of Current Segregated Fiscal Year 2012 Derivatives Portion Funds Total Beginning balance at May 1 $ (5,330) $ 4,043 $ 161,981 $ 160,694 Transfers out of Level 3 3,477 3,477 Net realized and unrealized gain/
(loss) included in earnings (24,492) 69 380 (24,043)
Net realized and unrealized gain recorded as regulatory assets or liabilities 249 249 Sales (928,843) (928,843)
Purchases (19,050) - 766,233 747,183 Settlements (2,734) (2,734)
Balance at April 30 $ (48,129) $ 4,112 $--- $ (44,017)
Segregated Current Funds, Net Portion of Commodity of Current Segregated Fiscal Year 2011 Derivatives Portion Funds Total Beginning balance at May 1 $ 5,602 4,118 $ 136,710 $ 146,430 Transfers out of Level 3 1,552 1,552 Net realized and unrealized gain/
(loss) included in earnings (8,285) (75) 963 (7,397)
Net realized and unrealized gain recorded as regulatory assets or liabilities - 936 936 Sales (807,417) (807,417)
Purchases 2,602 830,789 833,391 Settlements (6,801) - (6,801)
Balance at April 30 $ (5,330) $ 4,043 $ 161,981 $ 160,694 Realized and unrealized gains and losses included in earnings identified above are included in wholesale revenues, power purchased, fuel cost, other operating expenses or investment income, as appropriate, in the accompanying Combined Statements of Net Revenues.
Fair Value Disclosures - U.S. GAAP requires disclosure of the estimated fair value of certain financial instruments and the methods and significant assumptions used to estimate their fair values. Many but not all of the financial instruments are recorded at fair value on the accompanying Combined Balance Sheets. Financial instruments held by SRP are discussed below.
Financialinstruments for which fair value approximates carrying value - Certain financial instruments that are not carried at fair value on the accompanying Combined Balance Sheets are carried at amounts that approximate fair value due to their short-term nature and generally negligible credit risk. The instruments include receivables, accounts payable, customers' deposits, other current liabilities and commercial paper.
Financialinstruments for which fair value does not approximate carrying value - SRP presents long-term debt at carrying value on the accompanying Combined Balance Sheets. The collective fair value of the District's revenue bonds and the Desert Basin Lease-Purchase Agreement, including the current portion, was estimated by using pricing scales from independent sources. The carrying amount of commercial paper approximates fair value because of its short term maturity and pricing confirmed through independent sources. As of April 30, 2012 and 2011, the carrying amounts, including current portion and accrued interest, were $4.5 billion and $4.6 billion, respectively, and the estimated fair values were
$4.9 billion and $4.6 billion, respectively. (See Note [7] LONG-TERM DEBT for further discussion of these items.)
(7) LONG-TERM DEBT AND CAPITAL LEASE OBLIGATION:
Long-term debt consists of the following at April 30 (in thousands):
Interest Rate 2012 2011 Revenue bonds 2002 Series A (matured 2012) 4.75-5.25% $ 309,280 2002 Series B (mature 2030 - 2032) 4.75 - 5.00% 468,400 89,175 2002 Series C (mature 2013 - 2015) 5.00% 140,800 89,755 2004 Series A (mature 2013 - 2024) 4.00- 5.00% 104,450 43 2005 Series A (mature 2027 - 2035) 4.75 - 5.00% 327,090 327,090 2006 Series A (mature 2033 - 2037) 5.00% 296,000 296,000 2008 Series A (mature 2016 - 2038) 5.00% 816,650 816,650 2009 Series A (mature 2013 - 2039) 2.75 - 5.00% 706,680 725,430 2009 Series B (mature 2013 - 2020) 3.00- 4.50% 296,375 296,375 2010 Series A (mature 2040 - 2041) 4.839% 500,000 500,000 2010 Series B (mature 2014 - 2027) 2.00 - 5.00% 216,785 216,785 2011 Series A (mature 2012 - 2030) 3.00- 5.00% 441,500 2012 Series A (mature 2029 - 2031) 5.00% 236,185 Total revenue bonds 4,016,195 4,201,260 Unamortized bond (discount) premium 191,810 111,629 Total revenue bonds outstanding 4,208,005 4,312,889 Finance lease 3.70- 5.25% 178,390 195,845 Commercial paper 50,000 50,000 Total long-term debt 4,436,395 4,558,734 Less: Current portion of long-term debt (143,025) (139,635)
Total long-term debt, net of current $ 4,293,370 $ 4,419,099
The annual maturities of long-term debt (excluding unamortized bond discount/premium) as of April 30, 2012, due infiscal years ending April 30, are as follows (inthousands):
Revenue Bonds Finance Lease 2013 $ 120,030 $ 22,995 2014 112,765 17,500 2015 116,185 27,715 2016 106,960 16,075 2017 100,850 35,115 Thereafter 3,459,405 58,990 Total $ 4,016,195 $ 178,390 Revenue Bonds - Revenue bonds are secured by a pledge of, and a lien on, the revenues of the electric system, after deducting operating expenses, as defined in the amended and restated bond resolution, effective inJanuary 2003, as amended (Bond Resolution). The Bond Resolution requires the District to charge and collect revenues sufficient to fund the debt reserve account and pay operating expenses, debt service, and all other charges and liens payable out of revenues and income. Under the terms of the Bond Resolution, the District makes debt service deposits to a non-trusteed segregated fund. Included in segregated funds in the accompanying Combined Balance Sheets are $190.2 million and $190.5 million of debt service related funds as of April 30, 2012 and 2011, respectively. Additionally, the Bond Resolution requires the District to maintain a debt service coverage ratio of 1.1 or greater on outstanding revenue bonds. To be eligible to issue additional revenue bonds, the District must anticipate sufficient revenues to maintain that ratio post-issuance. For the years ended April 30, 2012 and 2011, the debt service coverage ratio was 2.59 and 2.78, respectively.
44 In October 2010, the District issued $500 million 2010 Series A Electric System Revenue Bonds as federally taxable, direct payment "Build America Bonds." Subject to the District's compliance with certain provisions of the ARRA, the District expects to receive cash subsidy payments from the United States Treasury equal to 35% of the interest payable on the 2010 Series A Bonds over the term of the 2010 Series A Bonds. The District accrued $8.5 million and $4.8 million for cash subsidy payments earned from the United States Treasury for the years ending April 30, 2012 and 2011, respectively. The accrued cash subsidy payments are included in the Combined Statements of Net Revenues as a reduction to interest on bonds, net.
Interest, Build America Bonds subsidy payments, and the amortization of the bond discount, premium and issue expense on the various issues result in an effective rate of 4.52% over the remaining term of the bonds.
In October 2010, the District also issued $216.8 million 2010 Series B Electric System Revenue Bonds, the proceeds of which were used with $0.8 million of available funds to fund an externally trusteed irrevocable escrow to defease
$235.0 million of outstanding Revenue Bonds (the 2010 Refunded Bonds). The funds inthe escrow will be applied to interest payments occurring after the sale and to the redemption price of the Refunded Bonds upon their respective call dates of November 1, 2010, January 1, 2012 and January 1, 2013. The bond defeasance is a non-cash activity on the Combined Statements of Cash Flows and the Refunded Bonds have been removed from SRP's balance sheet.
In October 2011, the District issued $441.5 million 2011 Series A Electric System Refunding Revenue Bonds, the proceeds of which were used to fund an externally trusteed irrevocable escrow to defease $479.2 million of outstanding Revenue Bonds (the 2011 Refunded Bonds). The funds in the escrow will be applied to interest payments occurring after the sale and to the redemption price of the 2011 Refunded Bonds upon their respective call dates of January 1, 2012 and January 1, 2013. The bond defeasance is a non-cash activity on the Combined Statements of Cash Flows and the 2011 Refunded Bonds have been removed from SRP's balance sheet.
InApril 2012, the District issued $236.2 million 2012 Series A Electric System Refunding Revenue Bonds, the proceeds of which were used to fund an externally trusteed irrevocable escrow to defease $261.4 million of outstanding Revenue Bonds
(the 2012 Refunded Bonds). The funds in the escrow will be applied to interest payments occurring after the sale and to the redemption price of the 2012 Refunded Bonds upon their call date of January 1, 2013. The bond defeasance is a non-cash activity on the Combined Statements of Cash Flows and the 2012 Refunded Bonds have been removed from SRP's balance sheet.
The District has authorization to issue additional Electric System Revenue Bonds totaling $1.168 billion principal amount and Electric System Refunding Revenue Bonds totaling $5.007 billion principal amount.
Finance Lease - In December 2003, the District entered into a lease-purchase agreement (Desert Basin Lease-Purchase Agreement) with Desert Basin Independent Trust (DBIT) to finance the acquisition of the Desert Basin Generating Station (Desert Basin) located in central Arizona. In a concurrent transaction, $282.7 million infixed-rate Certificates of Participation (COPs) were issued pursuant to a Trust Indenture, between Wilmington Trust Company, as trustee, and DBIT, to fund the acquisition of Desert Basin and other electric system assets of the District. Investors in the COPs obtained an interest in the lease payments made by the District to DBIT under the Desert Basin Lease-Purchase Agreement. Due to the nature of the Desert Basin Lease-Purchase Agreement, the District has recorded a lease-finance liability to DBIT with the same terms as the COPs.
Capital Lease Obligation - InMay 2008, the District entered into a 20-year purchase power agreement to purchase energy from a 575 MW simple cycle natural gas peaking facility. The commercial operation date of the facility was May 1, 2011. Upon expiration of the contract and with proper notice, the District may renew the agreement for another 10 years, subject to certain conditions. Under the agreement, the District will pay a capacity charge, operation and maintenance costs and property taxes. The District is also obligated to provide the natural gas needed to operate the facility. The capacity charge is paid monthly and will total approximately $51.9 million yearly. The District has concluded that this purchase power agreement is a capital lease. Accordingly, a capital lease asset and corresponding liability were recorded on May 1, 2011 in the amount of $517 million. The capital lease asset is being amortized on the straight-line 45 basis over the original 20-year term of the contract. Accumulated amortization as of April 30, 2012 is $24.8 million. The addition of the capital lease asset is excluded from investing activities in the Combined Statements of Cash Flows as a non-cash item.
Future minimum lease payments, excluding executory costs, under the capital lease as of April 30, 2012 are as follows (inthousands):
2013 $ 51,867 2014 51,867 2015 51,867 2016 51,867 2017 51,867 Thereafter 726,140 Total minimum lease payments 985,475 Less: Imputed interest (464,302)
Less: Imputed lessor profit on executory costs (15,431)
Less: Current portion of capital lease obligation (12,117)
Long-term capital lease obligation $ 493,625
(8) COMMERCIAL PAPER AND CREDIT AGREEMENTS:
The District is authorized by the Board to issue up to $475.0 million incommercial paper. The District had $50.0 million Series C Commercial Paper outstanding at April 30, 2012. At April 30, 2012, the Series C issue had an average weighted interest rate to the District of 0.19%. The commercial paper matures not more than 270 days from the date of issuance and is an unsecured obligation of the District.
The District had a $50.0 million revolving line-of-credit agreement supporting the $50.0 million of outstanding commercial paper at April 30, 2012. The revolving credit agreement was to expire September 16, 2012. Subsequent to April 30, 2012, the District renegotiated the agreement, increasing it to $100 million and extending the expiration date to May 16, 2017 The additional $50 million in credit under the renegotiated line of credit may be used to support the issuance of additional commercial paper or for other general corporate purposes. SRP has classified the commercial paper program as long-term debt inthe accompanying Combined Balance Sheets at April 30, 2012 and 2011.
The original and renegotiated revolving line-of-credit agreements contain various conditions precedent to borrowings that include, but are not limited to, compliance with the covenants set forth in the agreement, the continued accuracy of representations and warranties, no existence of default and maintenance of certain investment grade ratings on the District's revenue bonds. The agreements have various covenants, with which management believes the District was incompliance at April 30, 2012. The District has never borrowed under the agreements. Alternative sources of funds to support the commercial paper program include existing funds on hand or the issuance of alternative debt, such as revenue bonds.
(9) EMPLOYEE BENEFIT PLANS AND INCENTIVE PROGRAMS:
Defined Benefit Pension Plan and Other Postretirement Benefits - SRP's Employees' Retirement Plan (the Plan) covers 46 substantially all employees. The Plan is funded entirely from SRP contributions and the income earned on invested Plan assets. SRP made contributions of $132.0 million in fiscal years 2012 and 2011.
SRP provides a non-contributory defined benefit medical plan for retired employees and their eligible dependents (contributory for employees hired January 1, 2000 or later) and a non-contributory defined benefit life insurance plan for retired employees. Employees are eligible for coverage if they retire at age 65 or older with at least five years of vested service under the Plan (ten years for those hired January 1, 2000 or later), or any time after attainment of age 55 with a minimum of ten years of vested service under the Plan (20 years for those hired January 1, 2000 or later). The funding policy is discretionary and is based on actuarial determinations.
U.S. GAAP requires employers to recognize the overfunded or underfunded positions of defined benefit pension and other postretirement plans in their balance sheets. Any actuarial gains and losses, prior service costs and transition assets or obligations must be recorded on the balance sheet with an offset to accumulated other comprehensive income until the amounts are amortized as a component of net periodic benefit costs.
The Board has authorized the District to collect future amounts associated with the pension and other postretirement plan liabilities as part of the pricing process. The District established a regulatory asset for the amounts otherwise chargeable to accumulated other comprehensive income that are expected to be recovered through prices in future periods. The changes in actuarial gains and losses, prior service costs and transition assets or obligations pertaining to the regulatory asset are recognized as an adjustment to the regulatory asset or liability accounts as these amounts are recognized as components of net periodic pension costs each year. The District's amortization amounts for fiscal year 2012 are $2.1 million for prior service cost and $31.1 million for net actuarial loss. The District's amortization amounts for fiscal year 2011 are $2.1 million for prior service cost and $26.2 million for net actuarial loss.
The following tables outline changes in benefit obligations, plan assets, the funded status of the plans and amounts included in the accompanying Combined Financial Statements (inthousands):
Pension Benefits Postretirement Benefits 2012 2011 2012 2011 Change in benefit obligation Benefit obligation at beginning of year $ 1,486,308 $ 1,365,606 $ 561,446 $ 513,378 Service cost 42,662 38,307 11,440 10,287 Interest cost 82,881 80,243 31,346 30,236 Actuarial gain 183,801 56,031 41,402 26,895 Benefits paid (59,019) (53,879) (20,235) (19,349)
Benefit obligation at end of year $ 1,736,633 $ 1,486,308 $ 625,399 $ 561,447 Change in plan assets Fair value of plan assets at beginning of year $ 1,352,929 $ 1,105,452 $ -
Actual return on plan assets 40,968 169,356 Employer contributions 132,000 132,000 20,235 19,350 Benefits paid (59,019) (53,879) (20,235) (19,350)
Fair value of plan assets at end of year 1,466,878 1,352,929 Funded status at end of year $ (269,755) $ (133,379) $ (625,399) $ (561,447)
Amounts recognized in Combined Balance Sheets Other current liabilities $ - $ - $ (22,519) $ (21,104)
Accrued post-retirement liability (269,755) (133,379) (602,880) (540,343) 47 Net asset (liability) recognized $ (269,755) $ (133,379) $ (625,399) $ (561,447)
Amounts recognized as a regulatory asset*
Transition obligation (asset) $ - (2) $ (3)
Prior service cost (credit) 4,108 6,424 (6,786) (6,990)
Net actuarial loss 733,206 502,109 179,860 144,808 Net regulatory asset $ 737,314 $ 508,533 $ 173,072 $ 137,815 The following table represents the amortization amounts expected to be recognized or paid during the fiscal year ending April 30, 2013 (inthousands):
Pension Postretirement Benefits Benefits Net transition obligation/(asset) $ $ (1)
Prior service cost/(credit) $ 2,141 $ (266)
Net actuarial $ 40,378 $ 8,402
The following table outlines the projected benefit obligation and accumulated benefit obligation in excess of Plan assets (inthousands):
2012 2011 Projected benefit obligation $ 1,736,633 $ 1,486,308 Accumulated benefit obligation $ 1,507,028 $ 1,297,244 Fair value of Plan assets $ 1,466,878 $ 1,352,929 SRP internally funds its other postretirement benefits obligation. At April 30, 2012 and 2011, $525.7 million and
$533.7 million of segregated funds, respectively, were designated for this purpose.
The weighted average assumptions used to calculate actuarial present values of benefit obligations at April 30 were as follows:
Pension Benefits Postretirement Benefits 2012 2011 2012 2011 Discount rate 4.92% 5.69% 4.92% 5.69%
Rate of compensation increase 4.00% 4.00% N/A N/A Weighted average assumptions used to calculate net periodic benefit costs were as follows:
Pension Benefits Postretirement Benefits 2012 2011 2012 2011 Discount rate 5.69% 6.00% 5.69% 6.00%
48 Expected return on Plan assets 8.25% 8.25% N/A N/A Rate of compensation increase 4.00% 4.00% N/A N/A For employees who retire at age 65 or younger, for measurement purposes, a 70% annual increase before attainment of age 65 and a 70% annual increase on and after attainment of age 65 in per capita costs of health care benefits were assumed during 2012; these rates were assumed to decrease uniformly until equaling 5% in all future years.
The components of net periodic benefit costs for the years ended April 30, are as follows (inthousands):
Pension Benefits Postretirement Benefits 2012 2011 2012 2011 Service cost $ 42,662 $ 38,307 $ 11,440 $ 10,287 Interest cost 82,881 80,243 31,346 30,236 Expected return on Plan assets (112,972) (102,168)
Amortization of transition obligation (1) (1)
Amortization of net actuarial loss 24,708 20,597 6,349 5,576 Amortization of prior service cost 2,315 2,315 (203) (203)
Net periodic benefit cost $ 39,594 $ 39,294 $ 48,931 $ 45,895
-, I*' ii:'? All]rJUAI RýPU~ I Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in the assumed health care cost trend rates would have the following effect (inthousands):
One One Percentage Percentage Point Point Increase Decrease Effect on total service cost and interest cost components $ 8,538 $ (6,052)
Effect on postretirement benefit obligation $ 112,087 $ (77,148)
Plan Assets - The Board has established an investment policy for Plan assets and has delegated oversight of such assets to a compensation committee (the Committee). The investment policy sets forth the objective of providing for future pension benefits by targeting returns consistent with a stated tolerance of risk. The investment policy is based on analysis of the characteristics of the Plan sponsors, actuarial factors, current Plan condition, liquidity needs, and legal requirements.
The primary investment strategies are diversification of assets, stated asset allocation targets and ranges, and external management of Plan assets. The Committee determines the overall target asset allocation ratio for the Plan and defines the target asset allocation ratio deemed most appropriate for the needs of the Plan and the risk tolerance of the District.
The market value of investments (reflecting returns, contributions, and benefit payments) within the Plan trust appreciated 2.95% during fiscal year 2012, compared to an increase of 15.4% during fiscal year 2011. Changes in the Plan's funded status affect the assets and liabilities recorded on the balance sheet in accordance with FASB authoritative guidance.
Due to the District's regulatory treatment, the recognition of funded status is offset by regulatory assets or liabilities and is recovered through prices. The Pension Protection Act of 2006 establishes new minimum funding standards and restricts plans underfunded by more than 20% from adopting amendments that increase plan liabilities unless they are funded immediately. In December 2008, the Worker, Retiree, and Employer Recovery Act (WRERA) was enacted. Among 49 other provisions, the WRERA provides temporary funding relief to defined benefit plans during the current economic down-turn. The Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 (PACMBPRA) was signed into law during fiscal year 2011. WRERA and PACMBPRA will favorably impact the level of minimum required contributions.
The Plan's weighted-average asset allocations are as follows:
Target Allocations 2012 2011 Equity securities 65.0% 61.9% 65.1%
Debt securities 25.0% 29.4% 27.7%
Real estate 10.0% 8.7% 7.2%
Total 100.0% 100.0% 100.0%
The investment policy, as authorized by the Board, allows management to reallocate Plan assets at any time within a tolerance range up to plus or minus 5% from the target asset allocation which allows for flexibility in managing the assets based on prevailing market conditions and does not require automatic rebalancing ifthe actual allocation strays from the target allocation.
Fair Value of Plan Assets - The following table sets forth the fair value of SRP's Plan assets, by asset category, at April 30, 2012 (dollars in thousands):
Level 1 Level 2 Level 3 Total Money market funds $ 8,857 $ 45,727 $- $ 54,584 Mutual funds 278,057 - 278,057 U.S. government securities - 98,194 98,194 Corporate bonds - 206,297 206,297 Corporate stocks 382,102 398 382,500 Commingled funds - 232,121 85,111 317,232 Real estate - - 128,234 128,234 Exchange traded derivatives 686,069 - - 686,069 OTC derivatives - 46,003 46,003 Exchange traded derivative liabilities (683,433) - (683,433)
OTC derivative liabilities (46,859) (46,859)
Total assets $671,652 $581,881 $ 213,345 $ 1,466,878 The fair value of the Plan assets, excludes $332.7 million payable for collateral on loaned securities in connection with the participation of the Plan in securities lending programs.
The following table sets forth the fair value of SRP's Plan assets, by asset category, at April 30, 2011 (dollars inthousands):
Level 1 Level 2 Level 3 Total 50 Money market funds $ 654 $ 54,520 $ $ 55,174 Mutual funds 127,227 - 127,227 U.S. government securities 46,031 46,031 Corporate bonds 215,161 215,161 Corporate stocks 500,853 2,751 503,604 Commingled funds 239,719 65,549 305,268 Real estate - 97,485 97,485 Exchange traded derivatives 845,159 845,159 OTC derivatives 31,442 31,442 Exchange traded derivative liabilities (842,177) (842, 177)
OTC derivative liabilities - (31,445) (31,445)
Totalassets $ 631,716 $ 558,179 $ 163,034 $ 1,352,9-29 The fair value of the Plan assets, excludes $3072 million payable for collateral on loaned securities inconnection with the participation of the Plan in securities lending programs.
For a description of the fair value hierarchy, refer to Note (6) FAIR VALUE MEASUREMENTS.
Valuation Methodologies Real estate - Real estate commingled funds are funds with a direct investment ina pool of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, real estate investments have been categorized as Level 3 investments.
?ý , .- Z, ::, lu ,
Exchange traded derivatives - The fair values of exchange traded options and futures are priced based on inputs using quoted prices in active markets using observable inputs. Observable inputs reflect the assumptions market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the reporting entity. Therefore, these investments have been categorized as Level 1.
OTC derivatives - The fair values of OTC options, forwards, swaptions, and swaps are priced based on inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly through corroboration with observable market data. Therefore, these investments have been categorized in Level 2 inthe fair value hierarchy.
For an explanation of the valuation methodologies used to determine fair value of the assets of the Plan that are not listed above, refer to Note (61 FAIR VALUE MEASUREMENTS.
Changes in Level 3 Fair Value Measurements - The table below includes the reconciliation of changes to the balance sheet amounts for the years ended April 30 for financial instruments classified within Level 3 of the valuation hierarchy; this determination is based upon unobservable inputs to the overall fair value measurement:
Plan Assets (in thousands) 2012 2011 Beginning balance at May 1 $ 163,034 $ 133,207 Actual return on plan assets relating to assets still held at end of period 15,051 19,087 Purchases 35,260 10,740 Balance at April 30 $ 213,345 $ 163,034 Long-Term Rate of Return - The expected return on Plan assets is based on a review of the Plan asset allocations and consultations with a third-party investment consultant and the Plan actuary, considering market and economic indicators, historical market returns, correlations and volatility, and recent professional or academic research. 51 Employer Contributions - SRP expects to contribute $80.0 million to the Plan over the next valuation period.
Benefits Payments - SRP expects to pay benefits in the amounts as follows (inthousands):
Pension Benefits Postretirement Benefits Before Subsidy* Net 2013 $ 65,500 $ 23,250 $ 22,519 2014 70,347 25,283 24,464 2015 75,582 27,198 26,297 2016 81,355 29,136 28,144 2017 87,074 30,916 29,841 2018 through 2022 530,344 176,732 169,923
- Estimated future benefit payments, including prescription drug benefits, prior to federal drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
Defined Contribution Plan - SRP's Employees' 401(k) Plan (the 401(k) Plan) covers substantially all employees. The 401(k)
Plan receives employee pre-tax and post-tax contributions and partial employer matching contributions. Employees who hove one year of service inwhich they have worked at least 1,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> and who are also contributing to the 401 (k)Plan are eligible to receive partial employer matching contributions of $0.85 on every dollar contributed up to the first six-percent of their base pay that they contribute to the 401(k) Plan. Effective January 1, 2012, SRP increased its matching contribution from
$0.85 to $0.90 on every dollar contributed up to the first six-percent of employee base pay contributed. Employer matching contributions to the 401(k) Plan were $14.8 million and $14.0 million during fiscal years 2012 and 2011, respectively.
Employee Performance Incentive Compensation Program - During fiscal year 2011, a new Employee Performance Incentive Compensation program (EPIC) was approved by the Board. EPIC covers substantially all regular employees and the incentive compensation is based on the achievement of pre-established targets for fiscal years 2011 and 2012 combined. The total compensation accrued for EPIC through April 30, 2012 was $275 million.
(10) INTERESTS IN JOINTLY-OWNED ELECTRIC UTILITY PLANTS AND TRANSMISSION FACILITIES:
The District has entered into various agreements with other electric utilities for the joint ownership of electric generating and transmission facilities. Each participating owner inthese facilities must provide for the cost of its ownership share. The District's share of expenses of the jointly-owned plants and transmission facilities is included in operating expenses in the accompanying Combined Statements of Net Revenues.
The following table reflects the District's ownership interests in jointly-owned electric utility plants as of April 30, 2012 (inthousands):
Construction Ownership Plant in Accumulated Work Generating Station Share Service Depreciation in Progress Four Corners (NM) (Units 4 & 5) 10.00% $ 121,560 $ (101,195) $ 2,366 Navajo (AZ) (Units 1, 2 & 3) 21.70% 337,598 (322,131) 18,841 Hayden (CO) (Unit 2) 50.00% 141,610 (116,882) 10 Craig (CO) (Units 1 & 2) 29.00% 286,492 (233,599) 1,909 52 PVNGS (AZ) (Units 1, 2 &3) 17.49% 1,192,347 (1,027,808) 52,994
$ 2,079,607 $ (1,801,615) $ 76,120 The following table reflects the District's investment in jointly owned transmission facilities as of April 30, 2012 (inthousands):
Construction Plant in Accumulated Work Transmission Facility Service Depreciation in Progress Mead Phoenix $ 53,329 $(13,931) $3 Southwest Valley 77,227 (10,311)
Southeast Valley 183,028 (7,966) 887 Morgan-Pinnacle Peak 64,256 (66) 4,981 El Dorado 7,448 (4,011) 4,008 Southern Transmission 72,168 (29,475) 1,120 ANPP 58,779 (22,471) 502
$516,235 $(88,231) $11,501
(11) VARIABLE INTEREST ENTITIES:
On May 1, 2010, SRP adopted ASU No. 2009-17, "Consolidations (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities." The FASB authoritative guidance defines a variable interest entity (VIE) as a legal entity whose equity owners do not have sufficient equity at risk or lack certain characteristics of a controlling financial interest in the entity. This guidance identifies the primary beneficiary as the variable interest holder that has the power to direct the activities that most significantly impact the VIE's economic performance (power criterion) and has the obligation to absorb losses or right to receive benefits from the VIE (losses/benefits criterion). The primary beneficiary is required to consolidate the VIE unless specific exceptions or exclusions are met. SRP considers both qualitative and quantitative factors to form a conclusion whether it, or another interest holder, meets the power criterion and the losses/
benefits criterion. SRP performs ongoing reassessments of its VIEs to determine ifthe primary beneficiary changes each reporting period.
Unconsolidated VIEs - While SRP is not required to consolidate any VIE as of April 30, 2012 or 2011, it held variable interests in certain VIEs as described below.
InMay 2008, the District entered into a 20-year purchase power agreement to purchase energy from a 575 MW simple cycle natural gas peaking facility. The District has concluded that this purchase power agreement is a capital lease. The District has also determined that it is not the primary beneficiary of this variable interest entity since it does not control operations and maintenance, which it believes are the primary activities that most significantly impact the economic activities of the entity. See further discussion in Note (7) LONG-TERM DEBT AND CAPITAL LEASE OBLIGATION.
The District has entered into various long-term purchase power agreements with developing renewable energy generation facilities that extend for periods of 20 to 30 years. Two of the facilities, with capacities of approximately 50 MW and 20 MW, began commercial operation in fiscal year 2012 and one facility with capacity of 64 MW began commercial operation in fiscal year 2011. The District is receiving the power and renewable energy credits from these facilities and 53 other facilities started in prior years, and the amounts that the District paid to these projects were $34.3 million and
$175 million for fiscal years 2012 and 2011, respectively. Additional facilities are expected to begin commercial operation between fiscal year 2013 and fiscal year 2016. The expected capacity of all the facilities combined, once in operation, is approximately 291 MW. With the exception of two projects for which the District is obligated to pay operating and maintenance expenses, the District is only obligated to pay for actual energy delivered and will have no obligation with respect to any facilities that do not start commercial operations. Some of these agreements include a price adjustment clause that will affect the future cost. There are no minimum payment obligations under these agreements. The District has concluded that it is not the primary beneficiary of these VIEs since it does not control operations and maintenance, which it believes are the primary activities that most significantly impact the economic activities of the entity.
The District formed a partnership during fiscal year 2010 to market long-term water storage credits. The District made capital contributions to the partnership infiscal years 2012 and 2011 totaling $2.0 million and $1.0 million, respectively.
The District has a future maximum exposure up to a $25 million contribution limit. The District has concluded that it is not the primary beneficiary of this VIE since it does not have power to direct the activities related to the marketing of the long-term water storage credits, which represent the most significant economic activities of the VIE.
(12) COMMITMENTS:
Purchased Power and Fuel Supply - The District had various firm non-cancelable purchase commitments at April 30, 2012, which are not recognized in the accompanying Combined Balance Sheets. The following table presents actual payments and estimated future payments pertaining to firm purchase commitments with remaining terms greater than one year (inmillions):
Total Payments _ Purchase Commitments 2012 2011 2013 2014 2015 2016 2017 Thereafter Purchase power contracts* $ 109.0 $ 200.8 $ 62.8 $ 64.2 $ 65.7 $ 67.2 $ 68.8 $ 1,379.8 Fuel supply contracts 370.2 360.2 332.4 276.7 276.7 250.1 167.7 697.1 Total $ 479.2 $ 561.0 $ 395.2 $ 340.9 $ 342.4 $ 317.3 $ 236.5 $2,076.9
- Refer to Note (11)VARIABLE INTEREST ENTITIES for renewable energy facility purchase power commitments.
Inconjunction with an impairment analysis performed on generation-related operations, in August 1998, the District recorded provisions of $163.7 million for losses on certain contracts included in the table above. The provisions were being amortized over the life of the contracts, commencing January 1, 1999, and are fully amortized as of May 2011.
Amortization of $0.9 million and $12.3 million has been reflected as a reduction in purchased power expense in fiscal years 2012 and 2011, respectively.
Gas Purchase Agreement - In October 2007, the District entered into a 30-year gas purchase agreement with Salt Verde Financial Corporation (SVFC), an Arizona nonprofit corporation formed for the primary purpose of supplying natural gas to 54 the District. Under the agreement, the District is committed to purchase 10,120,000 MMBtus (millions of British thermal units) of natural gas in fiscal year 2013, 10,425,000 MMBtus infiscal year 2014, 10,425,000 MMBtus in fiscal year 2015, 10,270,000 MMBtus in fiscal year 2016, 10,420,000 MMBtus in fiscal year 2017 and 218,820,000 MMBtus over the balance of the term. These purchases are expected to supply approximately 20% of its projected natural gas requirements needed to serve retail customers over the remainder of the 30-year period. The District receives a discount off market prices and is obligated to pay only for gas delivered. Payments to SVFC under the agreement were $31.6 million and
$14.6 million in fiscal year 2012 and fiscal year 2011, respectively.
Operating Leases - The District entered into various operating leases to facilitate the operations of Springerville Unit 4, a 400 MW gas-fired plant owned by the District and operated by Tucson Electric Company (TEP). Total payments under the agreements to TEP and other parties were $13.0 million in fiscal years 2012 and 2011. Minimum payments under these agreements are estimated to be $13.3 million in fiscal year 2013 through fiscal year 2015, $9.5 million in fiscal years 2016 and 2017 and $2378 million thereafter. The leases expire in various years from 2015 through 2106.
(13) CONTINGENCIES:
Nuclear Insurance - Under existing law, public liability claims arising from a single nuclear incident are limited to
$12.595 billion. PVNGS Participants insure for this potential liability through commercial insurance carriers to the maximum amount available ($375.0 million) with the balance covered by an industry-wide retrospective assessment program as required by the Price-Anderson Act. If losses at any nuclear power plant exceed available commercial insurance, the District could be assessed retrospective premium adjustments. The maximum assessment per reactor per nuclear incident under the retrospective program is $1175 million including a 5% surcharge; applicable in certain circumstances, but not more than
$175 million per reactor may be charged in any one year for each incident. Based on the District's ownership share of PVNGS, the maximum potential assessment would be $61.7 million, including the 5% surcharge, but would be limited to
$9.2 million per incident in any one year.
2012 SRP ANNUAL REPORT PVNGS Participants also maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.750 billion, a substantial portion of which must first be applied to stabilization and decontamination. The District has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The coverage for property damage, decontamination, and replacement power is provided by Nuclear Electric Insurance Limited (NEIL). The District is subject to retrospective assessments under all NEIL policies if NEIL's losses inany policy year exceed accumulated funds. The maximum amount of retrospective assessments the District could incur under the NEIL policies totals approximately $10.8 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
Spent Nuclear Fuel - Under the Nuclear Waste Policy Act of 1982, the District pays $0.001 per kWh on its share of net energy generation at PVNGS to the U.S. Department of Energy (DOE). However, to date, for various reasons, the DOE has not constructed a site for the storage of spent nuclear fuel. Accordingly, APS has constructed an on-site dry cask storage facility to receive and store PVNGS spent fuel. PVNGS has sufficient capacity at its on-site spent fuel storage installation to be able to store all of the nuclear fuel that will be spent during the first operating license period which ends in December 2027 In addition, PVNGS has sufficient capacity to store a portion of the fuel that will be spent during the period of extended operation, which will end in December 2047 Potentially, and depending on how the NRC rules on the future unloading of spent fuel pools, PVNGS could use high capacity storage casks to store the balance of any fuel spent during the extended license period. The on-site facility stored its first cask in March 2003. As of April 30, 2012, ninety-four casks were being stored at the on-site facility.
The District's share of on-site interim storage at PVNGS is estimated to be $73.3 million for costs to store spent nuclear fuel from inception through the life of the plant. These costs are recovered through the District's base rates as a component of the system benefit charge. At April 30, 2012 and 2011, the District's accrued spent fuel storage cost was $25.8 million and $25.3 million, respectively, and included in deferred credits and other non-current liabilities on the accompanying Combined Balance Sheets. 55 Coal Supply Litigation - Navajo Nation v. Peabody (U.S. District Court, D.C. District - RICO Case) - In 1999, the Navajo Nation filed a lawsuit in the United States District Court in Washington D.C. (U.S. District Court) in which the Hopi Tribe later joined as a plaintiff. The lawsuit arose out of negotiations culminating in 1987 with amendments to the coal leases and related agreements. The Navajo Nation and the Hopi Tribe alleged that Peabody Western Coal Company (Peabody) (the coal supplier for NGS and Mohave), Southern California Edison Company (operating agent for Mohave),
the District (operating agent for NGS) and certain individual defendants, inviolation of the federal racketeering statutes, had improperly induced the Department of the Interior (DOI) to not approve the coal royalty rate proposed by the Navajo Nation. They further alleged that the DOI's failure to approve the rate caused the tribes to negotiate and settle upon a substantially lower royalty rate. The suit alleged $600.0 million in damages. The plaintiffs also sought treble damages against the defendants, measured by amounts awarded under the racketeering statutes. In addition, the plaintiffs claimed punitive damages of not less than $1.0 billion. In 2001, the claims of both the Navajo Nation and the Hopi Tribe were dismlssed n their ent;rety w'th respect to the Dislrlct.
On April 12, 2010, the Navajo Nation filed an amended complaint that did not include any RICO claims or claims against the District or any individual defendants. The amended complaint continued to allege $600.0 million indamages and punitive damages in the amount of $1.000 billion and sought to reform the coal leases to provide for a reasonable royalty rate, to dispossess the defendants of all interests in property on the Reservation and to permanently exclude the defendants from the Reservation.
On October 15, 2010, Peabody, the NGS Owners and the Mohave Owners agreed to settle the case with respect to the Hopi Tribe and on August 1, 2011, a settlement was agreed to with the Navajo Nation. Neither settlement had a material effect on SRP's results of operations. This ends the matter in regard to the claims of both the Hopi Tribe and the Navajo Nation.
Navajo Mine Permit - BHP Billiton Limited (BHP) operates the Navajo Coal Mine, which supplies the Four Corners Generating Station, in which the District owns 30% of Units 4 and 5. Several environmental groups have filed lawsuits challenging the mining permit and expanded operations. If these lawsuits were successful, they would result not only in increased cost of mining operations, which would be passed to the owners of the generating station, but could result in the suspension or termination of mining activities. APS, as operating agent of Four Corners, is working with BHP and other defendants to allow the expansion and continuation of the mine. The District cannot predict the outcome of these lawsuits at this time.
Environmental - SRP is subject to numerous legislative, administrative and regulatory requirements at the federal, state and local levels as well as lawsuits relative to air quality, water quality, hazardous waste disposal and other environmental matters. Such requirements have resulted, and will continue to result, in increased costs associated with the operation of existing properties. At April 30, 2012, and 2011, SRP accrued $36.4 million and $38.2 million, respectively, for environmental issues, on a non-discounted basis, which is included in deferred credits and other non-current liabilities on the accompanying Combined Balance Sheets. The following topics highlight some of the major environmental compliance issues affecting SRP.
Water Quality. Due to the nature of its business, from time to time the District is involved in various state and federal superfund matters. In September 2003, the EPA notified the District that it might be liable under the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) as an owner and operator of a facility within the Motorola 52nd Street Superfund Site Operable Unit 3. The District completed the remedial investigation at the facility, but other potentially responsible parties are still undertaking remedial investigations and feasibility studies and the District could still be liable for past costs incurred and for future work to be conducted within the Superfund Site with regard to groundwater. At the adjacent West Van Buren state superfund site, the Roosevelt Irrigation District IRID) has sued the District and numerous other parties claiming that as a result of groundwater contamination, RID has been damaged in excess of 56 $125.0 million. The District denies the allegations and intends to vigorously contest the claim. While the District is unable at this time to predict the outcome of these matters, it believes it has recorded adequate reserves as part of its environmental reserves to cover expected liabilities related to these issues.
Air Quality. Efforts to reduce emissions from fossil fuel power plants will substantially increase the cast of, and add to the difficulty of siting, constructing, and operating electric generating units. As a result of legislative and regulatory initiatives, the District is planning emission reductions at its coal-fired power plants. In particular, under the terms of a consent agreement with the EPA, the District agreed in 2008 to install additional pollution control equipment at CGS at a projected cost of approximately $539.0 million, with work expected to be complete in approximately June 2014. As of April 30, 2012, approximately $140.0 million remains to be completed.
The full significance of air quality standards and emission reduction initiatives to the District in terms of costs and operational problems is difficult to predict, but it appears that costly equipment may have to be added to existing units and that permit fees may increase significantly resulting in potentially material cost to the District as well as reduced generation. The District s sossing the ris',3 poi ci n t.aives cn !:s generttari osse's ano s ieveiaping coniingency pions 'a comply wi~h future laws and regulations restricting greenhouse gas emissions. There is no way to predict the impact of such initiatives on the District at this time.
The District has negoated a Consent Order with the Arizona Department of Environrnental Qoualty (ADEQ), pursuant to which the District will delay compliance with current Arizona limitations on mercury emissions until 2016, and instead implemented a control strategy designed to achieve a 70 percent reduction of mercury emissions at CGS on a facility-wide annual average basis beginning January 1, 2012 at an estimated annual cost of $3.75 million.
In February 2012, the EPA published its Mercury and Air Toxics Standards (MATS) rule, which contains emissions standards for hazardous air pollutants from existing and new coal- and oil-fired power plants under the CAA, including emissions of mercury and particulate matter. Additional controls may be required at all coal-fired plants in which the District has an
2012 SRP ANNUAL REPORT interest. The District is analyzing the final rule and potential effects on future operations at its coal-fired plants and cannot yet estimate the associated costs.
Provisions of the EPA's Regional Haze Rule require emissions controls known as Best Available Retrofit Technology (BART) for coal-fired power plants and other industrial facilities that emit air pollutants that reduce visibility in Class I areas such as national parks. The District has financial interests in several coal-fired power plants that are subject to the BART requirements.
The EPA is expected to propose a BART determination for NGS in 2012, with a final determination expected later. The District believes that BART for NGS requires the installation on all three units of low-NOx burners and separated over-fired air (LNB/SOFA). The LNB/SOFA equipment has been installed on all three units at a total cost of approximately
$45.0 million, of which the District's share was $9.8 million. Nevertheless, the EPA may also require the installation of post-combustion controls such as selective catalytic reduction (SCR) as well as controls for sulfuric acid mist emissions and fine particulate matter, which would cost approximately $1.2 billion, of which the District's share would be approximately
$260.0 million.
With respect to CGS, the ADEQ submitted a Regional Haze State Implementation Plan (SIP) to the EPA in February 201].
In the SIP, the ADEQ proposed that BART for CGS requires the LNB/SOFA. In November 2011, the EPA sent a letter to all sources in Arizona subject to BART requirements indicating that the agency is developing a Federal Implementation Plan (FIP) that would supersede the ADEQ plan. The EPA is expected to issue a proposed FIP in earlyJuly 2012 that would require SCR on both units at CGS. Under the terms of the consent agreement for CGS previously referenced, SCR for Unit 2 is already scheduled to be installed by June 2014. The projected capital cost to the District of adding SCR for Unit 1 is approximately $109.8 million. Arizona is intervening in litigation related to the schedule for finalizing the FIP. If the current schedule is not altered, a final FIP for Arizona would be issued in November 2012. Any additional BART controls required by the FIP must be installed within five years of the final FIP. 57 The EPA's proposed BART determination for Four Corners would require the installation of SCRs on all five units, or the closure of Units 1, 2 and 3 and SCRs on Units 4 and 5. The comment period expired on May 2, 2011 and the EPA is expected to issue a final determination in early July 2012. SCR for Units 4 and 5 could cost $530.0 million, of which the District's share would be $53.0 million. Depending on the final determination, new controls could be required to be operational before 2017 The BART determinations for District-owned generating stations in Colorado include recommendations for installation of new emission control equipment on Craig Unit 1, Craig Unit 2 and Hayden Unit 2. Tri-State, the operating agent for Craig, has provided the EPA with an estimate of approximately $213.1 million to install the emission control equipment at Craig Units 1 and 2, of which the District's share for the two units would be $62.0 million. According to Xcel Energy, the operating agent for Hayden, installation of SCR on Hayden Unit 2 would cost approximately $72.0 million, of which the District's share would be $36.0 million. The BART determinations are expected to be finalized by September 2012. If required, the new emission control equipment is expected to be :n operation within five years of the final BART determ~nalions.
In May 2009, the National Parks Conservation Association (NPCA) and other environmental and tribal groups, petitioned the U.S. Department of Interior Nao~onal Pork Service (DOI to certify to the EPA that visibility impairment ;n Grand Canyon National Pork was "reasonably attributable" to oxides of nitrogen and particulate matter emissions from NGS (the NGS Petition). On February 16, 2010, NPCA and a similar coalition of environmental and tribal groups filed a similar petition with both the DOI and the U.S. Department of Agriculture - U.S. Forest Service (DOA) with respect to Four Corners, asking the DOI and the DOA to certify to the EPA that impairment of visibility in sixteen areas within 300 kilometers of Four Corners, including the Grand Canyon National Park, among others, was reasonably attributable to pollutant emissions from Four Corners. However, the DOI and the DOA deferred action on the petitions pending completion of the BART determinations for the plants.
On January 20, 2011, NPCA and other environmental and tribal groups sued both DOI and the DOA, asserting that the agencies failed to act without unreasonable delay. The defendants filed a motion to dismiss the suit and both the District (on behalf of the NGS Owners) and APS (on behalf of Four Corners Owners) successfully intervened in the suit. On June 30, 2011, the U.S. District Court dismissed the suit and the decision was not appealed.
On October 4, 2011, following earlier notices of intent to sue, Earthjustice, representing Dine Citizens, Sierra Club, and National Parks Conservation Association, filed a citizen suit in the District Court of New Mexico against the co-owners of Four Corners, including the District, alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the CAA. The plaintiffs alleged that the defendants made two sets of major modifications to Units 4 and 5, in which the District owns 10%, which allowed the plant to significantly increase its emissions of pollutants without first obtaining a PSD permit. On January 13, 2012, the District was served with a Summons and First Amended Complaint asserting two additional claims related to Four Corners. In addition to the alleged PSD violations, the First Amended Complaint alleges violations of the New Source Performance Standards (NSPS) arising from the same two sets of modifications. Among other things, the plaintiffs ask the court to enjoin operations at Four Corners until defendants apply for and obtain a PSD permit and comply with the NSPS, order Four Corners to install best available control technology (BACT), and order civil penalties, including a beneficial mitigation project. APS has proposed to the EPA that these and other potential liabilities be resolved as part of the BART determination for Four Corners.
In December 2009, the EPA found that emissions of greenhouse gases (GHG) endanger public health and welfare. In April 2010, the EPA issued a rule that allows the EPA to regulate emissions of GHG by stationary sources such as power plants.
Thereafter, the EPA issued its "tailoring rule," which specifies thresholds that trigger permitting requirements for sources of GHG emissions. The rule applied to power plants on January 2, 2011. In March 2012, the EPA proposed a separate rule that would establish a single performance standard for C02 emissions from new power plants. This standard would apply to all newly constructed fossil-fuel-fired facilities. The EPA is expected to finalize the rule by 2013. At this time, the EPA has chosen not to address C02 emissions from existing plants, but could address them in a later rulemaking. The District cannot 58 predict the impact of these rules on its operations or finances at this time.
The California Legislature has enacted GHG Laws that have indirectly affected the District. As a result, the Los Angeles Department of Water and Power (LADWP), one of the participants in NGS, and SCE, a participant in Four Corners Units 4 and 5, are or will be selling their interests in those plants. Also, the California Air Resource Board (CARB) is developing a program to reduce California emissions of GHG, including an economy-wide cap-and-trade program for GHG. The CARB regulations could impact the District's ability to sell excess generation into California. Based on available information, the District cannot estimate or predict the impact of the California laws on it at this time.
Hazardous Waste. The EPA has issued a proposed rule seeking comments on regulatory options governing the handling and disposal of coal combustion residuals (CCRs), such as fly ash, bottom ash and flue gas desulfurization sludge (FGD). The District disposes of CCRs in dry landfill storage areas at CGS and NGS, with the exception of wet surface impoundment disposal of FGD sludge at CGS. Both CGS and NGS sell a portion of their fly ash for beneficial reuse as a constituent in concrete production. The District also owns interests in joint participation plants, such as Four Corners, Craig, t oayden ana Sprtngerville, vhich dospose of CCR.s n dry storage areas ane n ash ponds. The rogula,ea commuri~ty, including utilities, strongly opposes regulation of CCRs as hazardous waste and is exploring legislation that 'would prohibit the EPA from regulating CCRs as hazardous waste. The EPA is expected to issue a final rule in late 2012 or in 2013. At this time, it is too early to definitively estimate projected costs, but the costs could be substantial depending on the approach taken in the final rules.
EndangeredSpecies. Several species listed as threatened or endangered under of the Endangered Species Act (ESA) have been discovered in and around reservoirs on the Salt and Verde Rivers, as well as C.C. Cragin Reservoir operated by SRP.
Potential ESA issues also exist along the Little Colorado River in the vicinity of the Coronado and Springerville Generating Stations. The District obtained Incidental Take Permits (ITPs) from the United States Fish and Wildlife Service IUSFWS), which allow full operation of Roosevelt Dam on the Salt River and Horseshoe and Bartlett Dams on the Verde River. The ITPs, and associated Habitat Conservation Plans (HCPs), identify the obligations, such as mitigation and wildlife monitoring, the
2012 SRP ANNUAI REPORT District must undertake to comply with the ESA. The District has established trust funds to pay mitigation and monitoring expenses related to the implementation of both the Roosevelt HCP and Horseshoe-Bartlett HCP and believes it has recorded adequate reserves as a part of its environmental reserves to cover its related obligations. The District continues to assess the potential ESA liabilities along the Little Colorado River and at C.C. Cragin, and is working closely with the USFWS and other state and federal agencies to address potential species concerns as necessary, but cannot predict the ultimate outcome at this time.
Water Rights - The District and the Association are parties to a state water rights adjudication proceeding initiated in 1976 that encompasses the entire Gila River System (the Gila River Adjudication). This proceeding is pending in the Superior Court for the State of Arizona, Maricopa County, and will eventually result in the determination of all conflicting rights to water from the Gila River and its tributaries, including the Salt and Verde Rivers. The District and the Association are unable to predict the ultimate outcome of this proceeding.
In 1978, a water rights adjudication was initiated in the Apache County Superior Court for the State of Arizona with regard to the Little Colorado River System and will eventually result in the determination of all conflicting rights to water from the Little Colorado River and its tributaries, including Clear Creek, the location of C.C. Cragin Dam and Reservoir.
The District has filed its claim to water rights in this proceeding, which includes a claim for groundwater being used in the operation of CGS. The District is unable to predict the ultimate outcome of this proceeding, but believes an adequate water supply for CGS will remain available and that the rights to C.C. Cragin will be confirmed.
The City of Prescott, together with the Towns of Prescott V/alley and Chino Valley, have plans to withdraw groundwater from the Big Chino Groundwater Sub-Basin and transport the water to their respective service areas for municipal and industrial uses. The District opposed these plans because of the potential that such pumping would deplete the base flow of the Verde River, which is delivered to and used by Association shareholders. The District is negotiating agreements with the parties that will satisfy its concerns. 59 Other Litigation - In the normal course of business, SRP is exposed to various litigations or is a defendant in various litigation matters. In management's opinion, the ultimate resolution of these matters will not have a material adverse effect on SRP's financial position or results of operations.
Self-Insurance - SRP maintains various self-insurance retentions for certain casualty and property exposures. In addition, SRP has insurance coverage for amounts in excess of its self-insurance retention levels. SRP provides reserves based on management's best estimate of claims, including incurred but not reported claims. In management's opinion, the reserves established for these claims are adequate and any changes will not have a material adverse effect on SRP's financial position or results of operations. SRP records the reserves in deferred credits and other non-current liabilities in the accompanying Combined Balance Sheets.
2012 SRP ANNUAL REPORt REPORT OF INDEPENDENT AUDITORS To the Board of Directors of the Salt River Project Agricultural Improvement and Power District and the Board of Governors of the Salt River Valley Woter Users' Associotion In our opinion, the accompanying combined balance sheets and the related combined statements of net revenues and of cash flows present fairly, in all material respects, the financial position of the Salt River Project Agricultural Improvement and Power District and its subsidiaries and the Salt River Valley Water Users' Association (collectively, "SRP") at April 30, 2012 and 2011, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of SRP's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements 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 misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
61 PricewaterhouseCoopers LLP
[as Vegas, Nevada July 2, 2012
Dijfii&/bivý ,I A
Boards Salt River
SRP SRP COUNCILS The two Councils enact and amend bylaws relating to the governance of SRP and also serve as liaisons to Association shareho ders and District electors As with the SRP Boards, there is one Council for the Association and one for the District. The 30 Association Council members are e ected to staggered four-year terms from 10 voting districts.
The 30 District Council members are elected to staggered four-year terms from 10 voting div sions Most often. candidates seek eecion o both Councs District/Division 1 District/Division 2 Eldan R.Hart Gerald E.Geiger Ronald S.Kolb Kimberly A. Owens John R.Starr William W. Sheely District/Division 3 District/Division 4 Aaron M.Herrera Garvey M.Biggers Richard W.Swier Michael G.Rakow Paul A.Van Hofwegen Leslie C.Williams k
District/Division 5 District/Division 6 I
John R.Augustine Jacqueline L.Diller Miller J.Weston Lines Nicholas J.Vanderway John R.Shelton Robert W.Warren District/Division 7 District/Division 8 Mark A.Lewis Christopher J.Dobson Barry E.Paceley Mark L.Farmer Harmnen Tjaardo Jr.
Mark C.Pedersen District/Division 9 District/ Division 10 R50en C '5e*
W. Curtis Donc Laron J.DeWitt 41-4 William P.Schrader Jr, A
I Five-Year Operational and Statistical Review Financial Data ($000) 2012 2011 2010 2009 2008 Oe reeues 2c4 - _9 -
Tola. ce'eatlng expe"ses 2 ( ) .
1era otner income Io. ,er I 005 128 375 13 497) 58 I04 Net financing costs 59399 38,390 132474 123;216 Net revenues for the year (2) 303 ,/8 3/0 9/5 24/ 022l 25/ 103 Taxes and tax equivalents 05 ;)2 102 392 9? 840 93 376 Selected Data Debt service coverage ratio 2ý78 2,48 2.33 2 82 Debt ratio 51 0 506 51 6 48 9 Total electric sales (million kVhn) 31,960 32,591 33 064 33,998 Peak SRP retail customers (KW) 6 350 000 0438,000 6 4 0 ,000 6,578.000 Water deliveries (acre-eetJ (11 802,558 809,825 795,689 794,235 0
Ruo acre feetP 1 397 781 I )9 193 I 48 866 1 098 219 Fnonoyeas or ea-ed 43 90
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