ML083100367

Submittal of 2007 Annual Financial Reports

ML083100367
Person / Time
Site:	Palo Verde
Issue date:	10/29/2008
From:	Weber T Arizona Public Service Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
102-05918-TNW/KAR
Download: ML083100367 (158)

Text

10 CFR 50.71(b)

LAM Palo Verde Nuclear Generating Station Thomas N. Weber Department Leader Regulatory Affairs Tel. 623-393-5764 Fax 623-393-5442 Mail Station 7636 PO Box 52034 Phoenix, Arizona 85072-2034 102-05918-TNW/KAR October 29, 2008 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

Subject:

Palo Verde Nuclear Generating Station (PVNGS)

Units 1, 2, and 3 Docket Nos. STN 50-52815291530 Submittal of 2007 Annual Financial Reports Pursuant to 10 CFR 50.71(b), enclosed please find copies of the 2007 Annual Financial Reports for the Participants who jointly own PVNGS and do not file a Form 1 0-Q with the Securities and Exchange Commission or a Form 1 with the Federal Energy Regulatory Commission. These Participants are Salt River Project, Southern California Public Power Authority, and Los Angeles Department of Water and Power.

The remaining Participants who jointly own PVNGS file a Form 1 with the Federal Energy Regulatory Commission and are thereby exempt from filing an Annual Financial Report.

These Participants are Southern California Edison Company, El Paso Electric Company, Arizona Public Service Company and Public Service Company of New Mexico.

No commitments are being made to the NRC by this letter.

Should you have any questions, please contact Russell A. Stroud, Licensing Section Leader at (623) 393-5111.

Sincerely, Enclosure TNW/RAS/KAR/gat cc:

E. E. Collins Jr.

B. K. Singal R. I Treadway NRC Region IV Regional Administrator (w/o Enclosure)

NRC NRR Project Manager (w/o Enclosure)

NRC Senior Resident Inspector for PVNGS (w/o Enclosure)

A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway El Comanche Peak 11 Diablo Canyon E3 Palo Verde [ San Onofre [ South Texas 0 Wolf Creek 140rwl

M LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Financial Statements and Required Supplementary Information June 30, 2007 and 2006 (With Independent Auditors' Report Thereon)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Table of Contents Page(s)

Independent Auditors' Report 1-2 Management's Discussion and Analysis 3 - 13 Financial Statements:

Balance Sheets 14-15 Statements of Revenues, Expenses, and Changes in Fund Net Assets 16 Statements of Cash Flows 17-18 Notes to Financial Statements 19-58 Required Supplementary Information 59

KPMG LLP Suite 2000 355 South Grand Avenue Los Angeles, CA 90071-1568 Independent Auditors' Report The Board of Water and Power Commissioners Department of Water and Power City of Los Angeles:

We have audited the accompanying balance sheets of the City of Los Angeles' Department of Water and Power's Power Revenue Fund (Power System), an enterprise fund of the City of Los Angeles, California, as of June 30, 2007 and 2006, and the related statements of revenues, expenses, and changes in fund net assets and cash flows for the years then ended. These financial statements are the responsibility of the Los Angeles Department of Water and Power's (the Department) management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America and the standards applicable to financial audits contained in Government Auditing Standards issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Power System's internal control over financial reporting.

Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and the significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in note 1, the financial statements present only the Power System and do not purport to, and do not, present fairly the financial position of the City of Los Angeles, California, as of June 30, 2007 and 2006, the changes in its financial position or its cash flows for the years then ended in conformity with U.S.

generally accepted accounting principles.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Power System as of June 30, 2007 and 2006 and the changes in its financial position and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

In accordance with Government Auditing Standards, we have also issued our report dated November 14, 2007 on our consideration of the Power System's internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements, and other matters. The purpose of that report is to describe the scope of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on the internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Government Auditing Standards and should be considered in assessing the results of our audit.

KPMG LLP, a U.S. limited liability partnership, is the U.S.

member firm of KPMG International, a Swiss cooperative.

The management's discussion and analysis included on pages 3 through 13 and the schedules of funding progress for the pension plan and postemployment healthcare plan on pages 51 note 12(c) and 59 are not a required part of the basic financial statements but are supplementary information required by U.S. generally accepted accounting principles. We have applied certain limited procedures, which consisted principally of inquiries of management regarding the methods of measurement and presentation of the required supplementary information. However, we did not audit the information and express no opinion on it.

KPtMC, LCP November 14, 2007 2

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Management's Discussion and Analysis June 30, 2007 and 2006 (Unaudited)

The following discussion and analysis of the financial performance of the City of Los Angeles' (the City)

Department of Water and Power's (the Department) Power Revenue Fund (the Power System) provides an overview of the financial activities for the fiscal years ended June 30, 2007 and 2006. Descriptions and other details pertaining to the Power System are included in the notes to the financial statements. This discussion and analysis should be read in conjunction with the Power System's financial statements, which begin on page 14.

Using this Financial Report This annual financial report consists of the Power System's financial statements and required supplementary information and reflects the self-supporting activities of the Power System that are funded primarily through the sale of energy, transmission, and distribution services to the public it serves.

Balance. Sheets, Statements of Revenues, Expenses, and Changes in Fund Net Assets, and Statements of Cash Flows The financial statements provide an indication of the Power System's financial health. The balance sheets include all of the Power System's assets and liabilities, using the accrual basis of accounting, as well as an indication about which assets can be utilized for general purposes, and which assets are restricted as a result of bond covenants and other commitments. The statements of revenues, expenses, and changes in fund net assets report all of the revenues and expenses during the time periods indicated. The statements of cash flows report the cash provided by and used in operating activities, as well as other cash sources and uses, such as investment income and cash payments for bond principal and capital additions and betterments.

3 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Management's Discussion and Analysis June 30, 2007 and 2006 (Unaudited)

The following table summarizes the financial condition and changes in fund net assets of the Power System as of and for the fiscal years ended June 30, 2007, 2006, and 2005:

Table 1 - Summary of Financial Condition and Changes in Fund Net Assets (Amounts in millions)

Assets Utility plant, net Restricted investments Other noncurrent assets Current assets 2007 5,923 669 1,843 1,516 9,951 Liabilities and Fund Net Assets Long-term debt, net of current portion Other long-term liabilities Current liabilities Fund net assets:

Invested in capital assets, net of related debt Restricted Unrestricted Total fund net assets 4,183 737 June30 2006 5,709 955 1,362 1,720 9,746 4,262 710 662 5,634 1,774 1,159 1,179 4,112 9,746 2005 5,299 1,036 1,307 1,314 8,956 3,481 732 681 4,894 1,641 1,482 939 4,062 8,956 763 5,683 1,582 1,244 1,442 4,268 9,951 4

(Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Management's Discussion and Analysis June 30, 2007 and 2006 (Unaudited)

Revenues, Expenses, and Changes in Fund Net Assets (Amounts in millions)

Residential Commercial and industrial Sales for resale Other Total operating revenues Fuel for generation and purchased power Maintenance and other operating expenses Total operating expenses Operating income Nonoperating revenues (expenses):

Investment income Other nonoperating revenues and expenses, net Debt expenses Income before capital contributions and transfers Capital contributions Transfer to the reserve fund of the City of Los Angeles Increase in fund net assets 2007 818 1,643 103 36 2,600 (1,245)

(1,021)

(2,266) 334 Year ended June 30 2006 759 1,545 153 39 2,496 (1,283)

(1,004)

(2,287) 209 2005 693 1,421 102 39 2,255 (1,113)

(969)

(2,082) 173 153 123 113 15 (191)L 13 (167) 5 (146) 311 20 178 30 145 26 (175) 156 4,112 4,268 (158) 50 4,062 4,112 (160) 11 4,051 4,062 Beginning balance of fund net assets Ending balance of fund net assets 5

(Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Management's Discussion and Analysis June 30, 2007 and 2006 (Unaudited)

Assets Utility Plant During fiscal years 2007 and 2006, the Power System capitalized $281 million and $331 million of additions, respectively, including transfers from construction work in progress to utility plant in service. Of the

$281 million, $156 million, or 56%, related to distribution plant assets. In addition, during 2007, the Power System capitalized $53 million in transmission plant mostly related to the Pacific DC Intertie and Sylmar Converter Station, a jointly owned transmission facility that is approximately 846 miles and connects Southern California to the hydroelectric power of the Pacific Northwest. Of the $331 million, $186 million, or 56%,

related to distribution plant assets. In addition, during 2006, the Power System capitalized $61 million related to generation assets. Furthermore, the Power System had capital improvements to its transmission and distribution utility plant assets to maintain and support normal load growth of the distribution and transmission systems.

Construction work in progress increased by $203 million in fiscal year 2007 and by $136 million in fiscal year 2006. The 2007 increases were mostly attributable to the Pinetree Wind Project and Distribution Control Systems. The increase in 2006 was mostly attributable to the Pinetree Wind Project and other generation improvements.

Additional information regarding the Power System's utility plant assets can be found in note 4 in the accompanying notes to the financial statements.

The Department's strategy is to have generating utility plant assets that can produce energy from a variety of fuel types. This is referred to as a hedged power supply. This is important in that if the costs related to a particular fuel type rise substantially in a short period of time, the Department can utilize its mix of generation assets to meet customer demand and to minimize increases in fuel expense. The Department has implemented a $2 billion, ten-year plan to upgrade its local power plants and to implement a program that includes demand side management, alternative energy sources, and distributed generation. Through June 30, 2007, the Department has incurred $1.3 billion related to such upgrades.

On July 1, 2005, the Power System and other members of the Southern California Public Power Authority (SCPPA) completed the acquisition of natural gas reserves and other real property located in Pinedale Wyoming.

The transaction totaled in excess of $300 million of which the Power System contributed approximately

$230 million. This is the first natural gas reserves acquisition for the Power System. Additional information regarding the natural gas field can be found in note I in the accompanying notes to the financial statements.

6 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Management's Discussion and Analysis June 30, 2007 and 2006 (Unaudited)

The tables below summarize the generating resources available to the Department as of June 30, 2007. These resources include those owned by the Department (either solely or jointly with other utilities) as well as resources available through long-term purchase agreements. Generating station capacity is measured in megawatts (MWs).

Table 2 - Department-Owned Generation Facilities Net Net maximum dependable Number of Number of capability capability Type of fuel facilities units (MWs)

(MWs)

Natural Gas 4

(1) 22 3,421 3,354 Large Hydro 1

6 (2) 1,175 1,075 Renewables 14 22 (3) 233 (4) 177 Subtotal 19 50 4,829 4,606 CDWR (65)

(5)

(65)

Total 19 50 4,764 4,541 (1) Consists of the following generating stations: Harbor Station, Haynes Station, Scattergood Station, and Valley Station.

(2) The Castaic Plant currently has six out of seven units available due to ongoing modernization work scheduled to be completed by 2011.

(3) The Department-owned renewable resources include the twenty-two Los Angeles Aqueduct, Owens Valley, and Owens Gorge small hydro units that qualify under the Department's renewable resource definition. This number does not include two of the Scattergood gas-fueled units that partially burn digester gas in which the output related to the digester gas also qualifies under the Department's renewable resource definition.

(4) Includes 22 MWs of renewable energy generated at the Scattergood Station by burning digester gas from the Hyperion Treatment Plant.

(5) Energy payable to the California Department of Water Resources for energy generated at the Castaic Plant.

7 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Management's Discussion and Analysis June 30, 2007 and 2006 (Unaudited)

Table 3 - Jointly Owned and Contracted Facilities Type Large Hydro Nuclear Coal Renewables/DG Total"5)

Net maximum Number of capability facilities (MWs) 1 491

(

1 380 (2) 3 1,515 (3) 112 (4) 108 117 2,494 Net dependable capability (MWs) 389 374 1,515 108 2,386

()The Department's Hoover Plant contract entitlement is 25.16% of the Hoover total contingent capacity of 1,951 MWs, Current reduced lake level has reduced available capacity to 389 MWs.

(2) The Department's Palo Verde Station (PVNGS) entitlement is 9.66% of the maximum net plant capability of 3,938 MWs, (3) The Department's current Intermountain Station (IPP) entitlement is 57.67% of the maximum net plant capability of 1,800 MW. A portion of the IPP entitlement is subject to recall. The Department's Navajo Station entitlement is 21.20% of the maximum.net plant capability of 2,250 MWs. The Mohave Station generating units were removed from service at the end of 2005.

(4) The Department's contract renewable resources include energy generated from various landfills in the Los Angeles area, hydro from British Columbia, Canada, wind from Wyoming, variety of solar photovoltaic resources and fuel cell installations, also located in the Los Angeles area, and green energy purchases.

Customer distributed generation (DG) units located in the city also provide energy resources.

(5) Previously, the Department categorized customer energy efficiency (EE) and demand side management (DSM) programs that result in customer energy savings as a resource rather than as a means of reducing future load growth. The Department currently views EE and DSM programs that result in customer energy savings as a means of reducing future load growth.

8 8 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Management's Discussion and Analysis June 30, 2007 and 2006 (Unaudited)

Liabilities and Fund Net Assets Long-Term Debt As of June 30, 2007, the Power System's total long-term debt balance was $4.3 billion. The decrease of

$108 million over the prior year resulted from the scheduled maturities of $68.6 million and the cash defeasance of $39.8 million of Power System revenue bonds. Outstanding principal, plus scheduled interest as of June 30, 2007, is scheduled to mature as shown in the chart below:

Chart: Debt Service Requirements 0

0 0

$1,600,000

$1,400,000

$1,200,000

$1,000,000

$800,000

$600,000

$400,000

$200,000 I

2012 2017 2022 2027 2032 2037 2042 Five-Year Periods Ending As of June 30, 2007, $57 million principal amount of long-term debt is considered defeased and remains outstanding. This debt, together with trust funds set aside for its full repayment at scheduled maturity dates, is not reflected on the balance sheet.

In addition, the Power System had $503 million and $451 million on deposit in trust funds restricted for the use of debt reduction as of June 30, 2007 and 2006, respectively.

In September 2007, Standard & Poor's Rating Services, Moody's Investors Service, and Fitch Ratings affirmed the Power System's bond rating of AA-, Aa3, and AA-, respectively, due to the Power System's broad revenue stream, sound financial metrics, and the City Council authorizing the unfreezing of the energy cost adjustment factor, which allows the Power System to fully recover changes in purchased power costs, fuel costs, and 9

(Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Management's Discussion and Analysis June 30, 2007 and 2006 (Unaudited) renewable resource costs. Additional information regarding the Power System's long-term debt can be found in note 10 in the notes to the financial statements.

Changes in Fund Net Assets Operating Revenues The operating revenues of the Power System are generated from wholesale and retail customers. There are four major customer categories of retail revenue. These categories include residential, commercial, industrial, and other, which includes public street lighting. Table 4 summarizes the percentage contribution of retail revenues from each customer segment in fiscal years 2007 and 2006.

Table 4 - Revenue and Percentage of Revenue by Customer Class (Amounts in thousands)

Fiscal year 2007 Fiscal year 2006 Revenue Percentage Revenue Percentage Customer type:

Residential Commercial Industrial Other Total retail revenue 817,642 33%

758,932 32%

1,428,282 57 1,320,870 56 214,795 9

223,985 10 36,353 1

39,122 2

2,497,072 100% $

2,342,909 100%

While commercial customers consume the most electricity, residential customers represent the largest customer class. As of June 30, 2007 and 2006, the Power System had approximately 1.4 million customers. As shown in Table 5, 1.2 million, or 86%, of total customers were in the residential customer class.

Table 5 - Number of Customers and Percentage of Customers by Customer Class (Amounts in thousands)

Fiscal year 2007 Fiscal year 2006 Number Percentage Number Percentage Customer type:

Residential Commercial Industrial Other 1,247 86%

1,242 86%

185 13 186 13 14 1

14 1

2 3

1,448 100%

1,445 100%

10 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Management's Discussion and Analysis June 30, 2007 and 2006 (Unaudited)

Fiscal Year 2007 Retail revenues increased $154.2 million while wholesale revenues decreased $50.5 million from fiscal year 2006. The increase in retail revenue is mostly due to the unfreezing of the energy cost adjustment factor and a 3.2% increase in retail consumption. The decrease in wholesale revenue is due to decreased sales activity.

Fiscal Year 2006 Retail revenues increased $189.6 million and wholesale revenues increased $51 million from fiscal year 2005.

The increase in retail revenue is mostly due to discontinuing the deferral of revenue collected for out-of-market purchased power costs and beginning to recognize prior deferred amounts. The increase in wholesale revenue is due to increased sales activity in both the forward and real-time energy and capacity markets.

Operating Expenses Fuel for generation and purchased power are two of the largest expenses that the Power System incurs each fiscal year. Fuel for generation expense includes the cost of fuel that is used to generate energy. The majority of fuel costs include the cost of natural gas, coal, and nuclear fuel.

Purchased power expense includes the cost of buying power on the open market and paying the current portion of the Power System's purchase power contracts. Under these purchase power contracts, the Department has an entitlement to the energy that is produced at various generating stations and an entitlement to the use of various transmission facilities. Most of these contracts require the Department to pay for these services regardless of whether the energy or transmission is used. These types of contracts are referred to as "take-or-pay" contracts.

Depreciation expense is computed using the straight-line method based on service lives for all projects completed after July 1, 1973, and for all office and shop structures, related furniture and equipment, and transportation and construction equipment. Depreciation for facilities completed prior to July 1, 1973 is computed using the 5%

sinking fund method based on estimated service lives. The Department uses the composite method of depreciation and, therefore, groups assets into composite groups for purposes of calculating depreciation expense. Estimated service lives range from 5 to 75 years. Amortization expense for computer software is computed using the straight-line method over 5 years.

I1I (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Management's Discussion and Analysis June 30, 2007 and 2006 (Unaudited)

The table below summarizes the Power System's operating expenses during fiscal years 2007 and 2006:

Table 6 - Operating Expenses and Percentage of Expense by Type of Expense (Amounts in thousands)

Fiscal year 2007 Fiscal year 2006 Expense Percentage Expense Percentage Type of expense:

Fuel for generation 545,221 24% $

541,659 24%

Purchased power 699,841 31 741,810 32 Other operating costs 496,599 22 472,394 21 Maintenance 254,988 11 260,217 11 Depreciation and amortization 269,587 12 270,841 12 2,266,236 100% $

2,286,921 100%

Fiscal Year 2007 Fiscal year 2007 operating expenses were $21 million lower as compared to fiscal year 2006. Purchased power costs were $42 million lower as compared to fiscal year 2006. The decrease is attributable to lower sales for resale. This decrease was offset by a $4 million increase in fuel for generation expense related to natural gas run plants.

Other operating costs increased by $24 million and were offset in decreases in maintenance and depreciation expense of $5 million and $1 million, respectively. The increase in other operating costs was primarily due to

$10 million in customer accounting and collection expenses and $8 million in other production expenses. The decrease in maintenance costs was mostly related to distribution plant.

Fiscal Year 2006 Fiscal year 2006 operating expenses were $205 million higher as compared to fiscal year 2005. Fuel for generation expense increased by $63 million due to higher cost of natural gas. Purchased power costs increased due to economic purchases being made. Economic purchases are purchases of energy on the open market where the Department has determined the cost of acquiring the energy is less expensive than using available generation resources to meet customer demand.

Maintenance and depreciation increased by $23 million and $24 million, respectively. The increase in maintenance was due to addition work being performed on transmission assets. The increase in depreciation was due to additional assets being placed in service. These increases were offset by a decrease in other operating costs related to distribution assets.

12 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Management's Discussion and Analysis June 30, 2007 and 2006 (Unaudited)

Nonoperating Revenues and Expenses Fiscal Year 2007 The major nonoperating activities of the Power System for fiscal year 2007 included the transfer of

$174.7 million to the City's General Fund, interest income earned on investments of $153 million, and

$191 million in debt expenses.

The transfer to the City is based on 7% of the previous year's operating revenues. Operating revenues for fiscal year 2006 were $2.5 billion, which generated a city transfer of $174.7 million.

Interest income increased $30 million due to more cash available for investing in fiscal year 2007 as compared to 2006.

The increase in debt expense is due to having a full year of interest expense on the 2005 series debt that was issued December 2005 offset by slightly lower interest rates on variable rate debt. The variable rate bonds' daily and weekly rate range increased from 3.94% to 3.95% as of June 30, 2006 to 3.70% to 3.76% as of June 30, 2007.

Fiscal Year 2006 The major nonoperating activities of the Power System for fiscal year 2006 included the transfer of

$157.9 million to the City's General Fund, interest income earned on investments of $123 million, and

$167.5 million in debt expenses.

The transfer to the City is based on 7% of the previous year's operating revenues. Operating revenues for fiscal year 2005 were $2.3 billion, which generated a city transfer of $157.9 million.

Interest income increased $10 million due to interest rates trending higher in fiscal year 2006 as compared to 2005.

The increase in debt expense is due to the issuance $932 million of revenue bonds and higher interest rates on variable rate debt. The variable rate bonds' daily and weekly rate range increased from 2.22% to 2.27% as of June 30, 2005 to 3.94% to 3.95% as of June 30, 2006.

Other Significant Matters On October 2, 2007, the board of water and power commissioners approved an electric base rate increase of 2.9% effective January 1, 2008, 2.9% effective July 1, 2008, and 2.7% effective July 1, 2009. This increase is required to fund costs related to general inflation and Power System's reliability improvements. City Council's approval by ordinance is required.

13

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Balance Sheets June 30, 2007 and 2006 (Amounts in thousands)

Assets Noncurrent assets:

Utility plant:

Generation Transmission Distribution General Accumulated depreciation Construction work in progress Nuclear fuel, at amortized cost Natural gas field, net Restricted investments Long-term California wholesale energy receivable, net Long-term notes and other receivables, net of current portion Deferred debits Net pension asset Net postemployment asset Total noncurrent assets Current assets:

Cash and cash equivalents - unrestricted Cash and cash equivalents - restricted Cash collateral received from securities lending transactions Customer and other accounts receivable, net of $14,555 and

$33,432 allowance for losses, respectively Current portion of long-term notes receivable Accrued unbilled revenue Materials and fuel Prepayments and other current assets Total current assets Total assets 2007 3,479,754 962,290 4,443,792 979,960 9,865,796 (4,969,876) 4,895,920 773,694 18,311 235,163 5,923,088 668,710 116,339 1,117,142 228,181 84,710 296,053 8,434,223 448,817 196,959 237,946 282,897 31,778 147,335 118,349, 52,350 1,516,431 9,950,654 2006 3,444,102 906,848 4,288,601 948,407 9,587,958 (4,701,006) 4,886,952 570,418 14,578 237,403 5,709,351 955,340 116,367 1,144,941 99,793 8,025,792 315,298 731,205 73,509 280,723 32,887 140,386 112,107 33,948 1,720,063 9,745,855 14 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Balance Sheets June 30, 2007 and 2006 (Amounts in thousands)

Liabilities and Fund Net Assets Fund net assets:

Invested in capital assets, net of related debt Restricted:

Debt service Capital projects Other postemployment benefits Pension benefits Other purposes Unrestricted Total fund net assets Long-term debt, net of current portion Other noncurrent liabilities:

Accrued liabilities Deferred credits Net other postemployment benefit obligation Accrued workers' compensation claims Total other noncurrent liabilities Current liabilities:

Current portion of long-term debt Accounts payable and accrued expenses Accrued interest Accrued employee expenses Due to Water System Obligations under securities lending transactions Total current liabilities Total liabilities Total liabilities and fund net assets 2007 1,581,687 624,265 102,799 296,053 84,710 136,487 1,441,883 4,267,884 4,183,127 228,181 480,296 28,368 736,845 158,756 198,836 78,507 84,908 3,845 237,946 762,798 5,682,770 9,950,654 2006 1,774,252 600,750 97,017 231,496 99,793 129,304 1,178,955 4,111,567 4,261,748 564,164 110,823 35,558 710,545 188,821 223,434 80,249 82,575 13,407 73,509 661,995 5,634,288 9,745,855 See accompanying notes to financial statements.

15

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Statements of Revenues, Expenses, and Changes in Fund Net Assets Years ended June 30, 2007 and 2006 (Amounts in thousands)

Operating revenues:

Residential Commercial and industrial Sales for resale Other Uncollectible accounts 2007 817,642 1,643,077 102,983 45,519 (9,166) 2,600,055 545,221 699,841 751,587 269,587 Operating expenses:

Fuel for generation Purchased power Maintenance and other operating expenses Depreciation and amortization 2,266,236 Operating income 333,819 Nonoperating revenues (expenses):

Investment income Other nonoperating income Other nonoperating expenses Debt expenses:

Interest on debt Allowance for funds used during construction Income before capital contributions, transfers, and extraordinary item Capital contributions Transfers to the reserve fund of the City of Los Angeles Increase in fund net assets 152,936 20,556 173,492 (4,899) 168,593 (201,840) 10,773 (191,067) 311,345 19,719 (174,747) 156,317 4,111,567 4,267,884 2006 758,932 1,544,855 153,480 50,579 (11,457) 2,496,389 541,659 741,810 732,611 270,841 2,286,921 209,468 122,734 17,394 140,128 (4,246) 135,882 (170,839) 3,339 (167,500) 177,850 29,925

.(157,894) 49,881 4,061,686 4,111,567 Fund net assets:

Beginning lof year End of year See accompanying notes to financial statements.

16

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Statements of Cash Flows Years ended June 30, 2007 and 2006 (Amounts in thousands)

Cash flows from operating activities:

Cash receipts:

Cash receipts from customers Cash receipts from customers for othei agency services Cash receipts from interfund services provided Other cash receipts Cash disbursements:

Cash payments to employees Cash payments to suppliers Cash payments for interfund services used Cash payments to other agencies for fees collected Cash flows from noncapital financing activities:

Payments to the reserve fund of the City of Los Angeles Transfer of assets to the Retiree Health Benefits Fund Interest paid on noncapital revenue bonds Cash flows from capital and related financing activities:

Additions to plant and equipment, net Purchase of natural gas field Capital contributions Principal payments and maturities on long-term debi Proceeds from issuance of bonds and revenue certificates Debt interest payments Cash flows from investing activities:

Purchases of investment securities Sales and maturities of investment securities Purchase of long-term notes receivable Proceeds from notes receivable Investment income Net increase (decrease)

Cash and cash equivalents:

Cash and cash equivalents at July 1 (including $731,205 and $405,561 reported in restricted accounts, respectively)

Cash and cash equivalents at June 30 (including $196,959 and $731,205 reported in restricted accounts, respectively) 2007 2,464,217 379,152 308,898 17,074 (473,496)

(1,451,947)

(369,717)

(366,247) 507,934 (174,747)

(425,672)

(20,014)

(620,433)

(489,135) 22,937 (108,434)

(182,981)

(757,613)

(1,839,545) 2,126,176 32,887 149,867 469,385 (400,727) 2006 2,445,727 349,767 286,947 32,810 (431,114)

(1,462,463)

(342,519)

(319,998) 559,157 (157,894)

(17,060)

(174,954)

(465,831)

(230,190) 12,186 (172,600) 956,171 (133,831)

(34,095)

(2,122,855) 2,214,078 (92,385) 44,999 101,630 145,467 495,575 550,928 1,046,503 1,046,503 645,776 17 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Statements of Cash Flows Years ended June 30, 2007 and 2006 (Amounts in thousands)

Reconciliation of operating income to net cash provided by operating activities:

Operating income Adjustments to reconcile operating income to net cash provided by operating activities:

Depreciation and amortization Depletion expenses Amortization of nuclear fuel Provision for losses on customer and other accounts receivable Provision for obsolete inventory Changes in assets and liabilities:

Customer and other accounts receivable Accrued unbilled revenue Materials and fuel Deferred debits Net pension asset Accounts payable and accrued expenses Accrued liabilities Deferred credits Due to Water System Net other postemployment benefit liability Workers' compensation liability and othei Net cash provided by operating activities 2007 333,818 269,587 6,358 10,227 9,166 (15,441)

(6,949)

(6,242)

(228,181) 15,083 (24,598) 228,181 (83,868)

(9,562) 18,795 (8,440) 507,934 2006 209,468 270,841 5,200 12,939 11,457 11,500 (25,843)

(15,108)

(6,405) 14,728 63,427 (61,391)

(4,001) 39,655 32,690 559,157 See accompanying notes to financial statements.

18

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (1)

Summary of Significant Accounting Policies The City of Los Angeles' (the City) Department of Water and Power (the Department) exists as a separate proprietary department of the City under and by virtue of the City Charter enacted in 1925 and as revised effective July 2000. The Department's Power Revenue Fund (the Power System) is responsible for the generation, transmission, and distribution of electric power for sale in the City. The Power System is operated as an enterprise fund of the City.

(a)

Method ofAccounting The accounting records of the Power System are maintained in accordance with U.S. generally accepted accounting principles (GAAP) for governmental entities. The financial statements have been prepared using the economic resources measurement focus and the accrual basis of accounting.

Prior to fiscal year 2003, the Department applied all statements issued by the Governmental Accounting Standards Board (GASB) and all statements and interpretations issued by the Financial Accounting Standards Board (FASB), which are not in conflict with statements issued by GASB. In fiscal year 2003, the Department changed its election under the guidance in GASB Statement No. 20, Accounting and Financial Reporting for Proprietary Funds and Other Governmental Entities That Use Proprietary Fund Accounting (GASB No. 20), to follow all GASB statements and only FASB statements and interpretations issued on or before November 30, 1989.

The Department's rates are determined by the board of water and power commissioners (the Board) and are subject to review and approval by the City Council. As a regulated enterprise, the Department utilizes Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71), which requires that the effects of the rate-making process be recorded in the financial statements. Such effects primarily concern the time at which various items enter into the determination of changes in fund net assets. Accordingly, the Power System records various regulatory assets and liabilities to reflect the Board's actions.

Regulatory liabilities were recorded in. deferred credits and regulatory assets were included as deferred debits on the balance sheets. Management believes that the Power System meets the criteria for continued application of SFAS No. 71, but will continue to evaluate its applicability based on changes in the regulatory and competitive environment (see note 3 and 14(d)ii).

(b)

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

(c)

Utility Plant The costs of additions to utility plant and replacements of retired units of property are capitalized.

Costs include labor, materials, an allowance for funds used during construction (AFUDC), and allocated indirect charges, such as engineering, supervision, transportation and construction equipment, retirement plan contributions, healthcare costs, and certain administrative and general expenses. The costs of maintenance, repairs, and minor replacements are charged to the appropriate 19 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 operations and maintenance expense accounts. The original cost of property retired, net of removal and salvage costs, is charged to accumulated depreciation.

(d) Impairment of Long-Lived Assets The Department follows GASB Statement No. 42, Accounting and Financial Reporting for Impairment of Capital Assets and for Insurance Recoveries (GASB No. 42). Governments are required to evaluate prominent events or changes in circumstances affecting capital assets to determine whether impairment of a capital asset has occurred. A capital asset is considered impaired when its service utility has declined significantly and unexpectedly. Under GASB No. 42, impaired capital assets that will no longer be used by the government should be reported at the lower of carrying value or fair value. Impairment losses on capital assets that will continue to be used by the government should be measured using the method that best reflects the cause of the diminished service utility of the capital asset.

(e)

Depreciation and Amortization Depreciation expense is computed using the straight-line method based on service lives for all projects completed after July 1, 1973, and for all office and shop structures, related furniture and equipment, and transportation and construction equipment. Depreciation for facilities completed prior to July 1, 1973 is computed using the 5.0%/o sinking fund method based on estimated service lives. The Department uses the composite method of depreciation and, therefore, groups assets into composite groups for purposes of calculating depreciation expense. Estimated service lives range from 5 to 75 years. Amortization expense for computer software is computed using the straight-line method over 5 years. Depreciation and amortization expense as a percentage of average depreciable utility plant in service were 2.8% and 3.0% for fiscal years 2007 and 2006, respectively.

(f)

Nuclear Decommissioning The Department owns a 5.7% direct ownership interest in the Palo Verde Nuclear Generating Station (PVNGS). In addition, through its participation in the Southern California Public Power Authority (SCPPA), the Department is party to a contract for an additional 3.95% of the output of PVNGS.

Nuclear decommissioning costs associated with the Power System's output entitlement are included in purchased power expense (see note 6).

Decommissioning of PVNGS is expected, to commence subsequent to the year 2024. The total cost to decommission the Power System's direct ownership interest in PVNGS is estimated to be

$130 million in 2004 dollars. This estimate is based on an updated site-specific study prepared by an independent consultant in 2004. As of June 30, 2007 and 2006, the Power System has recorded

$122.4 million and $116.6 million, respectively, to accumulated depreciation to provide for the decommissioning liability.

Prior to December 1999, the Power System contributed $70.2 million to external trusts established in accordance with the PVNGS participation agreement and Nuclear Regulatory Commission requirements. During fiscal year 2000, the Department suspended contributing additional amounts to the trust funds, as management believes that contributions made, combined with reinvested earnings, 20 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 will be sufficient to fully fund the Department's share of decommissioning costs. The Department will continue to reinvest its investment income into the decommissioning trusts. The Department reinvested $5.8 million and $1.3 million of investment income in fiscal years 2007 and 2006, respectively. Decommissioning funds, which are included in restricted investments, totaled

$102.8 million and $97.0 million as of June 30, 2007 and 2006 (at fair value), respectively. The Department's current accounting policy recognizes any realized and unrealized investment earnings from nuclear decommissioning trust funds as a component of accumulated depreciation.

(g)

Nuclear Fuel Nuclear fuel is amortized and charged to fuel for generation on the basis of actual thermal energy produced relative to total thermal energy expected to be produced over the life of the fuel. Under the provisions of the Nuclear Waste Policy Act of 1982, the federal government assesses each utility with nuclear operations, including the Power System, $1 per megawatt hour of nuclear generation.

The Power System includes this charge as a current year expense in fuel for generation. See note 14 for discussion of spent nuclear fuel disposal.

(h)

Natural Gas Field In July 2005, the Power System acquired approximately a 74.5% ownership interest in gas properties located in Pinedale, Wyoming. The Power System uses the successful efforts method of accounting for its investment in gas producing properties. Costs to acquire the mineral interest in gas properties, to drill and equip exploratory wells that find proven reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proven reserves are expensed.

Capitalized costs of producing gas properties are depleted by the unit-of-production method based on the estimated future production of the proved developed producing wells.

Depletion expense related to the gas field is recorded as a component of fuel for generation expense.

During fiscal year 2007 and 2006, the Power System recorded $10.2 million and $12.9 million of depletion expense, respectively.

(i)

Cash and Cash Equivalents As provided for by the State of California Government Code (the Code), the Power System's cash is deposited with the City Treasurer in the City's general investment pool for the purpose of maximizing interest earnings through pooled investment activities. Cash and cash equivalents in the City's general investment pool are reported at fair value and changes in unrealized gains and losses are recorded in the statements of revenues, expenses, and changes in fund net assets. Interest earned on such pooled investments is allocated to the participating funds based on each fund's average daily cash balance during the allocation period. The City Treasurer invests available funds of the City and its independent operating departments on a combined basis. The Power System classifies all cash and cash equivalents that are restricted either by creditors, the Board, or by law, as restricted cash and cash equivalents on the balance sheets. The Department considers its portion of pooled investments with an original maturity of three months or less to be cash equivalents.

21 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 At June 30, 2007 and 2006, restricted cash and cash equivalents include the following (amounts in thousands):

June30 Bond redemption and interest funds Construction funds Self-insurance fund Other 2007 120,044 483 73,868 2,564 196,959 2006 149,308 515,471 63,862 2,564 731,205

(!')

Materials and Fuel Materials and supplies are recorded at average cost. Fuel is recorded at lower of cost or market, on an average-cost basis.

(k)

Accrued Unbilled Revenue Accrued unbilled revenue is the receivable for estimated energy sales during the period for which the customer has not been billed.

(1)

Restricted Investments Restricted investments include primarily commercial paper, U.S. government and governmental agency securities, and corporate bonds. Investments are reported at fair value and changes in unrealized gains and losses are recorded in the statements of revenues, expenses, and changes in fund net assets except for Nuclear Decommissioning Trust Funds. The stated fair value of investments is generally based on published market prices or quotations from major investment dealers (see note 7).

(in)

Accrued Employee Expenses Accrued employee expenses include accrued payroll and an estimated liability for vacation leave, sick leave, and compensatory time, which is accrued when employees earn the rights to the benefits.

Below is a schedule of accrued employee expenses as of June 30, 2007 and 2006 (amounts in thousands):

June 30 2007 2006 Type of expenses:

Accrued payroll Accrued vacation Accrued sick time Compensatory time Total 29,352 37,704 8,727 9,125 84,908 31,178 35,125 8,399 7,873 82,575 22 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (n)

Debt Expenses Debt premium, discount, and issue expenses are deferred and amortized to debt expense using the effective-interest method over the lives of the related debt issues. Gains and losses on refundings related to bonds redeemed by proceeds from the issuance of new bonds are amortized to interest on debt using the effective-interest method over the shorter of the life of the new bonds or the remaining term of the bonds refunded.

(o)

Gas and Electricity Option and Location Swap Agreements Gas and electricity option and location swap agreements were previously reported at fair value on the balance sheets. With the change in election under GASB No. 20, the Department now accounts for these contracts on a settlement basis (see note 9).

(p)

Accrued Workers' Compensation Claims Liabilities for unpaid workers' compensation claims are recorded at their present value when they are probable of occurrence and the amount can be reasonably estimated (see note 13).

(q)

Customer Deposits Customer deposits represent deposits collected from customers upon opening of new accounts. These deposits are obtained when the customer does not have a previously established credit history with the Department. Original deposits plus interest are paid to the customer once a satisfactory payment history is maintained, generally after one to three years. The Water System is responsible for collection, maintenance, and refunding of these deposits for all Department's customers, including those of the Power System. As such, the Water System's balance sheets include a deposit liability of

$80.0 million and $67.9 million as of June 30, 2007 and 2006, respectively, for all customer deposits collected. In the event that the Water System defaults on refunds of such deposits, the Power System would be required to pay amounts owing to its customers.

(r)

Revenues The Power System's rates are established by a rate ordinance, which is approved by the City Council. The Power System sells energy to the City's other departments at rates provided in the ordinance. The Power System recognizes energy costs in the period incurred and accrues for estimated energy sold but not yet billed.

Operating revenues are revenues generally derived from activities that are billable in accordance with the electric rate ordinance approved by the City Council.

(s)

Capital Contributions Capital contributions (formally referred to as contributions in aid of construction) and other grants received by the Department for constructing utility plant and other activities are recognized when all applicable eligibility requirements, including time requirements, are met.

23 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (t)

Allowance for Funds Used During Construction An AFUDC represents the cost of borrowed funds used for the construction of utility plant.

Capitalized AFUDC is included as part of the cost of utility plant and as a reduction of debt expenses. The average AFUDC rate was 4.6% for fiscal years 2007 and 2006.

(u)

Use of Restricted and Unrestricted Resources The Power System's policy is to use unrestricted resources prior to restricted resources to meet expenses to the extent that it is prudent from an operational perspective. Once it is not prudent, restricted resources will be utilized to meet intended obligations.

(v)

Reclassifications Certain financial statement items for 2006 have been reclassified to conform to the 2007 presentation.

(2)

Recent Accounting Pronouncements (a)

GASB Statement No. 49 In November 2006, the GASB issued Governmental Accounting Statement No. 49, Accounting and Financial Reporting for Pollution Remediation Obligations (GASB No. 49). This Statement addresses accounting and financial reporting standards for pollution (including contamination) remediation obligations, which are obligations to address the current or potential detrimental effects of existing pollution by participating in pollution remediation activities, such as site assessments and cleanups. The scope of the document excludes pollution prevention or control obligations with respect to current operations and future pollution remediation activities that are required upon retirement of an asset, such as landfill closure and postclosure care and nuclear power plant decommissioning. This statement is effective for the Department beginning in fiscal year 2009. The Department has not yet determined the financial statement impact of adopting this new statement.

(b)

GASB Statement No. 50 In May 2007, the GASB issued Governmental Accounting Statement No. 50, Pension Disclosures-an amendment to GASB Statement's No. 25 and No. 27 (GASB No. 50). This statement more closely aligns the financial reporting requirements for pensions with those for other postemployment benefits (OPEB) and, in doing so, enhances information disclosed in notes to the financial statements or presented as required supplementary information (RSI) by pension plans and by employers that provide pension benefits. The reporting changes required by this statement amend applicable note disclosure and RSI requirements of GASB Statements No. 25, Financial Reporting for Defined Benefit Pension Plans and Note Disclosures for Defined Contribution Plans, and No. 27, Accounting for Pensions by State and Local Governmental Employers, to conform to requirements of GASB Statements No. 43, Financial Reporting for Postemployment Benefit Plans Other Than Pension Plans, and No. 45, Accounting and, Financial Reporting by Employers for Postemployment Benefits Other Than Pensions. This statement is effective for the Department beginning fiscal year 2008. The Department does not expect that there will be a material impact to the financial statement disclosures as a result of adopting this statement.

24 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (c)

GASB Statement No. 51 In June 2007, the GASB issued Governmental Accounting Statement No. 51, Accounting and Financial Reporting for Intangible Assets (GASB No. 51). This statement establishes accounting and financial reporting standards for intangible assets. Intangible assets include, but are not limited to, easements, water rights, timber rights, patents, trademarks, and computer software. This statement is effective for the Department beginning fiscal year 2010. The Department has not yet determined the financial statement impact of adopting this new statement.

(3)

Regulatory Matters (a)

Federal Regulation of Transmission Access The Energy Policy Act of 1992 (the Energy Policy Act) made fundamental changes in the federal regulation of the electric utility industry, particularly in the area of transmission. As amended by the Energy Policy Act, Sections 211, 212, and 213 of the Federal Power Act (FPA) provide FERC authority, upon application by any electric utility, federal power marketing agency, or other person or entity generating electric energy for sale or resale, to require a transmitting utility to provide transmission services (including any enlargement of transmission capacity necessary to provide such services) to the applicant at rates, charges, terms, and conditions set by FERC based on standards and provisions in the FPA. Under the Energy Policy Act, electric utilities owned by municipalities and other public agencies, which own or operate electric power transmission facilities that are used for the sale of electric energy at wholesale are "transmitting utilities" subject to the requirements of Sections 211, 212, and 213.

FERC is encouraging the voluntary formation of regional transmission organizations (RTOs) independent from owners of generation and other market participants that will provide transmission access on a nondiscriminatory basis to buyers and sellers of power. Investor-Owned Utilities (IOUs) and publicly owned utilities are being encouraged to participate in the formation and operation of RTOs, but are not, at this time, being ordered by FERC to participate. FERC has adopted a "go slow" approach to the issue of RTO formation in the western United States; it is contemporaneously engaged in a wholesale overhaul of the California market design, referred to initially as the Market Design 2002 proceeding and more recently as the Market Redesign and Technology Update (MRTU) proceeding. These FERC proceedings will have potential impacts on every electric utility doing business in California. MRTU involves a comprehensive overhaul of the electricity markets administered by California Independent System Operator (CAISO),. including the areas of transmission congestion management, trading and scheduling energy in the day ahead, or spot market, improved market power mitigation, and pricing transparency measures and system improvements to increase operational efficiency and enhance reliability, among other things.

Currently, MRTU is scheduled to be implemented on March 31, 2008. It is not certain at this time what impact, if any, FERC's final decision on MRTU will have on the Power System. In addition, CAISO has announced its intention to implement further market changes over the next five years.

25 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (b)

Federal Energy Legislation On August 8, 2005, the Energy Policy Act of 2005 (the EP Act) was enacted, the first comprehensive energy legislation in over a decade. One of the most significant provisions of the EP Act repeals the Public Utility Holding Company Act of 1935 (PUHCA) six months after the effective date of the Act, on February 8, 2006. PUHCA prevented investment in the public utility sector by entities such as financial institutions and industrial companies and was a barrier to consolidation within the industry through its requirement that merged companies operate within a single region.

Another significant provision of the Act empowers FERC to certify an Electric Reliability Organization (ERO) to improve the reliability of the nation's "bulk-power system" through mandatory and enforceable electric reliability standards (in contrast to the current voluntary system).

The definition of "bulk-power system" does not include facilities used in the local distribution of electric energy. The ERO will file any proposed reliability standard or modification with FERC. A "reliability standard" is a requirement that provides for reliable operation of the bulk-power system.

Such a standard includes requirements for the operation of existing transmission facilities or the design of planned additions or modifications to the extent necessary to provide for reliable operation.

It does not include, and the ERO may not impose, any requirement to enlarge existing facilities or to construct new transmission or generation. All users, owners, and operators of the bulk-power system are required to comply with the electric reliability standards. The ERO may impose a penalty on a user, owner, or operator for violating a reliability standard, and FERC may order compliance with such a standard and impose a penalty if it finds that a user, owner, or operator is about to engage in an act that would violate a reliability standard.

The EP Act authorizes FERC to require nondiscriminatory access to transmission facilities owned by municipal, cooperative, and other. transmission companies not currently regulated by FERC, unless exercising this authority would violate a private activity bond rule for purposes of Section 141 of the Internal Revenue Code of 1986. FERC is prohibited from requiring any such entities to join RTOs.

The EP Act also allows FERC to issue permits for the construction of new transmission facilities when states have been unable or unwilling to act and allows load-serving entities to use the firm transmission rights, or equivalent tradable or financial transmission rights, in order to deliver output or purchased energy to the extent required to meet its service obligations. The EP Act does not relieve a load-serving entity from any obligation under state or local law to build transmission or distribution facilities adequate to meet its service obligations, or to abrogate preexisting firm transmission service contracts.

The EP Act directs FERC to establish, by rule, incentive-based rates for transmission no later than August 2006 and requires FERC to establish market transparency rules for the electric wholesale market (entities that have a de minimis market presence are exempt from the rules). The EP Act instructs that the market transparency rules must provide for the timely dissemination of information about the availability and prices of wholesale electric energy and transmission service to FERC, state commission, buyers and sellers of wholesale electric energy, users of transmission services, and the public. Within 180 days of the EP Act's enactment, FERC and the Commodity Futures Trading Commission are required to enter into a memorandum of understanding regarding information sharing pursuant to these rules.

26 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 In addition, the EP Act prohibits any person from willfully and knowingly reporting false information to any federal agency on the price of wholesale electricity or availability of transmission capacity, or using (directly or indirectly) any manipulative device in contravention of any FERC rule. The EP Act increases civil and criminal penalties, modifies the procedures for review of FERC orders under the FPA, and changes the refund date under the FPA to be effective as of the date an applicable complaint is filed. The EP Act also establishes an entity's right to a refund if (i) it makes a short-term sale of electric energy through an organized market in which the rates for the sale are set by a FERC-approved tariff (not by a contract) and (ii) the sale violates the terms of the tariff or applicable FERC rule in effect at the time of the sale.

The overall impact of the EP Act on the Department cannot be predicted at this time.

(4)

Utility Plant The Power System had the following activities in utility thousands):

plant during fiscal year 2007 (amounts in Nondepreciable utility plant:.

Land and land rights Construction work in progress Nuclear fuel Natural gas field Balance July 1, 2006 144,621 570,418 14,578 237,403 Total nondepreciable utility plant Depreciable utility plant:

Generation Transmission Distribution General Total depreciable utility plant Less accumulated depreciation:

Generation Transmission Distribution General Additions 126 247,773 10,091 7,987 265,977 32,752 52,434 120,410 30,886 Retirements and disposals (1,234)

(6,358)

(10,227)

(17,819)

(972)

(998)

(63)

(44,497)

Transfers Balance June 30, 2007 143,513 773,694 18,311 235,163 1,170,681 3,465,219 882,586 4,400,292 974,186 967,020 3,429,568 829,496 4,245,071 939,202 (44,497) 3,871 656 35,809 4,161 9,443,337 236,482 (2,033) 44,497 9,722,283 (1,934,917)

(357,062)

(1,784,373)

(624,654)

(115,268)

(19,596)

(110,416)

(25,623) 972 998 63 (2,049,213)

(376,658)

(1,893,791)

(650,214)

Total accumulated depreciation Total utility plant, net (4,701,006)

(270,903) 2,033 (4,969,876) 5,709,351 231,556 (17,819) 5,923,088 Depreciation and amortization expense during fiscal 2007 was $269.6 million.

27 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 The Power System had the following activities in utility plant during fiscal year 2006 (amounts in thousands):

Nondepreciable utility plant:

Land and land rights Construction work in progress Nuclear fuel Natural gas field Balance July 1, 2005 148,568 434,105 13,472 Additions 6,619 324,694 6,306 250,342 Retirements and disposals (10,566)

(5,200)

(12,939)

Transfers Balance June 30, 2006 144,621 (188,381) 570,418 14,578 237,403 Total nondepreciable utility plant Depreciable utility plant:

Generation Transmission Distribution General 596,145 587,961 (28,705)

(188,381) 967,020 3,376,741 792,262 4,070,937 971,216 27,926 797 78,343 35,831 (8,666)

(895)

(11,733)

(77,803) 33,567 37,332 107,524 9,958 3,429,568 829,496 4,245,071 939,202 Total depreciable utility plant 9,211,156 142,897 (99,097) 188,381 9,443,337 Less accumulated depreciation:

Generation Transmission Distribution General (1,835,185)

(340,535)

(1,676,710)

(655,900)

(107,409)

(16,806)

(109,044)

(35,537) 7,677 183 1,384 66,876 76,120 96 (3)

(93)

Total accumulated depreciation (1,934,917)

(357,062)

(1,784,373)

(624,654)

(4,701,006) 5,709,351 (4,508,330)

(268,796)

Total utility plant, net 5,298,971 462,062 (51,682)

Depreciation and amortization expense during fiscal 2006 was $270.8 million.

28 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (5)

Jointly Owned Utility Plant The Power System has direct interests in several electric generating stations and transmission systems, which are jointly owned with other utilities. As of June 30, 2007 and 2006, utility plant includes the following amounts related to the Power System's ownership interest in each jointly owned utility plant (amounts in thousands, except as indicated):

Utility plant in service Share of June 30, 2007 Ownership capacity Accumulated interest (MWs)

Cost depreciation Utility plant in service June 30, 2006 Accumulated Cost depreciation Palo Verde Nuclear Generating Station Navajo Generating Station Mohave Generating Station Pacific Intertie DC Transmission Line Other transmission systems 5.7%

224 21.2 477 10.0 40.0 1,240 Various 552,460 315,940 68,334 309,963 257,463 68,273 546,915 318,440 70,136 284,929 243,618 68,619 261,908 71,326 211,709 66,690 80,792 44,504 77,598 39,897 1,279,434 751,529 1,224,798 703,753 The Power System will incur certain minimal operating costs related to the jointly owned facilities, regardless of the amount or its ability to take delivery of its share of energy generated. The Power System's proportionate share of the operating costs of the joint plants is included in the corresponding categories of operating expenses.

(6)

Purchase Power Commitments The Power System has entered into a number of energy and transmission service contracts, which involve substantial commitments as follows (amounts in thousands, except as indicated):

Power System's interest in agency's share Agency Capacity Outstanding Agency share Interest (MWs) principal Intermountain Power Project Palo Verde Nuclear Generating Station Mead-Adelanto Project Mead-Phoenix Project Southern Transmission System IPA SCPPA SCPPA SCPPA SCPPA 100.0%

5.9 68.0 17.8-22.4 100.0 62.2%

67.0 36.0 25.0 60.0 1,091 1,343,535 151 291 148 1,142 76,189 77,952 17,072 520,399 IPA: The Intermountain Power Agency (IPA) is an agency of the state of Utah established to own, acquire,,

construct, operate, maintain, and repair the Intermountain Power Project (IPP). The Power System serves as the project manager and operating agent of IPP.

SCPPA: The Southern California Public Power Authority, a California Joint Powers Agency. SCPPA's interest in the Mead-Phoenix Project includes three components.

29 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 The above agreements require the Power System to make certain minimum payments, which are based primarily upon debt service requirements. In addition to average annual fixed charges of approximately

$309 million during each of the next five years, the Power System is required to pay for operating and maintenance costs related to actual deliveries of energy under these agreements (averaging approximately

$342 million annually during each of the next five years). The Power System made total payments under these agreements of approximately $497 million and $433 million in fiscal years 2007 and 2006, respectively. These agreements are scheduled to expire from 2027 to 2030.

The Power System earned fees under the IPP project manager and operating agent agreements totaling

$17.7 million and $16.9 million in fiscal years 2007 and 2006, respectively.

(a)

Long-Term Notes Receivable Under the terms of its purchase power agreement with IPA, the Department is charged for its output entitlements based on its share of IPA's costs, including debt service. During fiscal year 2000, the Department restructured a portion of this obligation by transferring $1.11 billion to IPA in exchange for long-term notes receivable. The funds transferred were obtained from the debt reduction trust funds and through the issuance of new variable rate debentures (see notes 7 and 10). IPA used the proceeds from these transactions to defease and to tender bonds with par values of approximately

$618 million and $611 million, respectively.

On September 7, 2000, the Department paid $187 million to IPA in exchange for additional long-term notes receivable. IPA used the proceeds to defease bonds with a face value of

$198 million.

On July 20, 2005, the Department paid $97 million to IPA in exchange for additional long-term notes receivable. IPA used the proceeds to defease bonds with a face value of $92 million.

The IPA notes are subordinate to all of IPA's publicly held debt obligations. The Power System's future payments to IPA will be partially offset by interest payments and principal maturities from the subordinated notes receivable. The net IPA notes receivable balance totaled $1.14 billion and

$1.17 billion as of June 30, 2007 and 2006, respectively.

(b)

Energy Entitlement The Department has a contract through 2017 with the U.S. Department of Energy for the purchase of available energy generated at the Hoover Power Plant. The Power System's share of capacity at Hoover is approximately 500 MWs. The cost of power purchased under this contract was

$15 million and $13 million in fiscal years 2007 and 2006, respectively.

30 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (7)

Cash, Cash Equivalents, and Investments (a)

Restricted and Other Investments A summary of the Power System's restricted and other thousands):

Restricted and other investments:

Restricted investments:

Debt reduction trust funds Postretirement healthcare benefit trust Nuclear decommissioning trust fund Natural gas trust fund SCPPA Palo Verde Investment Total restricted investments investments is as follows (amounts in June30 2007 2006 503,292 450,561 342,319 102,799 97,017 25,050 25,043 37,569 40,400 668,710 955,340 Other investments:

Cash collateral received from securities lending transactions - Department Program only*

(see note 8) 125,798 Total restricted and other investments 794,508 955,340 The Power System also has $112,148 and $73,509 of cash collateral received from securities lending transactions in the City's securities lending program as of June 30, 2007 and 2006, respectively (see notes 7(b) and 8).

All restricted and other investments are to be used for a designated purpose as follows:

Debt Reduction Trust Funds The debt reduction trust funds were established during fiscal year 1997 to provide for the payment of principal and interest on long-term debt obligations and purchased power obligations arising from the Department's participation in IPP and SCPPA (see note 6). The Department has transferred funds from purchased power precollections into these trust funds. Funds from operations may also be transferred by management as funds become available.

Postretirement Healthcare Benefit Trust Funds The postretirement healthcare benefit trust fund was established to provide for the payment of the Department's postretirement healthcare benefits. In fiscal 2007, the Department transferred the balance to the Retiree Health Benefits Fund, a fiduciary fund (see note 12).

31 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 Nuclear Decommissioning Trust Funds Nuclear decommissioning trust funds will be used to pay the Department's share of decommissioning PVNGS at the end of its useful life (see note 1).

Natural Gas Trust Fund The natural gas trust fund was established to serve as depository to pay for costs and to post margin or collateral in connection with contracts for the purchase and delivery of financial transactions for natural gas. These transactions are entered into to stabilize the natural gas portion of the Department's fuel for generation costs.

SCPPA Palo Verde Investment The SCPPA Palo Verde investment is a fixed rate investment held by SCPPA to be drawn down over the next 12 years to pay for purchased power obligations arising from the Department's participation in the SCPPA Palo Verde project.

As of June 30, 2007, the Power System's securities lending, cash collateral, and restricted investments and their maturities are as follows (in thousands):

I to 30 Type of investment Fair value days Investment maturitii 31 to 60 61 to 365 days days 366 days Over to 5 years 5 years U.S. agencies Medium-term notes Commercial paper Negotiable CDs Money market funds Securities lending cash collateral:

Repurchase agreements Commercial paper Money market funds SCPPA Palo Verde investment 384,820 147,227 54,027 42,446 2,621 85,000 39,927 871 29,161 20,337 19,789 2,621 85,000 37,937 871 31,080 9,256 9,935 12,450 1,990 91,442 71,318 24,302 29,996 200,869 46,317 32,268 37,569 37,569 S

794,508 233,285 64,711 217,058 247,186 32,268 32 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 As of June 30, 2006, the Power System's securities lending, cash collateral, and restricted investments and their maturities are as follows (in thousands):

Investment maturities I to 30 31 to 60 61 to 365 366 days Over Type of investment Fair value days days days to 5 years 5 years U.S. agencies 462,387 4,149 24,032 145,872 206,038 82,296 Medium-term notes 190,489 11,634 19,744 107,470 51,641 Commercial paper 158,070 121,009 27,168 9,893 Negotiable CDs 94,889 62,688 32,201 Money market funds 9,105 9,105 SCPPA Palo Verde investment 40,400 40,400 955,340 186,297 133,632 295,436 257,679 82,296 i

Interest Rate Risk The Department's investment policy limits the maturity of its investments to a maximum of 30 years for U.S. government agency securities; 5 years for medium-term corporate notes, 270 days for commercial paper; 397 days for negotiable certificates of deposits; and 45 days for repurchase agreements purchased with cash collateral from securities lending agreements.

ii. Credit Risk Under its investment policy and the Code, the Department is subject to the prudent investor standard of care in managing all aspects of its portfolios. The prudent investor standard requires that the Department "...shall act with care, skill, prudence, and diligence under the circumstances then prevailing, including, but not limited to, the general economic conditions and the anticipated needs of the agency, that a prudent person acting in a like capacity and familiarity with those matters would use in the conduct of funds of a like character and with like aims, to safeguard the principal and maintain the liquidity needs of the agency."

The U.S. government agency securities in the portfolio consist of securities issued by government-sponsored enterprises, which are not explicitly guaranteed by the U.S. government.

As of June 30, 2007 and 2006, the U.S. goverment agency securities in the portfolio carried the highest possible credit ratings by the Nationally Recognized Statistical Rating Organizations (NRSROs) that rated them.

The Department's investment policy specifies that medium-term corporate notes must be rated in a rating category of "A" or its equivalent or better by a NRSRO. Of the Power System's investments in corporate notes as of June 30, 2007, $24,409,663 (17%) was rated in the category of AAA, $93,307,449 (63%) was rated in the category of AA, and $29,510,044 (20%) was rated in the category of A by at least one NRSRO. Of the Power System's investments in corporate notes as of June 30, 2006, $3,385,560 (2%) was rated in the category of AAA, $129,933,595 (68%) was rated in the category of AA, and $57,170,056 (30%) was rated in the category of A by at least one NRSRO.

33 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 The Department's investment policy specifies that commercial paper must be of the highest ranking or of the highest letter and number rating as provided for by at least two NRSROs. As of June 30, 2007 and 2006, all of the Power System's investments in commercial paper were rated with at least the highest letter and number rating as provided by at least two NRSROs.

The Department's investment policy specifies that negotiable certificates of deposit must be of the highest ranking or letter and number rating as provided for by at least two NRSROs. As of June 30, 2007 and 2006, all of the Power System's investments in negotiable certificates of deposits were rated with at least the highest letter and number rating as provided by at least two NRSROs.

The Department's investment policy specifies that money market funds may be purchased as allowed under the Code, which requires that the fund must have either 1) attained the highest ranking or highest letter and numerical rating provided by not less than two NRSROs or

2) retained an investment advisor registered or exempt from registration with the Securities and Exchange Commission with not less than five years experience managing money market mutual funds with assets under management in excess of $500 million. As of June 30, 2007 and 2006, each of the money market funds in the portfolio had the highest possible ratings by three NRSROs, specifically AAAm by Standard and Poor's Corporation (S&P) and Aaa by Moody's Investors Service (Moody's), and AAA by Fitch Ratings (Fitch).

The Department's securities lending cash collateral investment policy specifies that repurchase agreement transactions shall be limited to broker/dealers or banks for which a securities lending line has been approved by the securities lending agent. Approved counterparties must be primary dealers in U.S. government securities that work directly with the Federal Reserve Bank of New York. Repurchase agreements must be adequately collateralized based on the margin requirements for the type of security listed in the investment policy. As of June 30, 2007, the counterparty to the repurchase agreement was an approved primary dealer rated with the highest short-term ratings as provided by two NRSROs. The collateral for the repurchase agreement consisted of mortgage-backed securities issued by U.S. government agencies that had minimum credit ratings of AAA with a margin of 102% of the repurchase agreements. As of June 30, 2006, the Power System. did not have any securities on loan under securities lending transactions and, therefore, had no related reinvestments of cash collateral.

The Department's securities lending cash collateral investment policy specifies that commercial paper must be of the highest ranking or of the highest letter and number rating as provided for by at least two NRSROs. As of June 30, 2007, all of the commercial paper purchased with cash collateral had the highest rating provided by two NRSROs.

The Department's securities lending cash collateral investment -policy specifies that money market funds may be purchased with cash collateral as allowed under the Code. As of June 30, 2007, the money market fund purchased with cash collateral was in compliance with the Code by having attained the highest possible ratings by three NRSROs, specifically AAAm by S&P, Aaa by Moody's, and AAA by Fitch.

34 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 iii. Concentration of Credit Risk The Department's investment policy specifies that there is no percentage limitation on the amount that can be invested in U.S. government agency securities, except that a maximum of 30% of the cost value of the portfolio may be invested in the securities of any single U.S.

government agency issuer.

Of the Power System's total investments as of June 30, 2007, $151,897,853 (20%) was invested in securities issued by the Federal National Mortgage Association; $141,413,981 (19%) was invested in securities issued by the Federal Home Loan Bank; and $84,244,675 (11%) was invested in securities issued by the Federal Home Loan Mortgage Corporation.

Of the Power System's total investments as of June 30, 2006, $148,351,195 (16%) was invested in securities issued by the Federal Home Loan Bank; $144,048,527 (16%) was invested in securities issued by the Federal Home Loan Mortgage Corporation; and $129,360,590 (14%)

was invested in securities issued by the Federal National Mortgage Association.

For overnight or open repurchase agreements, the Department's securities lending policy does not limit the percentage of cash collateral that may be invested with one particular counterparty.

Of the Power System's total investments as of June 30, 2007, cash collateral received from securities lending transactions of $85,000,000 (11%) was invested in an overnight repurchase agreement with Morgan Stanley and $8,000,000 (1%) was invested in commercial paper issued by Morgan Stanley for a total investment of $93,000,000 (12%) in securities issued by Morgan Stanley.

(b)

Pooled Investments The Power System's cash, cash equivalents and its collateral value of the City's securities lending program are included within the City Treasury's General and Special Investment Pool (Pool). As of June 30, 2007 and 2006, the Power System's share of the Pool was $757,924,000 and

$1,120,012,000, which represents approximately 10% and 15% of the Pool, respectively.

35 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 At June 30, 2007, the investments held in the City Treasury's General and Special Investment Pool Programs and their maturities are as follows (amounts in thousands):

1 to30 Type of investment Amount days Investment maturities 31 to 60 61 to 365 days days 366 days to 5 years 1,551,038 1,987,404 770,873 U.S. Treasury notes U.S. government agencies Medium-term notes Commercial paper Guaranteed investment contract State of California LAIF Short-term investment funds Securities lending cash collateral:

U.S. Treasury notes U.S. government agencies 1,651,432 2,588,342 1,135,468 900,606 314,860 2,664 7

270,397 811,138 314,860 2,664 7

63,258 54,758 100,394 267,283 364,595 34,710 898,087 5,386 217,385 892,701 217,385 5,419,401 Total general and special pools $

7,708,851 1,399,066 118,016 772,368 At June 30, 2006, the investments held in the City Treasury's General and Special Investment Pool Programs and their maturities are as follows (amounts in thousands):

Type of investment Amount 1 to 30 days Investment maturities 31 to 60 61 to 365 days days 366 days to 5 years U.S., Treasury notes U.S. Treasury bills U.S. government agencies Medium-term notes Commercial paper State of California LAIF Short-term investment funds Securities lending cash collateral:

U.S. Treasury notes U.S. agencies 750,633 7,193 3,483,994 1,077,004 1,298,356 2,204 13 607,597 344,340 7,193 229,854 1,173,459 2,204 13 259,964 52,464 750,633 519,398 2,474,778 125,689 951,315 72,433 607,597 344,340 Total general and special pools $

7,571,334 1,412,723 312,428 717,520 5,128,663

i.

Interest Rate Risk The City's investment policy limits the maturity of its investments to a maximum of five years for U.S. Treasury and federal agency securities, medium-term corporate notes, and bonds issued by local agencies; 270 days for commercial paper; and 92 days for repurchase agreements.

36 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 ii. Credit Risk As of June 30, 2007, the City's pooled investment policy requires that for all classes of investments, except linked banking program certificates of deposits, the issuers' minimum credit ratings shall be S&P A-i/A or Moody's P-1/A2; if available, Fitch IBCA Fl/A. In addition, domestic banks are limited to those with a current Fitch Ratings BankWatch of "B/C".or better and an A-i short-term rating. The City Treasurer is granted the authority to specify approved California banks with a Fitch Ratings BankWatch of "C" or better and an A-2 rating where appropriate. Foreign banks with domestic licensed offices must be rated AAA for country risk, "B" or better, and TBW-1 short-term rating by Fitch Ratings BankWatch. Domestic savings banks must be rated "B/C" or better and a TBW-I short-term rating by Fitch Ratings BankWatch.

Medium-term notes must be issued by corporations operating within the United States and having total assets in excess of $500 million. Commercial paper issuers must meet the preceding requirement or must be issued by corporations organized in the United States as a special purpose corporation, trust, or limited liability company having program-wide credit enhancements.

The City's $2.59 billion investments in U.S. government agencies consist of securities issued by government-sponsored enterprises, which are not explicitly guaranteed by the U.S. government.-

As of June 30, 2007; these securities carried the highest ratings of AAA (S&P) and Aaa (Moody's).

The City's $1.14 billion investments in medium term notes consist of securities issued by banks and corporations that comply with the requirements discussed above and were rated "A".or better by S&P and "A2" or better by Moody's.

The City's $900.6 million investments in commercial paper comply with the requirements discussed above and were rated A-I+/A-1 by S&P and P-1 by Moody's.

The issuers of the guaranteed investment contracts and the State of California Local Agency Investment Fund (LAIF) are not rated.

As of June 30, 2006, the City's pooled investment policy requires that for all classes of investments, except linked banking program certificates of deposits, the issuers must have minimum credit ratings as follows: S&P A-i/A; Moody's P-i/A2; Fitch, if available, F-i/A. The City's investments in medium-term notes were rated A+ or better by S&P and Ai or better by Moody's, while investments in commercial paper were rated A-I+/A-1 by S&P and P-1 by Moody's. As further required by the City's investment policy, issurers of medium-term notes are corporations that have total assets in excess of $500 million and are operating within the United States. In addition, issuers of commercial paper notes are corporations organized in the United States as special purpose corporations, trust or limited liability companies having program-wide credit enhancements. The State of California Local Agency Investment Fund is not rated.

iii. Concentration of Credit Risk 37 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 The City's investment policy does not allow more than 10% of its investment portfolio, except U.S. Treasury and federal agencies, to be invested in securities of a single issuer, including its related entities. The City's investment policy further provides for a maximum concentration limit of 30% on any individual federal agency or government-sponsored entity. The City's pooled investments comply with these requirements. GAAP requires disclosure of certain investments in any one issuer that represents 5% or more of total investments, the City does not have such investment as of June 30, 2007 or 2006.

(8)

Securities Lending Transactions The Power System participates in two securities lending programs as follows (collateral amounts in thousands):

June30 Program 2007 2006 Department Program 125,798 City of Los Angeles Program 112,148 73,509 237,946 73,509 Department Program In December 1999, the Department initiated a securities lending program managed by its custodial bank to increase interest income. The bank lends up to 20% of the investments held in the debt reduction trust funds, decommissioning trust funds, postretirement healthcare benefits trust for securities, cash collateral or letters of credit equal to 102% of the market value of the loaned securities, and interest, if any. The Department can sell securities received as collateral only in the event of borrower default. Both the investments purchased with the cash collateral received and the related liability to repay the cash collateral are reported on the balance sheets. A summary of the Power System's portion of the Department's securities lending program as of June 30, 2007 and 2006 is as follows (amounts in thousands):

June30 2007 2006 Fair value Fair value of of underlying Collateral underlying Collateral Securities lent for cash collateral securities value securities value U.S. government and agency securities 123,228 125,798 Cash collateral received is reinvested by the lending agent in open repurchase agreements. As such, the maturities of reinvested cash collateral always match the maturities of the underlying securities lent. The lending agent provides indemnification for borrower default. There were no violations of legal or contractual provisions and no borrower or lending agent default losses during fiscal years 2007 and 2006.

38 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 General Investment Pool Program The Power System also participates in the City's securities lending program through the pooled investment fund. The City's program has substantially the same terms as the Department's direct securities lending program. The Department recognizes its proportionate share of the cash collateral received for securities loaned and the related obligation for the general investment pool. As of June 30, 2007 and 2006, the Power System's attributed share of cash collateral and the related obligation from the City's program was

$112.1 million and $73.5 million, respectively.

Management believes that participation in these securities lending programs increases interest earnings and results in minimal credit risk exposure to the Department because the amounts owed to the borrowers exceed the amounts that have been loaned.

(9)

Derivative Instruments In accordance with GASB Technical Bulletin 03-01, the Power System does not record its derivative instruments on the balance sheets, but instead discloses the derivatives in the financial statement footnotes and records the impact upon settlement of the derivatives. The Power System had three main types of derivative instruments as of June 30, 2007 and 2006: electricity swaps, forward contracts, and financial natural gas hedges. As of June 30, 2007 and 2006, the fair values of these outstanding derivative instruments were $36.8 million and $85.9 million, respectively.

(a)

Objective of Electricity Swap and Options In order to obtain the highest market value on energy that is sold into the wholesale market, the Department monitors the sales price of energy, which varies based on which hub the energy is to be delivered. There are three primary hubs within the Department's transmission region: Palo Verde, California-Oregon Border, and Mead. The Department enters into various locational swap transactions with other electric utilities in order to effectively utilize its transmission capacity and to achieve the most economical exchange of energy purchased and sold.

A call option is the right, but not the obligation, to buy energy at a fixed price on or before a specific date. Because the Department has excess electric generation available at certain times during the year, it sells call options for a premium to other utilities. If the buyer calls the option, the Department is obligated to sell the energy for a specified dollar amount and deliver it to a specific delivery point.

If the buyer does not call the option, the Department has no obligation to deliver energy, but does retain the premium collected. Premiums received are deferred and amortized to income over the period the option is outstanding and are recorded as part of sales for resale revenue. As of June 30, 2007 and 2006, the Power System had no deferred option revenue relating to options entered into prior to the fiscal year-end.

The Department does not enter into forward and option agreements for trading purposes. The Department is exposed to risk of nonperformance if the counterparties default or if the swap agreements are terminated.

39 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (b)

Objective of Forward Contracts The Department enters into forward contracts in order to meet the electricity requirements to serve its customers.

(c)

Objective of Financial Natural Gas Hedges The Department enters into natural gas hedging contracts in order to stabilize the cost of gas needed to produce electricity to serve its customers.

As of June 30, 2007, the Power System had the following derivatives, which were not recorded on its balance sheet (amounts in thousands):

Derivative description Electricity swaps:

Purchases Sales Contract price Total range quantities

$ per unit First effective date Last termination date Cash received Fair at derivative value inception 123,200 MW 123,200 MW 62.00 10/01/07 12/31/07 65.50 10/01/07 12/31/07 83 338 Electricity options Forward contracts:

Electricity Natural gas Financial natural gas:

Hedges*

121,600MW 75.52-108.93 2,021,400 MW 75.25 - 84.75 310,000 MMBtu 3.43 77,610,500 MMBtu 4.30-7.50 07/01/07 09/01/07 07/01/07 12/31/11 07/01/07 07/31/07 07/01/07 06/01/11 (67) 426 (27) 166 36,348

• Financial hedges were variable to fixed rate swaps that serve to lock in a fixed cost or natural gas.

As of June 30, 2006, the Power System had the following derivatives, which were not recorded on its balance sheet (amounts in thousands):

Derivative Total' description quantities Contract price range

$ per unit 63.00 66.50 First effective date Last termination date Cash received Fair at derivative value inception (53) 478 Electricity swaps:

Purchases Sales Electricity options Financial natural gas:

Hedges*

121,600 MW 121,600 MW 30,800 MW 75.50 10/01/06 12/31/06 10/01/06 12/31/06 07/01/06 09/30/06 10/01/05 06/01/10 (55) 346 91,336,000 MMBtu 4.30-7.49 85,521

• Financial hedges were variable to fixed rate swaps that serve to lock in a fixed cost of natural gas.

40 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (d)

Fair Value All fair values were estimated using forward market prices available from broker quotes and exchanges.

(e)

Credit Risk The Power System is exposed to credit risk related to nonperformance by its wholesale counterparties under the terms of contractual agreements. In order to limit the risk of counterparty default, the Department has implemented a Wholesale Marketing Counterparty Evaluation Policy (the Policy). The Policy includes provisions to limit risk including: the assignment of internal credit ratings to all Department's counterparties based on counterparty and/or debt ratings; the requirement for credit enhancements (including irrevocable letters of credit, escrow trust accounts, and parent company guarantees) for counterparties that do not meet an acceptable level of risk; and the use of standardized agreements which allow for the netting of positive and negative exposures associated with a single counterparty.

As of June 30, 2007, the ten financial natural gas hedge counterparties were rated by Moody's as follows: two at Aaa, four at Aal, three at Aa3, and one at Al. The counterparties were rated by S&P as follows: two at AA+, four at AA, three at AA-, and one at A. As of June 30, 2006, the eight financial natural gas hedge counterparties were rated by Moody's as follows: three at Aal, two at Aaz and three at Aa3. The counterparties were rated by S&P as follows: two at AA+, one at AA, two at AA-and three at A+.

Based on the International Swap Dealers Association agreements, the Department obtains collateral to support derivatives subject to credit risk in the form of cash, negotiable debt instruments (other than interest only and principal-only securities) or eligible letters of credit. Collateral posted by a counter party is held by a custodian.

As discussed in note 14, during fiscal year 2001, the Power System experienced nonperformance and material counterparty default with the CAISO and the California Power Exchange (CPX). The Power System does not anticipate nonperformance by any other of its counterparties and has no reserves related to nonperformance at June 30, 2007 and 2006, respectively. Apart from the events discussed in note 14, the Power System did not experience any material counterparty default during fiscal years 2007 or 2006.

09 Basis Risk The Department mitigates basis risk through long-term physical transportation contracts.

(g)

Termination Risk The Power System or its counterparties may terminate the contractual agreements if the other party fails to perform under the terms of the contract. No termination events have occurred and there are no out-of-the-ordinary termination events contained in contractual documents.

41 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (10) Long-Term Debt Long-term debt outstanding as of June 30, 2007 and 2006 consists of revenue bonds and refunding revenue bonds due serially in varying annual amounts as follows (amounts in thousands):

Bond issues Issue of 2001, Series AI Issue of 2001, Series A2 Issue of 2001, Series B Issue of 2001, Series Cl Issue of 2002, Series A Issue of 2002, Series C2 Issue of 2003, Series Al Issue of 2003, Series A2 Issue of 2003, Series B Issue of 2004, Series C3 Issue of 2005, Series Al Issue of 2005, Series A2 Issue of 2006, Series C4 Date of issue 03/20/01 11/06/01 06/05/01 11/15/01 08/22/02 11/22/02 07/31/03 08/19/03 08/28/03 04/07/04 12/28/05 12/28/05 03/01/06 Effective interest rate 4.931%

5.109 Variable 4.788 Variable 4.375 3.409 4.662 5.013 4.298 4.700 4.700 4.040 Fiscal year of last scheduled Principal outstanding maturity 2007 2006 2025 2022 2035 2017 2036 2018 2017 2032 2036 2020 2041 2031 2017 993,895 109,095 580,800 3,211 388,500 11,544 385,670 515,830 200,000 11,899 616,895 315,195 8,526 4,141,060 1,023,800 109,095 620,600 4,543 388,500 11,846 422,380 515,830 200,000 12,192 616,895 315,195 8,618 4,249,494 200,000 1,075 (188,821)

Total principal amount Revenue certificates Unamortized premiums, discounts, and debt-related costs (including net loss on refundings), net Debt due within one year (including current portion of variable rate debt) 200,000 823 (158,756)

S 4,183,127 4,261,748 Revenue bonds generally are callable 10 years after issuance. The Department has agreed to certain covenants with respect to bonded indebtedness. Significant covenants include the requirement that the Power Systems' net income, as defined, will be sufficient to pay certain amounts of future annual bond interest and of future annual aggregate bond interest and principal maturities. Revenue bonds and refunding bonds are collateralized by the future revenues of the Power System.

42 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (a)

Long-Term Debt Activity The Power System had the following activity in long-term debt for the fiscal year ended June 30, 2007 and 2006 (amounts in thousands):

Long-term debt:

Bonds Revenue certificates Total Balance Julyl, 2006 4,250,569 200,000 4,450,569 Balance July 1, 2005 3,457,583 200,000 3,657,583 Additions Reductions Balance June 30, 2007 Current portion 138,756 20,000 (108,686) 4,141,883 200,000 (108,686) 4,341,883 158,756 Additions Reductions Balance June 30, 2006 Long-term debt:

Bonds Revenue certificates Total Current portion 168,821 20,000 188,821 966,155 966,155 (173,169) 4,250,569 200,000 (173,169) 4,450,569 (b)

New Issuances Fiscal Year 2006 In December 2005, the Power System issued $932 million of Power System Revenue Bonds. Also, in March 2006, the Power System issued $8.9 million of Mini-Bonds. The net proceeds from both transactions were deposited into the construction fund to be used for capital improvements.

(c)

Outstanding Debt Defeased The Power System defeased certain revenue bonds in prior years by placing cash or the proceeds of new revenue bonds in irrevocable trusts to provide for all future debt service payments on the old bonds. Accordingly, the trust account assets and the liability for the defeased bonds are not included in the Power System's financial statements.

In July 2005, the Power System defeased the $116.3 million Power System Revenue Bonds, Series A, Sub series A-3 with a carrying amount of $115.3 million by utilizing $110.7 million from the debt reduction trust fund to purchase securities placed in an irrevocable trust to provide for all future debt service on the bonds. The transaction resulted in a realized gain of $4.6 million that was netted against interest on debt.

43 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 At June 30, 2007, the following revenue bonds outstanding are considered defeased (amounts in thousands):

Principal Bond issues outstanding Issue of 1992 495 Second Issue of 1993.

8,855 Refunding Issue of 1994 41,365 Issue of 1994 5,950 56,665 (d)

Variable Rate Bonds and Revenue Certificates The variable rate bonds currently bear interest at daily and weekly rates (ranging from 3.70% to 3.87% as of June 30, 2007). The Power System can elect to change the interest rate period of the bonds with certain limitations. The bondholders have the right to tender the bonds to the tender agent on any business day with seven days' prior notice. The revenue certificates bear interest at an average rate of 3.66%. The Power System has entered into standby and line-of-credit agreements with a syndicate of commercial banks in an initial amount of $580.8 million, $388.5 million, and

$200 million to provide liquidity for the variable rate bonds and revenue certificates. The extended standby agreements expire in January 2010 for the $580.8 million issue and on July 11, 2008 for the

$388.5 million issue. The $200 million line-of-credit agreement for the revenue certificates expires in September 2010.

On April 2, 2007, the Power System refunded $39.8 million of Power System Revenue Bonds 2001, Series B.

Bonds purchased under the agreements will bear interest that is payable quarterly at the greater of the Federal Funds Rate plus 0.50% or the bank's announced base rate, as defined. The unpaid principal of bonds purchased is payable in ten equal semiannual installments, commencing after the termination of the agreement. At its discretion, the Power System has the ability to convert the outstanding bonds to fixed rate obligations, which cannot be tendered by the bondholders. These bonds have been classified as long-term on the balance sheets as the liquidity facilities give the Power System the ability to refinance on a long-term basis and the Power System intends to either renew the facility or exercise its right to tender the debt as a long-term financing. The portion that would be due in the next fiscal year in the event that the outstanding variable rate bonds were tendered and purchased by the commercial banks under the standby agreements have been included in the current portion of long-term debt and was $116.9 million and $120.9 million at June 30, 2007 and 2006, respectively.

44 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (e)

Scheduled Principal Maturities and Interest Scheduled annual principal maturities and interest are as follows (amounts in thousands):

Fiscal year(s) ending June 30:

2008 2009 2010 2011 2012 2013 -2017 2018-2022 2023 -2027 2028 -2032 2033 -2037 2038 -2042 Total requirements Principal 41,826 58,525 98,952 120,345 127,309 613,854 648,694 797,695 821,430 728,945 83,485 4,141,060 Interest and amortization 192,632 190,511 186,528 181,100 178,417 775,206 625,928 437,091 258,982 70,819 5,458 3,102,672 The maturity schedule presented above reflects the scheduled debt service requirements for all of the Power System's long-term debt. The schedule is presented assuming that the tender options on the variable rate bonds, as discussed on the previous page, will not be exercised and that the full amount of the revenue certificates will be renewed. Should the bondholders exercise the tender options and the Power System convert all of the revenue certificates under the line of credit, the Power System would be required to redeem the $1,169.3 million in variable rate bonds outstanding over the next six years, as follows: $116.93 million in fiscal year 2008, $233.86 million in each of the fiscal years 2009 through 2012, and $116.93 million in fiscal year 2013. Accordingly, the balance sheets include the possibility of the exercise of the tender options and reflect the $116.93 million that could be due in fiscal year 2007 as a current portion of long-term debt payable. Interest and amortization include interest requirements for variable rate bonds, using the variable debt interest rate in effect at June 30, 2007 of 3.87%.

(11)

Retirement, Disability, and Death Benefit Insurance Plan The Department has a funded contributory retirement, disability, and death benefit insurance plan covering substantially all of its employees. The Water and Power Employees' Retirement, Disability, and Death Benefit Insurance Plan (the Plan) operates as a single-employer defined benefit plan to provide pension benefits to eligible department employees and to provide disability and death benefits from the respective insurance funds. Plan benefits, are generally based on years of service, age at retirement, and the employee's highest 12 consecutive months of salary before retirement. Active participants who joined the Plan on or after June 1, 1984 are required to contribute 6.00% of their annual coveredpayroll. Participants who joined the Plan prior to June 1, 1984 contribute an amount based upon an entry-age percentage rate.

The Department contributes $1.10 for each $1.00 contributed by participants plus an actuarially determined 45 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 annual required contribution (ARC) as determined by the Plan's independent actuary. The required contributions are allocated between the Power System and the Water System based on the current year labor costs.

The Retirement Board of Administration (the Retirement Board) is the administrator of the Plan. The Plan is subject to provisions of the Charter of the City of Los Angeles and the regulations and instructions of the Board. The Plan is an independent pension trust fund of the City.

Plan amendments must be approved by both the Retirement Board and the Board. The Plan issues separately available financial statements on an annual basis. Such financial statements can be obtained from the Department of Water and Power Retirement Office, 111 N. Hope, Room 357, Los Angeles, California 90012.

The annual pension cost (APC) and net pension obligation (NPO) (asset) for the Department's Plan consists of the following (amounts in thousands):

Annual required contribution Interest on net pension asset Adjustment to annual required contribution APC (including $42.7 million and $36.2 million of amounts capitalized in fiscal years 2007 and 2006, respectively)

Department contributions Change in NPO NPO (asset) at beginning of year NPO (asset) at end of year Year ended June 30 2007 2006 141,464 118,342 (11,883)

(13,023) 17,707 19,405 147,288 (129,057) 18,231 (148,564)

(130,333) 124,724 (101,630) 23,094 (171,658)

(148,564) 46 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 The Power System's allocated share of APC and NPO consists of the following (amounts in thousands):

Annual required contribution Interest on net pension asset Adjustment to annual required contribution APC (including $26.3 million and $21.6 million of amounts capitalized in fiscal years 2007 and 2006, respectively)

Department contributions Change in NPO NPO (asset) at beginning of year NPO (asset) at end of year Year ended June 30 2007 2006 96,195 78,106 (8,080)

(8,595) 12,041 12,807 100,156 (85,073) 15,083 (99,793)

(84,710) 82,31,8 (67,590) 14,728 (114,521)

(99,793)

Annual required contributions are determined through actuarial valuations using the entry age normal actuarial cost method. The actuarial value of assets in excess of the Department's actuarial accrued liability (AAL) is being amortized by level contribution offsets over the period ended June 30, 2004. As a result of an April 2000 amendment to the Plan, the amortization period was changed to rolling 15-year 'periods effective July 1, 2000.

In accordance with actuarial valuations, the Department's required contribution rates are as follows:

Actuarial valuation date July 1 2006 2005 2004 Surplus Normal cost amortization 10.82%

10.58%

10.77 7.69 10.83 2.10 Contribution rate 22.25%

19.20 13.45 The significant actuarial assumptions include an investment rate of return of 8.0%, projected inflation-adjusted salary increases of 5.5%, and cost of living increases of 3.0%. The actuarial'value of assets is determined using techniques that smooth the effects of short-term volatility in the market value of investments over a four-year period. Plan assets consist primarily of corporate and government bonds, common stocks, mortgage-backed securities, and short-term investments.

47

'(Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 Trend information for fiscal years 2007,.2006, and 2005 for the Power System is as follows (amounts in thousands):

Percentage NPO of APC Year ended June 30 (asset) contributed APC 2007 (84,710) 85%

100,156 2006 (99,793) 82 82,318 2005 (114,521) 86 56,777 Disability and Death Benefits The Power System's allocated share of disability and death benefit plan costs and administrative expenses totaled $12 million and $9 million for fiscal years 2007 and 2006, respectively.

(12) Postretirement Healthcare Plan (a)

Plan Description The Department provides certain healthcare benefits to active and retired employees and their dependents. The healthcare plan is administered by the Department. The Retirement Board and the Board have the authority to approve provisions and obligations. Eligibility for benefits for retired employees is dependent on a combination of age and service of the participants pursuant to a predetermined formula. Any changes to these provisions must be approved by the Boards. The total number of active and retired department participants entitled to receive benefits was approximately 16,750 and 16,450 at June 30, 2007 and 2006, respectively.

The health plan is a single-employer defined benefit plan. During fiscal year 2007, the Retiree Health Benefits Fund was created to fund the post employment benefits of the Department. The fund is administered as a trust and has its own financial statements. Such financial statements can be obtained from the Department of Water Power Retirement Office, 111 N Hope, Room 357, Los Angeles, CA 90012.

(b)

Funding Policy The Department pays a monthly maximum subsidy of $1,090 for medical and dental premiums depending on the employee's work location and benefits earned. Participants choosing plans with a cost in excess of the subsidy they are entitled to are required to pay the difference.

No funding policy has been established for the future benefits to be provided under this plan.

However, in fiscal year 2007, the Department transferred $626,445,000 in investments and cash into the Retiree Health Benefits Fund and paid an additional $54,674,000 in retiree medical premiums.

Power System's portion of these amounts was $425,672,000 and $36,740,000, respectively.

48 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 Prior to the creation of the Retiree Health Benefits Fund, the Department held assets in an irrevocable trust with the intent to transfer the funds into a fiduciary fund that met the requirements of GASB No. 45 once it was created and approved by both boards.

Annual OPEB Cost and Net OPEB Obligation The annual other postemployment benefit (OPEB) cost (expense) is calculated based on the of the employer ARC, an amount actuarially determined in accordance with the parameters of GASB No. 45. The ARC represents a level of funding that, if paid on an ongoing basis, is projected to cover normal cost under each year and amortize any unfunded actuarial liabilities (or funding excess) over a period not to exceed 30 years.

The following table shows the components of the Department's annual OPEB cost for the year, the amount actually paid in premiums, and changes in the net OPEB (amounts in thousands):

Year ended June 30 Annual required contribution Interest on net OPEB obligation Adjustment to annual required contribution Contributions made Change in net OPEB obligation Net OPEB obligation - beginning of year Net OPEB obligation (asset) - end of year 2007 78,041 13,496 (9,867) 81,670 (681,119)

(599,449) 168,704 (430,745) 2006 110,813 7,094 (5,353) 112,554 (52,990) 59,564 109,140 168,704 49 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 The following table shows the components of the Power System's share in annual OPEB cost for the year, the amount actually contributed to the Plan, and changes in the net other postretirement obligation (amounts in thousands):

Annual required contribution Interest on net OPEB obligation Adjustment to annual required contribution Contributions made Change in net OPEB obligation Net OPEB obligation - beginning of year Net other post employment benefit obligation/(asset) -

end of year Year ended June 30 2007 2006 53,068 73,137 9,177 4,682 (6,709)

(3,533) 55,536 74,286 (462,412)

(406,876) 110,823 (296,053)

(34,631) 39,655 71,168 110,823 The Department's annual OPEB cost, the percentage of annual required contribution contributed to the Plan, and the net postretirement obligation for fiscal years 2007 and 2006 were as follows (amounts in thousands):

Annual OPEB cost Percentage of the ARC contributed Net postemployment obligation (asset) 2007 81,670 834%

(430,745) 2006 112,554 47%

168,704 2005 103,204 51%

109,140 The Power System's share in the annual OPEB cost, the percentage of annual required contribution contributed to the Plan, and the net retirement obligation for fiscal years 2007 and 2006 were as follows (amounts in thousands):

Annual OPEB cost Percentage of the ARC contributed Net postemployment obligation (asset) 2007 55,535 833%

(296,053) 2006 74,285 47%

110,823 2005 67,083 51%

71,168 50 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (c)

Funded Status and Funding Progress (Unaudited)

As of July 1, 2006, the Department's AAL for benefits was $1.1 billion resulting in an unfunded actuarial accrued liability (UAAL) of $1.1 billion. The covered payroll (annual payroll of active employees covered by the Plan) was $635.7 million, and the ratio of the UAAL to the covered payroll was 166%.

As of July 1, 2005, the Department's AAL for benefits was $1.7 billion resulting in an UAAL of

$1.7 billion. The covered payroll (annual payroll of active employees covered by the Plan) was

$612.3 million, and the ratio of the UAAL to the covered payroll was 277%.

Actuarial valuations of an ongoing plan involve estimates of the value of reported amounts and assumptions about the probability of occurrence of events far into the future. Examples include assumptions about future employment, mortality, and the healthcare cost trend. Amounts determined regarding the funded status of the Plan and the annual required contributions of the Department are subject to continual revision as actual results are compared with past expectations and new estimates are made for the future. The schedule of funding progress, presented as required supplementary information, presents information about whether the actuarial value of plan assets is increasing or decreasing over time relative to the AAL for benefits.

(d)

Actuarial Methods and Assumptions Projections of benefits for financial reporting purposes are based on the substantive plan (the Plan understood by the Department and the plan members) and include the types of benefits provided at the time of each valuation and the historical pattern of sharing of benefit costs between the Department and the plan members to that point. The actuarial methods and assumptions used include techniques that are designed to reduce the effects of short-term volatility in AAL and the actuarial value of assets, consistent with the long-term perspective of the calculations.

In the July 1, 2006 actuarial valuation, the entry-age normal cost method was used. The actuarial assumptions include 8.00% discount rate, which represents the expected long-term return on plan assets, an annual healthcare cost trend rate of 9.00% initially, reduced by decrements to an ultimate rate of 5.00% after eight years. Both rates include a 3.75% inflation assumption. The actuarial value of assets was determined using techniques that spread UAAL being amortized as a level percentage of projected payroll over a 29-year period.

In the' July 1, 2005 actuarial valuation, the entry-age normal cost method was used. The actuarial assumptions include 6.5% discount rate, which represents the expected long-term return on plan assets, an annual healthcare cost trend rate of 11.0% initially, reduced by decrements to an ultimate rate of 5.0% after seven years. Both rates include a 4.0% inflation assumption. The actuarial value of assets was determined using techniques that spread UAAL being amortized as a level percentage of projected payroll over a 30-year period.

51 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER

. POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 (13)

Other Long-Term Liabilities (a)

Other Long-Term Liabilities The Power System has the following other long-term liabilities:

Accrued liabilities Deferred credits:

Purchased power Public benefits Over (under) recovered costs Other Accrued workers' compensation claims

Balance, July 1, 2006 534,272 25,328 4,564 564,164 Additions 228,181 12,887 12,887 Reductions (76,643)

(19,382)

(730)

(96,755)

Balance, June 30, 2007 228,181 457,629 38,215 (19,382) 3,834 480,296 35,558 (7,190) 28,368 Deferred credits:

Purchased power Public benefits Other Accrued workers' compensation claims

Balance, July 1, 2005 612,828 12,727 625,555 Additions Reductions 12,601 4,564 17,165 (78,556)

(78,556)

Balance, June 30, 2006 534,272 25,328 4,564 564,164 35,558 35,558 No portion of these liabilities is automatically due within one year.

(b)

Accrued Liabilities In June 2007, a tentative decision was awarded to certain public entities against the Department that claimed they were charged more than their proportional share of the Department's capital costs in violation of Section 54999 of the code. The Department has accrued a liability as of June 30, 2007 relative to the court's tentative decision, but intends to vigorously contest this matter. As of June 30, 2007, the Department has accrued $228.2 million related to this matter. In addition, in the event the Department is unsuccessful in defending this claim, a long-term deferred debit for the same amount has been accrued since these costs will need to be recovered in the future. (See note 14(d)ii)).

52 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 Effective January 1, 2007, the California Legislature has amended Section 54999 of the code, et seq.

to clarify that, consistent with past practices, public agencies providing public utility service, such as the Department, may impose a reasonable fee, including a rate, charge, or other surcharge for any product, commodity, or service provided to a public agency and any public agency receiving service from such public agency providing public utility services will pay the imposed fee.

(c)

Deferred Credits The Department has deferred credits that are related to revenues collected from customers, but have not been fully earned. These funds are deferred and recognized as costs related to these deferrals are incurred.

Purchased Power Deferrals During fiscal year 2006, the Board approved the suspension of deferring precollected purchased power costs and the reversal of the precollected purchased power costs recorded in prior years. The amount reversed is the cost of energy from IPP less the amount designated in rates for out-of-market purchased power costs. The reversal of the deferred credit is credited to retail sales. During fiscal years 2007 and 2006, the Power System reversed $76.6 million and $78.5 million, respectively, related to precollected purchase power costs. At June 30,. 2007 and 2006, $457.6 million and

$534.3 million, respectively, remain as part of deferred credits related to precollected purchased power costs.

Public Benefits In accordance with Assembly Bill 1890, as amended by Assembly Bill 995 and pursuant to direction from the Board, a percentage of the Department's retail revenue is designated for use for qualifying public benefit programs. Qualifying programs include cost-effective demand side management services to promote energy efficiency and energy conservation, new investment in renewable energy resources and technologies, development and demonstration programs to advance science and technology, and services provided for low-income electricity customers. In accordance with current legislation and the Department's plans, the program is currently expected to cease on January 1, 2012.

The Department defers public benefits revenue from customers in excess of costs incurred under qualifying programs and defers qualifying expenses in excess of collections pursuant to approval received from the Board. During fiscal years 2007 and 2006, the Department spent $52.0 million and

$50.6 million, respectively, on public benefits programs. These programs include investments in electric buses and vehicles, photovoltaics or solar power and other alternative energy sources, and support for low-income and life support customers. As of June 30, 2007 and 2006, the Department has recorded a deferred credit in the amount of $38.2 million, and $25.3 million due to public benefit expenses below revenues. Regulatory liabilities are reduced when adequate public benefit expenses are incurred, and regulatory assets are recovered when the corresponding revenue is earned.

53 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 Over (Under) Recovered Costs Effective October 1, 2006, the Energy Cost Adjustment Factor (ECAF), which is a billing factor defined in the electric rate ordinance was unfrozen. This change allows the Power System to increase or decrease the factor on a quarterly basis incompliance with the ordinance. While this change allows the Power System to fully recover fuel costs, purchased power costs, and other costs outlined in the ordinance, the difference between the amount billed to customers and the value of the costs allowed to be recovered through the factor create an over or under recovered amount. Costs that are under recovered will be recovered in future periods. Amounts over recovered will be factored into future quarterly rates. As of June 30, 2007, the amount of under recovered costs was $19.4 million.

(d)

Accrued Workers' Compensation Claims Liabilities for unpaid workers' compensation claims are recorded at their present value when they are probable of occurrence and the amount can be reasonably estimated. The liability is actuarially determined, based on an estimate of the present value of the claims outstanding and an amount for claim events incurred but not reported based upon the Department's loss experience, less the amount of claims and settlements paid to date. The discount rate used to calculate this liability at its present value was 4% at June 30, 2007. The Department has third-party insurance coverage for workers' compensation claims in excess of $1 million.

Changes in the Department's liability since June 30, 2005 are summarized as follows (amounts in thousands):

June30 2007 2006 2005 Balance at beginning of year 61,173 63,785 55,990 Current year claims and changes in estimates 7,409 12,646 15,166 Payments applied (18,913)

(15,258)

(7,371)

Balance at end of year 49,669 61,173 63,785 The Power System's portion of the discounted reserves as of June 30, 2007 and 2006 are

$28.4 million and $35.6 million, respectively.

(14) Commitments and Contingencies (a)

Transfers to the Reserve Fund of the City of Los Angeles Under the provisions of the City Charter, the Power System transfers funds at its discretion to the reserve fund of the City. Pursuant to covenants contained in the bond indentures, the transfers may not be in excess.of the increase in fund net assets before transfers to the reserve fund of the City of the prior fiscal year. Such payments are not in lieu of taxes and are recorded as a transfer in the statement of revenues, expenses, and changes in fund net assets.

54 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 The Department authorized total transfers of $174.7 million and $157.9 million in fiscal years 2007 and 2006, respectively, from the Power System to the reserve fund of the City.

(b)

Palo Verde Nuclear Generating Station (PVNGS) Matters As a joint project participant in PVNGS, the Department has certain commitments with respect to nuclear spent fuel and waste disposal. Under the Nuclear Policy Act, the Department of Energy (the DOE) is to develop facilities necessary for the storage and disposal of spent fuel and to have the first such facility in operation by 1998; however, the DOE has announced that such a repository cannot be completed before 2010. There is an ongoing litigation with respect to the DOE's ability to accept spent nuclear fuel; however, no permanent resolution has been reached. Capacity in existing fuel storage pools at PVNGS was exhausted in 2003. A Dry Cask Storage Facility (also called the Independent Spent Fuel Storage Facility) was built and completed in 2003 at a total cost of

$33.9 million (about $3.3 million for the Department). The facility has the capacity to store all the spent fuel generated by the plant until the end of its life in 2026. The Department accrues for current nuclear fuel storage costs as a component of fuel expense as the fuel is burned. The Department's share of spent nuclear fuel costs related to its indirect interest in PVNGS is included in purchased power expense.

The Price-Anderson Act (the Act) requires that all utilities with nuclear generating facilities share in payment for claims resulting from a nuclear incident. Participants in PVNGS currently insure potential claims and liability through commercial insurance with a $300 million limit; the remainder of the potential liability is covered by the industry-wide retrospective assessment program provided under the Act. This program limits assessments to a maximum of $100.6 million for each licensee for each nuclear incident occurring at any nuclear reactor in the United States; payments under the program are limited to $10 million per incident, per year. Based on the Department's 5.70% direct interest and its 3.95% indirect investment interest through SCPPA, the Department would be responsible for a maximum assessment of $9 million per incident, limited to payments of $1 million per incident annually.

(c)

Environmental Matters Numerous environmental laws and regulations affect the Power System's facilities and operations.

The Department monitors its compliance with laws and regulations and reviews its remediation obligations on an ongoing basis. The following topics highlight some of the major environmental compliance issues affecting the Power System:

Air Quality - Nitrogen Oxide (NOx) Emissions The Power System's generating station facilities are subject to the Regional Clean Air Incentives Market (RECLAIM) NOx emission reduction program adopted by the South Coast Air Quality Management District (SCAQMD). In accordance with this program, SCAQMD established annual NOx allocations for NOx RECLAIM facilities based on historical emissions and type of emission sources operated. These allocations are in the form of RECLAIM trading emission credits (RTCs).

Facilities that exceed their allocations may buy RTCs from other companies that have emissions 55 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 below their allocations. The Department has a program of installing emission controls and purchasing RTCs, as necessary, to meet its emission requirements.

In May 2001, SCAQMD adopted amendments to RECLAIM, with the intent of lowering and stabilizing RTC prices. One key element of the amendments is that existing power plants were bifurcated from the rest of the RECLAIM market and were required to install Best Available Retrofit Control Technology (BARCT). As required under SCAQMD rules, the Department met the BARCT compliance date of January 1, 2003. In January 1, 2007, power producers can reenter the RECLAIM market. As a result of the installation of NOx control equipment and the repowering of existing units, the Department has sufficient RTCs to meet its native load requirements for normal operations until 2010. For future years, the Department may neeld to acquire additional RTCs.

Air Quality - Greenhouse Gas Emissions In September, Governor Schwarzenegger signed the California Global Warming Solutions Act of 2006 (AB32). The bill requires the California Air Resources Board to develop regulations and market mechanisms that will ultimately reduce California's greenhouse gas emissions by 25% by 2020. Mandatory caps will begin in 2012 for significant sources and be gradually reduced to meet the 2020 goals. As specified in the bill, all emissions from electricity that is consumed in the state, whether it is generated in California or in other states, will be subject to the cap. As a result, the Power System's share of emissions from IPP and other facilities outside California will be subject to this program.

It is uncertain at this time what impact this statute will have on the Power System's operations. If a cap and trade program is established, the primary issue will be how allowances will be allocated.to the Department and other power producers. The target date for the Air Resources Board to adopt regulations is January 1, 2011. The goal of the regulations would be to "achieve the maximum technologically feasible and cost-effective reductions in greenhouse gas, including provisions for using both market mechanisms and alternative compliance mechanisms." The Department will be actively participating in the rule-making process.

Power Plant Once-Through Cooling Water Systems Once-through cooling is the process where water is drawn from a source, pumped through equipment to provide cooling, and then discharged. Some type of cooling process is necessary for nearly every type of traditional electrical generating station, and the once-through cooling process is utilized by many electrical generating stations located next to large bodies of water. Typically, the water used for cooling is not chemically changed in the process although its temperature is increased.

In the past year, due to the Second Circuit Court's decision to remand most of Environmental Protection Agency's (EPA) new 316(b) Rule, EPA suspended its new 316(b) Rule. In the absence of EPA's 316(b) Rule, the California State Water Resources Control Board has decided to move forward and is in the process of developing their State-Wide Once Through Cooling Policy. In addition, other regulatory changes have been made that could significantly impact operations at the Haynes, Scattergood, and Harbor Generating Stations. The Regional Water Quality Control Board reclassified the body of water that the once-through cooling water is discharged to for the Harbor 56 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 Generating Station, and sent a letter of intent to reclassify the body of water for the Haynes Generating Station discharge. Should there be a reclassification for the water body discharges at the Haynes Generating Station, there will be requirements that cannot be met with its existing cooling configuration. The Department is in the process of reviewing the regulations and conducting studies.

Once the studies are reviewed, the Department will determine an appropriate course of action.

(d)

Litigation

i.

California Receivables and Refund Hearings During fiscal year 2001, the Power System made sales to two California agencies that were formed by Assembly Bill 1890 to facilitate the purchase and sale of energy and ancillary services in the State of California. Through June 30, 2007, these agencies, the CAISO, and the CPX, have made minimal payments since April 2001 on amounts outstanding to counterparties, including the Power System, for certain energy purchases in fiscal years 2000 and 2001. The CPX filed for protection under Chapter 11 of the Federal Bankruptcy Statute in January 2001. Two utilities with significant amounts due to these agencies* have paid all amounts due to the CPX; however, the amounts remain in an escrow account pending the resolution of disbursement of the funds.

As of June 30, 2007 and 2006, a total of $166.5 million was due to the Power System from the CAISO and the CPX. Claims have been filed questioning whether amounts charged for energy sold to the CAISO and the CPX during 2000 and 2001 represent "unlawful profits" that should be subject to refund. The Courts have opined that FERC has no jurisdiction over the Department; however, the Courts have stated that the California parties seeking the refund may have a cause of action. As such, the litigation in this area is continuing.

The Power System has recorded a $50.0 million liability as of June 30, 2007 and 2006 against the $166.5 million receivable, for potential refunds pertaining to its wholesale sales during 2000 and 2001. Management believes that this is the most probable amount that will be refunded by the Power System and is based on the most recent formula disclosed by FERC.

While management has recorded its estimate of the most probable amounts that will be refunded, management does believe that it is entitled to all amounts due from sales to counterparties in California, including those named above. Furthermore, management believes that interest may be due to it on those amounts but any potential receivable is not estimable at this time. In addition, management does not believe that the Power System's exposure to any additional losses with respect to these receivable balances is currently estimable. If final settlement of these receivables results in an amount less than the recorded balance, net of the

$50.0 million liability recorded, the Department will be required to record a loss in future periods.

57 (Continued)

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Notes to Financial Statements June 30, 2007 and 2006 ii.

Capital Facilities Fee Claims In June 2007, the Department received a tentative decision in favor of the state and a number of local government agencies that are electric customers of the Department that claimed that the Department has rates that include a capital facilities' charge that violates the state's statute.

The Department intends to vigorously defend the claim. However, a long-term liability related to the tentative decision has been accrued in the event that the Department is not successful in defending this claim. Additionally, as permitted by SFAS No. 71; the Board approved to defer all potential costs associated with the resolution of this litigation and establish a corresponding long-term deferred debit to be recovered through future revenues over a period of up to ten years, if necessary. (See note 13b).

iii.

Other A number of claims and suits are also pending against the Department for alleged damages to persons and property and for other alleged liabilities arising out of its operations. In the opinion of management, any ultimate liability, which may arise from these actions, is not expected to materially impact the Power System's financial position, results of operations, or cash flows as of June 30, 2007.

(e)

Risk Management The Power System is subject to certain business risks common to the utility industry. The majority of these risks are mitigated by external insurance coverage obtained by the Power System. For other significant business risks, however, the Power System has elected to self-insure. Management believes that exposure to loss arising out of self-insured business risks will not materially impact the Power System's financial position, results of operations, or cash flows as of June 30, 2007.

09 Credit Risk Financial instruments, which potentially expose the Department to concentrations of credit risk, consist primarily of retail and wholesale receivables. The Department's retail customer base is concentrated among commercial, industrial, residential, and governmental customers located within the City. Although the Department is directly affected by the City's economy, management does not believe significant credit risk exists at June 30, 2007, except as provided in the allowance for losses.

The Department manages its credit' exposure by requiring credit enhancements from certain customers and through procedures designed to identify and monitor credit risk.

(15)

Subsequent Event On October 2, 2007, the Board approved an electric base rate increase of 2.9% effective January 1, 2008, 2.9% effective July 1, 2008, and 2.7% effective July 1, 2009. This increase is required to fund costs related to general inflation and Power System's reliability improvements. City Council's approval by ordinance is required.

58

LOS ANGELES DEPARTMENT OF WATER AND POWER POWER SYSTEM Required Supplementary Information June 30, 2007 (Unaudited)

Pension Plan - Schedule of Funding Progress The following schedule provides information about the Department's overall progress made in accumulating sufficient assets to pay benefits when due, prior to allocations to the Water System and the Power System (amounts in thousands):

Actuarial Actuarial valuation value date July 1 of assets Actuarial accrued liability (AAL) 7,046,571 6,763,080 6,421,814 Unfunded AAL (UAAL) 598,808 432,032 170,393 Funded Covered ratio payroll 92% $

635,728 94 616,270 97 581,039 UAAL as a percentage of covered payroll 94%

70 29 2006 2005 2004 6,447,763 6,331,048 6,251,421 Postemployment Healthcare Plan - Schedule of Funding Progress The following schedule provides information about the Department's overall progress made in accumulating sufficient assets to pay benefits when due, prior to allocations to the Water System and the Power System (amounts in thousands):

Actuarial Actuarial valuation value date July 1 of assets Actuarial accrued liability (AAL)

Unfunded AAL (UAAL) 1,053,853 1,695,666 1,597,835 Funded Covered ratio payroll 635,700 612,270 628,898 UAAL as a percentage of covered payroll 166%

277 254 2006 2005 2004 1,053,853 1,695,666 1,597,835 See accompanying independent auditors' report.

59

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ABOU7Y SR Salt River Project (SRP) provides reliable, reasonably priced electricity to more than 2 million people living in central Arizona, one of the fastest-growing areas of the country.

As one of the nation's largest integrated public power utilities, we provide generation, transmission and distribution services to about 930,000 homes and businesses in our service area. We also are the greater Phoenix metropolitan area's largest water supplier, with a service area covering more than 375 square miles and management responsibilities for a 13,000-square-mile watershed.

SRP has more than a century of experience at anticipating, planning and executing strategies to make the most of Arizona's precious resources to meet the needs of our power customers and water shareholders.

To learn more about SRP and our right ideas for power customers, water shareholders, the environment and our communities, visit our Web site at www.srpnet.com.

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CON7EN5 Letter to Electric Customers, Water Shareholders and Bondholders 2

Letter from the General Manager..................

4 P o w e r..................................................

6 W a te r..................................................

8 En viro n m e nta l......................

10 C o m m u n ity.........................................

.. 1 2 Management's Financial and Operational Summary 14 Combined Financial Statements....

I.........

18 Notes to Combined Financial Statem ents.................................

22 Report of Independent Auditors....................

51 Boards and C ouncils.........

52 Corporate Inform ation..............................

54 The entire SRP 2008 Annual Report is available at www.srpnet.com/annualreport along with additional information found on key links provided in each section.

f LETTER TO ELECTRIC CUSTOMERS, WATER SHAREHOLDERS AND BONDHOLDERS I

Meeting the needs of our electric customers and water shareholders is always the right idea for SRP. For more than a century we have dedicated ourselves to providing reliable, reasonably priced water and power services that make it possible for people, businesses and communities to thrive in Arizona.

from 62 percent at the end of FY07. Like all Arizonans, we welcomed this break in the longest dry spell of our lifetimes.

But because there is no way to predict how much rain will fall this year, or in any future year for that matter, we continue to manage our water resources as if this were the first year of another prolonged drought.

Despite slower economic growth in our service area and rising fuel costs, SRP again delivered strong operational and financial performance in fiscal year 2008 (FY08).

Most of this we credit to a robust strategic planning process and the fact that we have a strong team of managers and employees with the experience and discipline to execute our plans.

The whole purpose of our extensive water infrastructure is to store water from wetter years to sustain us in the long dry periods that are a way of life here in the desert. Proactive water management is more important than ever to meet the needs of our growing communities and protect the rights of our water shareholders.

Winter rains provided welcome relief during the 13 th year of a record drought. Our reservoir storage system was at 98 percent of capacity on April 30, 2008, much improved SRP helped negotiate the largest-ever Indian water rights settlement, which was signed in December 2007 by the U.S. Department of the Interior. The historic agreement ended more than 30 years of uncertainty for SRP water shareholders by assigning specific water rights to the Gila River Indian Community.

2 SRP 2008 ANNUAL REPORT

We added about 9,600 new electric customers last fiscal year, an increase of 1 percent, despite a slower economy and sluggish housing market. Total demand grew 4.8 percent. SRP serves one of the fastest-growing parts of the country, challenging us to come up with the best energy ideas to meet our customers' needs today and in the years ahead.

SRP has invested almost $3.9 billion in capital expansion and improvement projects over the last six years. We have improved the efficiency of our conventional generating capabilities while building and strengthening our alternative energy portfolio.

We established an Electric Reliability Compliance department to strengthen our focus on reliability, which always has been an SRP strong suit. For years we have participated in voluntary reliability audits and last fall took part in readiness and compliance audits that are now mandated by federal regulators.

The preliminary results were good overall and we carefully will examine the final report to find improvement opportunities. The equivalent availability of SRP-operated generating resources averaged more than 96 percent for the year, which compares very favorably to industry benchmarks.

The same trends that are driving up prices for all of us at the gasoline pump affect fuel and purchased power costs for SRP. In fact, like oil prices, coal and natural gas prices are at or near all-time highs. We added $30 million to the SRP Rate Stabilization Fund in July 2007 to offset a portion of these significantly higher costs for customers. We made fuel adjustment price increases in November 2007 (4.7 percent) and May 2008 (2.1 percent) and a base price increase of 1.8 percent in May 2008 to support our capital expansion program.

SRP continues to lead the industry in applying technology and introducing pricing plans that help our customers manage energy use. This year we enhanced our program for customers in crisis who need help paying their bills, introduced new pricing plans to promote energy conservation and installed the 270,000th "smart" meter in our service area.

In FY08, our combined net revenues exceeded $257 million on total operating revenues of $2.7 billion. Consistent financial performance helped us earn the highest credit ratings available to public power utilities. It is a tribute to the respect SRP has earned in the financial community that the orders we received during our March 2008 revenue bond offering far exceeded the

$817 million in Electric System Revenue Bonds authorized by the SRP Board and Council.

SRP's long record of leadership in the energy industry and in our communities was recognized in the last year. In April 2008, John Williams was appointed to the U.S. Department of Homeland Security's National Infrastructure Advisory Council. On behalf of SRP employees, David Rousseau accepted the Excellence in Workplace Volunteer Programs Award from the Points of Light Foundation in July 2007.

For the seventh consecutive year J.D. Power and Associates recognized SRP for outstanding residential customer satisfaction, ranking us as the top electricity provider in the Western U.S. SRP placed first among large electric utilities in the American Public Power Association (APPA) 2007 Safety Contest, which recognizes utilities with safe working environments.

As we begin our third year as SRP's president and vice president, we want to thank the employees, management and elected officials of SRP for their foresight, leadership and commitment. They are the source of our success and one of the primary reasons for our confidence in the future.

JohnM.Williams Jr.

President David Rousseau Vice President SRP 2008 ANNUAL REPORT 3

This past year SRP continued to outperform expectations.

While customer growth fell off due to the sluggish economy, financial results exceeded budget.

Extensive precipitation on the watershed filled our reservoirs, and while only time will tell if the drought has ended, we once again are positioned to provide adequate supplies to our water shareholders. Although Central Arizona Project water is not currently needed, the knowledge that it could be available complements our planning for future shortages.

Water stewardship, core to our mission, has remained front and center as we continue to pursue resolution of conflicting claims to water rights on the SRP watershed. We focused our efforts this past year on resolving claims of the White Mountain Apache Tribe, providing water to the town of Payson from Cragin Reservoir, and engaging communities on the Verde River watershed in discussions to end infringements on rights of our shareholders.

We continued discussions with Valley cities on a drought protection plan that will increase groundwater pumping capability by co-locating new wells and refurbishing existing wells. Additionally, we are concerned with what water sources might be available to provide for growth areas outside SRP's traditional water service area, but within the electric service territory boundaries.

Compliance with federal laws and implementing regulations has become business as usual as national energy policy has become institutionalized. State regulatory policy dealing with possible resumption of competition remains unresolved.

While electric customer growth was tempered by the economic downturn in the greater Phoenix metropolitan area, we

{LETTER FROM THE GENERAL MANAGER continued to prepare for the resumption of sustained growth.

The interruption in historic growth provided an opportunity to catch our breath in advance of the inevitable turnaround.

Infrastructure additions continue. Our primary focus has been completion of construction of Unit 4 at Tucson Electric Power Company's Springerville Generating Station in eastern Arizona.

Unit 4 is being constructed on an aggressive schedule, with commercial operation scheduled the end of 2009. Major extra-high-voltage transmission line construction continues, as does the construction of numerous miles of sub-transmission and substation expansions.

We have identified the need for 2,500 megawatts of new intermediate and peaking generation by the year 2020. A portion will be provided under a long-term purchased power contract. Also, we are exploring the purchase of existing generation, and have undertaken the identification of several new generating sites.

With respect to new base load generation, the issue of global climate change and the contribution of greenhouse gases from fossil fuel generation have placed increased emphasis on the development of technologies to capture and sequester carbon dioxide emissions. SRP is participating in these efforts but recognizes the challenges in developing timely and economic solutions. We are actively engaged in national and regional debates about legal, regulatory and policy options.

During the past year a number of utilities announced plans for new nuclear generating units. We continue to monitor these activities, but are concerned with the escalating costs.of new units, the uncertainty of regulatory actions, and the lack of clear policy direction for spent fuel management.

This past year we began a program outside SRP's traditional water service area to determine if a representative group of electric customers would be helpful in resolving issues such as those arising in pricing proceedings and the location of new infrastructure. The two-year pilot program initiated by management is entering the next phase of issue engagement.

While growth in SRP's electric service territory, located in substantial part in the greater Phoenix metropolitan area, has declined, it is expected to resume in 2010. Current trends indicate 2 percent growth in the coming year.

4 SRP 2008 ANNUAL REPORT

Last year's challenges in keeping up with installation design requests by new customers, particularly commercial customers, have been resolved. Special efforts during the fiscal year were successful, helped in large part by the drop off in growth.

Volatile pricing of natural gas, the fuel used in local generating plants, continues to be the most significant expense of electricity production. While fuel hedging has worked well in mitigating impacts on customers, pricing adjustments to reflect such volatility continue. We are pleased that SRP completed a unique natural gas financing technique that will assist in lowering customer costs.

Standard electric pricing plan design changes have been put in place which are intended to better reflect cost patterns during summer peak usage. Two design changes to basic pricing plans include introduction of July-August peak period pricing, and higher pricing for monthly usage in excess of 2,000 kilowatt-hours during the six-month summer billing period. We expect customers to alter their consumption patterns in response to these changes. Special efforts have been taken to inform customers of these significant design changes.

A complementary activity to the pricing design changes has been a significant effort to enhance energy-efficiency programs offered to our customers. We have undertaken a comprehensive customer education program, employing numerous print and electronic communications to deliver timely energy-saving information to our customers. We have enhanced existing residential and commercial programs, and added new programs to provide customers with incentives for the purchase of energy-efficient equipment and products. Our program offerings will continue to expand next year.

In addition to pricing and energy-efficiency initiatives, we continue to expand our renewable portfolio. A new biomass plant began operation. Contracts for additional geothermal resources in New Mexico were finalized. Substantial progress has been made to bring new solar and wind installations to Arizona. We also expanded incentives for solar in residential and commercial installations.

SRP's award-winning customer service programs continue to expand and incorporate new value-added elements.

More than 55,000 customers now participate in SRP's voluntary M-Power program, the largest prepayment program for electricity service in North America. With the aid of an in-home display which shows real-time power usage, these customers are able to trim their power consumption by 12 percent, on average. Customers may purchase power from SRP-designed kiosks at 51 locations in our service territory. Our M-Power program attracted national attention and top accolades from the National Energy Resources Organization.

Over 190,000 residential customers participate in SRP's voluntary time-of-use pricing plan, making the program the second largest time-of-use initiative in the nation. Typical customers on this program trim their electric bills 7 percent by restricting the use of power over peak periods, helping SRP to manage peak loads.

Almost 300,000 customers are now served by "smart" meters. A smart meter is a technologically sophisticated meter capable of two-way telecommunication with the utility and with the potential to manage certain electrical loads within the home. Customers with smart meters now are able to view their prior day's usage on the Web and to receive periodic e-mails and/or text messages projecting their monthly electric bills based on month-to-date electricity consumption. Our plan is to equip every customer with a smart meter over the next several years.

Customers' perceptions of SRP have continued to be strong as reported in surveys conducted by J.D. Power and Associates. SRP has received the highest score for residential customer satisfaction in the West in nine of the last ten years. SRP has received the highest scores for business customer satisfaction in three of the five years that the survey has been performed.

We recognize the importance of effectively managing personnel changes resulting from the challenges of an aging workforce. Rotational programs, increased apprenticeship opportunities, mentoring, and development initiatives continue as top priorities. These efforts are among various programs that will position SRP for continued success.

In conclusion, the SRP workforce, in what is becoming an increasingly challenging environment, continues to deserve full credit for the fiscal year's successes. SRP's elected officials, in partnership with management, have provided the foundation for continued growth and ongoing improvement.

Richard H. Silverman General Manager SRP 2008 ANNUAL REPORT 5

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Maybe it's acres of new pavement or the extra square feet in today's hornes. Maybe it's all those modern conveniences that need to be plugged in or recharged. Demand for electricity is growing much faster than Arizona's population. In fact, the average SRP residential customer uses 14 percent more energy today than a decade ago.

So it's the right idea to find new and better ways to provide reliable, efficient and reasonably priced electricity to meet customers' needs today and tomorrow. Over the next six years, we'll invest about $7 billion to build new power plants, update existing plants and infrastructure, and add transmission lines.

Natural gas-and coal-fired plants will provide most of the electricity SRP customers need for years to come, and we're adding capacity in Pinal County and at the Springerville Generating Station. But every year a larger share of the energy we provide comes from "greener" sources such as solar, wind, biomass, geothermal and hydroelectric.

Every utility wants to expand its use of sustainable resources, which makes it harder to find new projects that make sense for SRP and our customers. A new biomass plant near Snowflake is ready to provide electricity generated from forest waste, and we're tripling our geothermal energy portfolio by acquiring 49 megawatts (MW) from a new California plant.

Improvements in solar technology are making it more practical to tap into Arizona's endless supply of sunny days. SRP is a leader in the solar revolution, with programs ranging from providing homeowner incentives to considering the feasibility of commercial solar power generating plants.

We are adding transmission lines to meet current and anticipated needs. Several construction projects are underway, including a 230-kilovolt (kV) transmission line to connect Desert Basin to Pinal South and 500-kV lines to transport power from the Palo Verde Nuclear Generating Station (PVNGS) to a new substation in western Pinal County.

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POWER I

Companies seldom urge people to use less of their product. But using less energy is always the right idea for SRP and its customers. Energy efficiency is a cornerstone of SRP's sustainability efforts and a way to reduce or delay the need for new generating resources.

For customers, energy efficiency literally pays for itself with lower power bills.

Through innovation, incentives and information, SRP helps customers take control of their energy consumption. To learn more about the SRP PowerWisel" program and other ways to save energy, visit www.srpnet.coam.

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Somebody forgot to tell La Nina that cooler ocean ternperatures are supposed to bring dry winters to Arizona.

An average of more than 12' inches of precipitation fell on the vast watershed SRP manages for our water shareholders, making it the 1 t[' wettest winter season since 1900.

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Like everyone in Arizona we welcome a reprieve from a 13-year drought, longest in the 105-year history of SRP. And we'd love to see a rainy monsoon season and another wet winter. But if more than a century of protecting the water supply has taught us anything, it's that wishing doesn't fill reservoirs and hoping doesn't deliver reliable supplies of water to thirsty communities.

It's always the right idea to manage our water system as if we're in the first year of another record dry spell, because we just might be.

The communities we serve continue to rank among the fastest-growing in the country, underscoring the importance of effective water management and storage strategies. On April 30, 2008, our reservoir system was at 98 percent of its capacity, containing more than 2.3 million acre-feet (almost 750 billion gallons) of water. That's good news for water shareholders who will receive their full allocation at least through 2009, even if the drought continues.

{-J Our underground storage program expands next year when the New River-Agua Fria River Underground Storage Project in Glendale becomes fully operational. In all, we've stored nearly 1 million acre-feet of water underground during the last 15 years.

An historic Indian water rights settlement signed in December 2007 reduces uncertainty for SRP shareholders and the Gila River Indian Community, and about 30 other parties. It's just one example of our ongoing efforts to protect the interests of water shareholders.

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Full reservoirs are good news, but don't let the numbers fool you. We can't celebrate by hosing off the driveway or letting the shower run while we answer the phone. Water conservation is the right idea for everyone in our rugged and beautiful state.

Conservation is a critical part of SRP's forward-looking Water Management Blueprint. By using our "smart" irrigation controller and adopting the SRP DesertWise Homes approach to water-efficiency, water users can help ensure the future of our water supply.

Visit www.srpnet.com to learn more about water conservation.

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SRP knows that the best way to have a positive impact on the environment is to have as little impact as possible. We weigh the environmental effects of every decision we make, not just to comply with rules and regulations, but because it's the right thing to do.

Right ideas come in all shapes and sizes, from planting trees and changing light bulbs to being a thought leader in addressing some of the biggest problems facing our planet.

SRP has been involved in climate change research for more than 20 years, so it's natural for us to take a lead role on this important topic. We have developed climate change principles to guide our actions and are a founding reporting member of The Climate Registry, a voluntary program to measure greenhouse gas emissions throughout North America.

Including nuclear power, 20 percent of the electricity we provide today is produced without creating greenhouse gases.

It's our goal to triple the percentage of our retail customers' needs that we meet with sustainable resources and energy efficiency by 2025.

SRP also is part of two groundbreaking Electric Power Research Institute (EPRI) programs: a study of a promising chilled-ammonia process to capture carbon emissions and isolate them underground, and a National Energy Efficiency tENVIRO i~j~

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Demonstration to show how utilities can use communications technology to help consumers reduce electricity use by up to 10 percent.

Arizona Rinse Smart proves that a small change can make a big difference. SRP has provided nearly 2,100 water-and energy-saving, high-pressure nozzles for installation in commercial kitchens; they save an estimated 19 million gallons of water per year.

SRP is planting trees in northern Arizona forests damaged by fires.

We match customers' contributions through the EarthWise Trees for Change program and donate 10 trees for every run the Arizona Diamondbacks score this season.

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Every part of SRP must embrace our environmental values, so we formed an Internal Sustainability Committee to help us improve our own operations.

Our new Pinal County Customer Care Center will meet Leadership in Energy and Environmental Design (LEED) certification standards when it opens next spring. We also installed more efficient lighting at all our facilities, which will save some 6,400 megawatt-hours (MWh) over six years, and have added 120 alternative fuel vehicles to our fleet. And we print almost everything - including this report - on paper with recycled content.

For more information: www.srpnet.com/energysavings

• www.srpnet.com/cflpledge

• www.srpnet.com/renewable I1I

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The best neighbors are there to lend a helping hand when you need it most. SRP already was involved in the community before Arizona became a state. So it's no surprise that we're still here and more active than ever.

These are our communities, too. It's the right idea to make life better in the hometowns where our customers, employees, friends and neighbors live, work and raise their families.

I SRP employees share our commitment to helping others.

Just ask the thousands of Southern Californians whose power service was restored by SRP line crews after last fall's devastating wildfires. Or ask the Points of Light Foundation, which presented its top workplace volunteer award to SRP in 2007 - for the second time. About 85 percent of employees show they care through volunteer efforts and charitable giving. Employees, their families and friends spent more than 700,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> volunteering in our communities last year.

SRP contributed more than $3.9 million to a wide range of arts and culture, civic, educational, environmental, and health and human services organizations.

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The largest share of our support goes to health and human service organizations, including food banks, the United Way and the Salvation Army. Donations from SRP and our customers also provided more than $278,000 in assistance to help low-income families pay their electric bills.

SRP is working on long-term solutions through more than 50 economic development organizations that are trying to attract new employers, create jobs and diversify Arizona's economy.

Higher food and fuel prices and a slower economy are putting pressure on Arizonans and the groups that help people in need.

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_S RVICE COMMUNITY Safety is a way of life for SRP and our employees. With just 1.22 reportable safety incidents per 200,000 working hours in 2007, the APPA named SRP the country's safest large utility.

Our safety culture extends into the community. More than 275 contractors and landscapers attended our 26th annual Electrical Safety Workshop.

We launched an ad campaign to raise awareness of electric and canal safety. And, with the "Latch & Lock It!"

program, SRP metering employees help prevent drownings by closing pool gates and leaving reminders for homeowners.

For more information: www.srpnet.com/srpsafety

• www.srpnet.com/clossroom

• www.srpnet.com/volunteers 13

MANAGEMENT'S FINANCIAL AND 1

OPERATIONAL

SUMMARY

This section explains SRP's general financial condition and results of operations for the fiscal year. SRP includes the Salt River Protect Agricultural Improvement and Power District (the District) and the Salt River Valley Debt Ratio Water Users' Association (the Association). The results of these entities are combined for financial reporting purposes.

Overview of Business 48.9 The District owns and operates an electric system which 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 FY 041 (5

06 07 08 generation, transmission and distribution resources to keep pace with load growth.

The District builds and acquires generation resources as needed, as well as makes short-and long-term purchases of wholesale power. For example, during the past fiscal year the District continued construction activities associated with the Palo Verde to Southeast Valley 500-kV transmission line, which, when completed in 2011, will provide additional capacity to the fast-growing southeastern portion of its service territory.

In terms of generation, the District continued construction of a 400-MW, coal-fired Debt Service Coverage Ratio generating unit near Springerville, Arizona. The new unit is located at Tucson Electric Power Company's existing Springerville Generating Station and is scheduled to

,0, 282 be operational in late 2009. The District also announced plans for new gas-fired generation facilities in fast-growing Pinal County.

SRP continues to pursue development and acquisition of renewable resources to expand its Sustainable Portfolio, which now contributes more than 6 percent of the energy needed for retail sales. Demonstrating environmental leadership, SRP became a founding reporter of The Climate Registry, a new Washington, D.C.-based nonprofit organization that records and tracks greenhouse gas emissions.

FY 0,1 (f) 06 07 08 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 located within the major portions of the cities of Phoenix, Avondale, Glendale, Mesa, Tempe, Chandler, Gilbert, Peoria, Scottsdale and Tolleson.

14

The District's subsidiaries include New West Energy Corporation, which supports the District's energy services activities in Arizona; Papago Park Center, Inc., which manages a mixed-use commercial development known as Papago Park Center, located on land owned by the District adjacent to its administrative offices; and SRP Captive Risk Solutions, Limited, which is a domestic captive insurer incorporated in January 2004 to primarily access property/boiler and machinery insurance coverage under the Federal Terrorism Risk Insurance Act of 2002 for certified acts of terrorism.

Results of Operations SRP's net revenues for the fiscal year ended April 30, 2008, were $257.1 million compared to $367.8 million the previous year. Operating revenues were

$2.7 billion for fiscal year 2008 (FY08), compared to $2.6 billion for FY07.

Increased operating revenues primarily were the result of continued growth in SRP's customer base, increased usage per customer and the increase in the Fuel and Purchased Power Adjustment Mechanism (FPPAM) in November 2007. These increases were partially offset by the decrease in wholesale revenue.

Specifically, total customers increased 1 percent from the previous year with 62 percent of the increase attributed to the residential class. Usage per customer increased 2 percent. The 4.7 percent increase in the FPPAM contributed

$56.1 million to operating revenues. The 11 percent decrease in total wholesale revenues primarily was due to the volatility of mark-to-market contracts, and the netting of certain purchases and sales of energy as required by accounting principles generally accepted (GAAP) in the U.S. Without these adjustments, wholesale revenues were down 3 percent because of limited opportunities to purchase power and make wholesale sales.

Operating expenses were $2.4 billion for FY08, compared with $2.2 billion for FY07. This change was driven by higher fuel expense, increased maintenance costs and higher operating expenses. Fuel expense was higher due to increased generation needs and overall higher market prices. Palo Verde Nuclear Generating Station (PVNGS) was a major contributor to higher maintenance and operating expenses as a result of actions needed to correct findings from the Nuclear Regulatory Commission and unplanned outages.

Interest income was $62.7 million, compared with $86.8 million the previous year. Interest income was lower during the year due to lower balances and interest rates, as well as the application of SFAS No. 115 accounting (see Note (6), Fair Value of Financial Instruments: Accounting for Debt and Equity Securities, in the accompanying notes to the Combined Financial Statements).

Retail Electric Revenues (SBilions 2,2 FY

0) 1 01b 06 0U7 08 15

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 peaking utility, there are times during the year when the District's resources and/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 Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). For a detailed explanation of the effects of SFAS No. 133 on the District's financial results, see Note (3), Accounting for Derivative Instruments and Hedging Activities, in the accompanying notes to the Combined Financial Statemenls.

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Defleation The Energy Risk Management Program is managed according to a policy approved by the District's Board of Directors (the 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, notional and duration limits. The Risk Oversight Committee is composed of SRP management executives. The District maintains an Energy Risk Management department, separate from the energy Depreciation marketing area, which regularly reports to the Risk Oversight Committee. In addition, the District has established a credit reserve for its activity in wholesale markets. The District believes that its existing risk management structure is appropriate and that any exposures are adequately covered by existing reserves.

Electric Pricing The District has a diversified customer base, with no single retail customer providing more than 1.6 percent of its operating revenues. The District has implemented projects and programs geared towards enhancing customer loyalty 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 for many years has made an effort to balance the summer-winter load relationships through seasonal price differentials. In addition, the District prices on a time-of-day basis for large commercial and industrial customers, residential customers, and certain small commercial users.

16

Net Financing Costs ($Millions)

On October 1, 2007, the District Board approved a 4.7 percent fuel and purchased power price increase, effective November 1, 2007. The increase was needed to help recover an under-collection of fuel-and purchased power-related costs.

123 On January 4, 2008, SRP initiated a price process to consider a proposal by 1

management to increase and modify SRP's price plans. The proposed increase varied across customer classes, but represented a 3.9 percent overall average retail 06 price increase that is expected to generate approximately $91.2 million annually.

Price plan design changes were made to better reflect underlying costs. It is expected that these design changes will promote energy efficiency and conservation.

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The District Board approved management's proposals and the increase arid design changes went into effect on May 1, 2008.

Rate Stabilization Fund In 2001, the District Board created a Rate Stabilization Fund (RSF) to be used in concert with the FPPAM to cover fuel related expenses and to stabilize future prices related to fuel, as well as for other purposes. Since the time of the initial authorization, the District has funded the RSF three times and transferred $165 million, plus interest, from the RSF to the District's General Fund to address a portion of fuel and purchased power expenses for fiscal years 2006 through 2008.

Capital Expenditures ($Millions) 1,076 Capital Improvement Program The Capital Improvement Program is driven by the need to expand the generation, 6

transmission and distribution systems of the District to meet growing customer electricity needs and to maintain a satisfactory level of service reliability.

FY08 capital spending levels were consistent with management's expectations.

Generation projects, 42 percent of the year's expenditures, included continued construction spending for the Springerville generating unit.

Expansion of the electrical distribution system to meet new growth and to replace aging underground cable accounted for 29 percent of FY08 capital expenditures.

Nearly half of the distribution system spending was for new business projects. The FY O

06 07 08 addition of new transmission facilities made up 14 percent of the year's capital expenditures. FY08 transmission spending included support for the Southeast Valley 500-kV transmission line.

Combined Balance Sheets As of April 30, 2008 and 2007 Assets 2008 2007 (Thousands)

Utility Plant Plant in service E le c tr ic.................................................................................

Ir r ig a tio n..........................................................................................

C o m m o n..........................................................

To ta l p la n t in se rv ice........................................................

Less - Accumulated depreciation on plant in service.....................

P la n t h e ld fo r fu tu re u se.................................................................

Construction work in progress.......................................................

N u c le a r fu e l, n e t............................................................

Other Property and Investments Non-utility property and other investments.......................................

Segregated funds, net of current portion...........................................

Current Assets C a sh a nd ca sh eq u iva lents................................................................

R a te S ta b iliza tio n Fu nd......................................

Te m p o ra ry inve stm e nts.........................................................................

Current portion of segregated funds..............................................

Receivables, net of allowance for doubtful accounts.................

F u e l s to c k s...............................................................................................

M a te ria ls a n d su p p lie s.........................................................................

O th e r c u rre n t a sse ts.............................................................................

8,943,588 294,038 488,692 9,726,318 (4,687,090) 5,039,228 3,726 1,041,462 94,904 6,179,320 194,900 1,153,803 1,348,703 414,428 106,556 98,765 241,626 37,829 124,160 115,527 1,138,891 8,596,738 283,065 472,244 9,352,047 (4,419,510) 4,932,537 3,283 511,580 45,955 5,493,355 137,837 877,171 1,015,008 495,150 82,273 137,058 83,000 226,456 26,902 106,740 57,524 1,215,103 422,266 8,145,732 Deferred Charges and Other Assets..............................

715,093 9,382,007 The accompanying notes are an integral part of these cambined financial statements.

1 8 SRP 2008 ANNUAL REPORT

Combined Balance Sheets As of April 30, 2008 and 2007 Capitalization and Liabilities 2008 2007 (Thousands)

Long-Term Debt....

3,679,929 Accumulated Net Revenues and Other Comprehensive Income.

To ta l C a p ita liz a tio n.............................................

3,838,835 7,518,764 3,041,408 3,606,896 6,648,304 Current Liabilities Current portion of long-term debt....

A cco unts paya ble..................................

Accrued taxes and tax equivalents A cc rued inte re st......................................

C ustom ers' deposits...........................

O ther current liabilities........................

170,748 284,295 72,600 49,122 79,049 174,644 830,458 146,148 219,027 75,135 47,646 73,909 159,745 721,610 Deferred Credits and Other Non-Current Liabilities....

1,032,785 775,818 Commitments and Contingencies (Notes 5, 7, 8, 9, 10 and 11) 9,382,007 8,145,732 The accompanying nates are an integral part of these combined financial statements.

SRP 2008 ANNUAL REPORT 1 9

Combined Statements of Net Revenues and Comprehensive Income For the years ended April 30, 2008 and 2007 Operating Revenues R e ta il e le c tric..........................................................

W a te r......................................................................

O th e r........................................................................

Total operating revenues..............................

Operating Expenses Po w e r p u rcha sed................................................

Fuel used in electric generation......................

Other operating expenses................................

M a in te n a n ce.........................................

Depreciation and amortization.......................

Taxes and tax equivalent...................................

Total operating expenses.............................

Net operating revenues...............................

2008 2007 (Thousands) 2,212,807 14,339 511,977 2,739,123 486,406 677,871 484,954 304,824 369,477 93,376 2,416,908 322,215 2,054,652 12,893 563,188 2,630,733 475,349 615,961 439,338 236,646 348,643 97,607 2,213,544 417,189 Other Income In te re st in c o m e.................................................................................................................................

6 2,6 5 7 8 6,7 6 5 Other income (deductions), net.........................................

To ta l o the r inco m e, net......................................................

Net revenues before financing costs............................

(4,5 5 3 )

58,104 380,319 Financing Costs In te re st o n b o n d s..................................

C a p ita liz ed inte re st................

Amortization of bond discount/premium and issuance expenses.............................

Inte rest o n o the r o b lig a tio ns........................................................

N e t fin a n c in g c o sts...............................................................

N e t R e v e n u e s....................................................

123,455 (23,552)

(5,962) 29,275 123,216 257,103 3,459 90,224 507,413 122,093 (9,110)

(6,181) 32,821 139,623 367,790 98,244 466,034 Other Comprehensive Income Comprehensive Income.. R (25,164) 23 1,939 The accompanying notes are an integral part of these combined financial statements.

20 SRP 2008 ANNUAL REPORT

Combined Statements of Cash Flows For the years ended April 30, 2008 and 2001 2008 257,103 2007 (Thousands)

Cash Flows from Operating Activities N e t re v e n u e s..........................................................................................................................

Adjustments to reconcile net revenues to net cash provided by operating activities:

Depreciation, amortization and accretion......................................................................

Amortization of net bond discount/premium and issuance expenses.................

Change in fair value of derivative instruments...........................................................

G a in o n sa le o f ca p ita l a sse ts.............................................................................................

Decrease (increase) in:

Fue l sto cks a nd m a te ria ls a nd sup p lies.............................................................................

Receivables, including unbilled revenues, net................................................................

O th e r c u rre n t a s s e ts..............................................................................................................

D efe rred cha rg es a nd o the r a ssets...................................................................................

Increase (decrease) in:

A c c o u n ts p a y a b le..........................................................................................................

A ccrued ta xes a nd ta x eq u iva lents....................................................................................

A c c r u e d in te re s t.......................................................................................................................

C u r re n t lia b ilitie s........................................................................................

Deferred credits and other non-current liabilities........................................................

Net cash provided by operating activities......................................................

Cash Flows from Investing Activities A d d itio n s to u tility p la n t, n e t................................................................................................

Pro ceed s fro m d ispo sitio n o f a ssets...................................................................................

P u rc h a se s o f in v e stm e n ts..................................................................

S a le s a nd m a tu ritie s o f secu ritie s.......................................................................................

Net change in short-term investments related to segregated funds......................

N et ca sh u sed fo r inve sting a ctiv ities......................................................................................

Cash Flows from Financing Activities Proceeds from issuance of revenue bonds......................................................................

Repayment of long-term debt, including refundings....................................................

N et cash p rovided by fina ncing activities........................................................................

Net Increase (Decrease) in Cash and Cash Equivalents...............................

367,790 369,477 (5,963)

(92,707)

(301)

(28,347)

(15,170)

(10,168)

(10,046) 348,643 (6,181)

(47,230)

(4,809)

(12,559)

(37,443) 26,144 (107,296) 65,268 (2,535) 1,476 19,768 (13,180) 534,675 (1,073,997) 9,101 (1,344,636) 1,210,608 (83,848)

(1,282,772) 816,139 (148,764) 667,375 (80,722) 495,150 414,428 56,223 2,378 2,239 (60,298) 212,922 740,523 (650,520) 43,512 (1,494,805) 1,290,228 (70,360)

(881,945) 299,963 (129,338) 170,625 29,203 465,947 495,150 143,565 Balance at Beginning of Year in Cash and Cash Equivalents.....

Balance at End of Year in Cash and Cash Equivalents....................

Supplemental Information Cash paid for interest (net of capitalized interest)....................................................

127,702 The accompanying notes are an integral port of these combined financial statements.

SRP 2008 ANNUAL REPORT 21

Notes to Combined Financial Statements April 30, 2008 ond 2007 The Company - The Salt River Project Agricultural Improvement and Power District (the District) is an agricultural improvement district organized in 1937 under the laws of the State of Arizona. It operates 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 in a 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 in Gila 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.

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 projecf. 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.

Principles of Combination - The accompanying combined financial statements reflect the combined accounts of the Association and the District (together referred to as SRP). The District's financial statements are consolidated with its three 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 in January 2004 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 in Arizona by retail competition in the supply of generation, but is now largely inactive. All material inter-company transactions and balances have been eliminated.

Regulation and Pricing Policies - Under Arizona law, the District's publicly elected Board of Directors (the Board) 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.

(2)

SD D1fIIIAIrh% ACC©UN19I1M IPOLDOCIOS:

Basis of Accounting - The accompanying combined financial statements are presented in conformity with accounting principles generally accepted (GAAP) in the United States (U.S.) and reflect the pricing policies of the Board. The District's "regulated" operations apply Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" ISFAS No. 71 ), while "non-regulated" operations follow GAAP for enterprises in general. Classification of regulated and non-regulated operations is determined in accordance with applicable GAAP accounting guidelines.

By virtue of SRP operating a federal reclamation project under contract, with the federal government's pre-emptive rights, asset ownership and certain approval rights, SRP is considered for financial reporting purposes to follow accounting stacdards as set forth by the Federal Accounting Standards Advisory Board IFASAB). Entities reporting in accordance with the standards issued by the Financial Accounting Standards Board IFASB) prior to October 19, 1999 (the date the American Institute of Certified Public Accountants IAICPA) designated the FASAB 22 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 as the accounting standard setting body for entities under the federal government) are permitted to continue to report in accordance with those standards. Consequently, SRP's financial statements are reported in accordance with FASB standards.

The preparation of financial statements in compliance with 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.

Utility Plant - Utility plant is stated at the historical cost of construction, less any impairment losses. Capitalized construction costs include labor, materials, services purchased under contract, and allocations of indirect charges for engineering, supervision, transportation and administrative expenses and capitalized interest or an Allowance for Funds Used During Construction (AFUDC). 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. The cost of property that is replaced, removed or abandoned, together with removal costs, less salvage, is charged to accumulated depreciation.

Composite rates of 4.76% and 4.67% were used in fiscal years 2008 and 2007 to calculate interest on funds used to finance construction work in progress, resulting in $23.6 million and $9.1 million of interest capitalized, respectively.

Depreciation expense is computed on the straight-line basis over the estimated useful lives of the various classes of plant assets..The following table reflects the District's average depreciation rates on the average cost of depreciable assets, for the fiscal years ended April 30:

2008 2007 A ve ra g e electric d ep recia tio n ra te...........................................................................................................

3.66%

3.5 8%

A verage irrigatio n dep reciatio n rate........................................................................................

2.05%

1.93%

A vera g e co m m o n d ep recia tio n ra te........................................................................................................

6.49%

6.35%

Bond Expense - Bond discount/premium and issuance expenses are amortized using the effective interest method over the terms of the related bond issues.

Allowance for Doubtful Accounts - The District has provided for an allowance for doubtful accounts of $12.1 million and $13.0 million as of April 30, 2008 and 2007, respectively.

Nuclear Fuel - The District 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 the disposal expense are components of fuel expense. Accumulated amortization of nuclear fuel at April 30, 2008 and 2007 was $425.7 million and $408.2 million, respectively.

Asset Retirement Obligations - SRP adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143), on May 1, 2003. SFAS No. 143 requires the recognition and measurement of liabilities for legal obligations associated with the retirement of tangible long-lived assets. Under the standard, these liabilities 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 included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

SRP 2008 ANNUAL REPORT 23

Notes to Combined Financial Statements April 30, 2008 and 2007 The District has identified retirement obligations for the Palo Verde Nuclear Generating Station (PVNGS), Navajo Generating Station INGS), Four Corners Generating Station (Four Corners) and certain other assets. Amounts recorded under SFAS No. 143 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. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as expense for asset retirement obligations. PVNGS received an updated decommissioning study during fiscal year 2008, which resulted in a decrease of $32.2 million to SRP's share of the PVNGS asset retirement obligation.

A summary of the asset retirement obligation activity of the District for the year ended April 30, 2008, is included below (in millions):

B a la n c e, M a y 1, 2 0 0 7..........................................................................................................

1......................................

1 9 5.0 L ia b ilitie s in c u r re d.................................................................................................................

2............................

2.5 C h a n g e s in e stim a te..........

(3 2.2 )

A c c re tio n e x p e n s e..........................................................................................................................................................

1 2.0 B a la n c e, A p ril 3 0, 2 0 0 8...........................................................................................................................................

BA0 1 7 7.3 In accordance with regulations of the Nuclear Regulatory Commission, the District maintains a trust for the decommissioning of PVNGS. Decommissioning funds of $194.5 million and $196.4 million, stated at market value, as of April 30, 2008 and 2007, respectively, are held in the trust and are classified as segregated funds in the accompanying Combined Balance Sheets. The nuclear decommissioning trust funds are invested in debt and equity securities. The trust funds are accounted for in accordance with Statement of Financial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Securities" (SFAS No. 11 51, and are classified as available-for-sale. The nuclear decommissioning trust funds-are exempt from federal and state income taxes.

In fiscal year 2008, the Board authorized the future recovery through prices of all costs associated with nuclear decommissioning. As a result, any difference between current year costs and revenues associated with nuclear decommissioning are deferred. Accordingly, the District's nuclear decommissioning activities are accounted for in accordance with SFAS No. 71 and have no impact to the District's earnings. Realized and unrealized gains and losses (including other-than-temporary impairments) on decommissioning trust funds increase or decrease the trust asset and the related regulatory asset or liability. (See Note (9), Regulatory Issues: Deferred Charges and Deferred Credits, for additional disclosure.)

Regulatory Accounting - The District accounts for the financial effects of the regulated portion of its operations in accordance with the provisions of SFAS No. 71, which requires cost-based, rate-regulated utilities to reflect the impacts of regulatory decisions in their financial statements. Regulatory assets represent probable future recovery of certain costs from customers through the pricing process and are included in deferred charges and other assets in the accompanying Combined Balance Sheets. (See Note (9), Regulatory Issues: Deferred Charges and Deferred Credits, for additional discussion.)

Accounting for 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, 24 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 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 under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" as amended (SFAS No. 1 33). Under SFAS No. 133, derivatives are recorded in the balance sheet as either an asset or liability measured at their fair value. The standard also requires changes in the fair value of the derivative to be recognized each period in current earnings or other comprehensive income depending on the purpose for using the derivative and/or its qualification, designation and effectiveness as a hedging transaction. Many of the District's contractual agreements qualify for the normal purchases and normal sales exception allowed under SFAS No. 133 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 contracted prices; and the SFAS 133 documentation requirements are met. (For further explanation of the effects of SFAS No. 133 on SRP's financial results, see Note (31, Accounting for Derivative Instruments and Hedging Activities.)

Concentrations of Credit Risk - The use of dontractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure 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, and continuously monitors credit exposures, routinely assesses the financial strength of its counterparties, 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 by requiring letters of credit, parent guarantees or other collateral when it does not consider the financial strength of a counterparty sufficient.

Income Taxes - The District is exempt from federal and Arizona state income taxes. The Association is not exempt from federal and Arizona state income taxes but has not been liable for income taxes on the basis of a settlement with the Commissioner of Internal Revenue in 1949 which was approved by the U.S. Secretary of the Treasury. The District has three wholly-owned taxable subsidiaries: CRS, PPC and New West Energy. The tax effect of these subsidiaries' operations on the combined financial statements is immaterial.

Cash Equivalents - The District treats short-term temporary cash investments with original maturities of three months or less as cash equivalents, except for those short-term investments that are set aside for a specific purpose, such as amounts held in the Rate Stabilization Fund IRSF) or as part of the segregated funds.

Rate Stabilization Fund - In 2001, the District Board created the RSF to be used in concert with the Fuel and Purchased Power Adjustment Mechanism (FPPAM) to cover fuel related expenses and to stabilize future prices related to fuel, as well as for other purposes. Since the time of the initial authorization, the District has funded the RSF three times and transferred $165.0 million, plus interest, from the RSF to the District's General Fund to address a portion of fuel and purchased power expenses for fiscal years 2006 through 2008. (See Note 19), Regulatory Issues: The Changing Regulatory Environment, for additional information on the FPPAM.I Revenue Recognition - The District 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 was $64.0 million and $60.1 million at April 30, 2008 and 2007, respectively. Other operating revenue consists primarily of revenue from marketing and trading electricity.

SRP 2008 ANNUAL REPORT 25

Notes to Combined Financial Statements April 30, 2008 and 2007 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 combined financial statements.

Materials and Supplies, and Fuel Stocks - Materials and supplies are stated at lower of market or average cost. Fuel stocks are stated at lower of market or weighted average cost.

Reclassifications - For comparative purposes, certain prior year amounts have been reclassified to conform to the current year presentation. The reclassifications had no impact on total assets, net revenues or cash flows.

Recently Issued Accounting Standards - The FASB has issued the following Statements of Financial Accounting Standards ISFAS), Emerging Issues Task Force Opinions (EITF) and Interpretations (FIN) that may have an impact on SRP:

In June 2006, the FASB issued EITF Issue No. 06-03, "How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (that is, Gross versus Net Presentation)" (EITF 06-03), which requires that SRP disclose its accounting policy regarding presentation of taxes on either a gross (included in revenues and costs) or a net (excluded from revenues) basis. Additionally, the amounts of any taxes reported on a gross basis in interim and annual financial statements must be disclosed. EITF 06-03 is effective for interim and annual reporting periods beginning after December 15, 2006. SRP adopted the provisions of this statement on May 1, 2007. Sales tax amounts collected from customers have been recorded on a net basis, which resulted in no impact to the financial statements. (See Sales and Use Taxes in this Note.)

FIN No. 48, "Accounting for Uncertainty in Income Taxes -An Interpretation of FAS 109" (FIN No. 48), issued July 2006, requires a determination of whether it is more-likely-than-not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. Once it is determined that a tax position meets the more-likely-than-not recognition threshold, the position is measured to determine the amount of benefit to recognize in the financial statements. FIN No. 48 is effective for fiscal years beginning after December 15, 2006, and was adopted by SRP on May 1, 2007. The adoption did not have a material impact on the accompanying combined financial statements.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, "Fair Value Measurements" ISFAS No. 1 57). SFAS No. 157 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 expands required disclosures about fair value measurements. SRP adopted the provisions of this standard effective May 1, 2008. Implementation of SFAS No. 157 impacts the recognition of future changes in fair value. As such, SRP cannot predict the impact that adopting this standard will have on the results of future operations.

Also in September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans" (SFAS No. 1 58). SFAS No. 158 requires an employer to recognize overfunded or underfunded status of the plan, measure defined benefit plan assets and obligations as of the date of the employer's statement of financial position, and disclose additional information in the footnotes. The provisions of this standard are effective for SRP for fiscal years ending after June 15, 2007; accordingly, SRP adopted'the provisions of this standard on April 30, 2008. (See Note (7), Defined Benefit Plans and Incentive Programs: Defined Benefit Pension and Other Post-Retirement Benefits, for additional discussion.]

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, "The' Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment to FASB Statement No. 115" (SFAS No. 159), which provides an option to report eligible financial assets and liabilities at fair value, with changes in fair value recognized in earnings.

26 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 SRP adopted the provisions of this standard effective May 1, 2008. Elections made under SFAS No. 159 impact the recognition of future changes in fair value. As such, SRP cannot predict the impact that its elections will have on the results of future operations.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, "Disclosures about Derivative Instruments and Hedging Activities-An Amendment of FASB Statement No. 133" (SFAS No. 161 ). SFAS No. 161 requires additional disclosures related to derivative instruments, including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption permitted. SRP will adopt the provisions of this standard on May 1, 2009.

SFAS No. 161 will impact disclosures only and will not have an impact on SRP's combined financial statements.

(3)

ACCOUNTING FOR* ID)IROVAUIVIE 01I*STRUMEN S AND H 1E@111G ACTIVIOIOE£:

SRP follows SFAS No. 133, which requires that entities recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value. Changes in fair value are recognized immediately in earnings unless specific hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings.

The District enters into contracts for electricity, natural gas and other energy commodities to meet the expected needs of its retail customers. The District sells excess capacity during periods when it is not needed to meet retail requirements. The District's energy risk management program uses various physical and financial contracts to economically hedge exposures to fluctuating commodity prices. The District examines contracts at inception to determine the appropriate accounting treatment. If a contract does not meet the derivative criteria, or if it qualifies for the SFAS No. 133 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).

Contracts that qualify as a derivative but do not meet the SFAS No. 133 normal purchases and normal sales scope exception are recorded at fair value with changes in fair value recognized in earnings. Changes in fair value related to the District's derivatives are classified as part of operating cash flows in the Combined Statements of Cash Flows.

The following table summarizes the District's derivative-related assets and liabilities at April 30 (in thousands):

2008 2007 O th e r c u rre n t a sse ts.......................................................................................................................................

10 1,7 9 5 4 0,0 2 4 D efe rred cha rg es a nd o the r a ssets...........................................................................................................

5 8,520 40,8 13 O th e r c u rre n t lia b ilitie s..................................................................................................................................

(5,4 6 0 )

(1 8,6 2 4 )

Deferred credits and other non-current liabilities................................................................................

(583)

(9,085)

Lo n g -te rm d e b t.................................................................................................................................................

7 2 4 1,8 5 5 N e t a s s e ts.............

1 5 4,9 9 6 5 4,9 8 3 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. As a result of these transactions, the District 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 $166.1 million and $150.4 million for fiscal years 2008 and 2007, respectively, but which did not impact net revenues or cash flows.

SRP 2008 ANNUAL REPORT 27

Notes to Combined Financial Statements April 30, 2008 and 2007 The following table summarizes the District's unrealized gains (losses) associated with derivative-related activity at April 30 (in thousands):

2008 8,5 0 0 Operating revenues Pow er purchased...............................................................................................

Fuel used in electric generation...................................................................

Interest on other obligations...........................................................................

N et unrealized gain.........................................................................................

26,271 56,284 1,652 92,707 2007 35,137 12,565 (472) 47,230 (4) foloinLgItable D

sm ize RacVcu UES AN D other compreHenSIVe IOncm linto The following table summarizes accumulated net revenues and other comprehensive income (in thousands):

Accumulated Other Comprehensive Income (Loss)

BALANCE, April 30, 2006...................

N et reve n ues........................................

Other comprehensive income..............

BALANCE, April 30, 2007.................

N et reven ues....................................

Accumulated Net Revenues

$ 3,202,326 367,790 3,570,116 257,103 Minimum Pension Liability

$(73,300)

Unrealized Gain on Available-For-Sale Securities 11,836 Total (61,464)

Accumulated Net Revenues and Other Comprehensive Income 3,140,862 367,790 98,244 3,606,896 73,300 24,944 98,244 36,780 (25,164) 11,616 36,780 (25,164) 257,103 (25,164)

Other comprehensive income..............

BALANCE, April 30, 2008...................

$ 3,827,219 11,616 3,838,835 (5).

dLeb onsislaRd DE idY:

Long-term debt consists of the following at April 30 (in thousands):

Interest Rate 4.00- 6.50%

Revenue bonds (mature through 2038)........................................

Unamortized bond (discount) prem ium........................................

Total revenue bonds outstanding...............................................

F in a n c e le a s e..........................................................................................

C o m m e rc ia l p a p e r................................................................................

To ta l lo n g -te rm d e b t........................................................................

Unamortized interest rate swap.......................................................

Less: Current portion of long-term.............................................

Total long-term debt, net of current...........................................

2.50- 5.25%

0.90- 2.75%

2008 3,074,928 51,108 3,126,036 250,365 475,000 3,851,401 (724)

(170,748) 3,679,929 2007 2,394,926 53,105 2,448,031 266,380 475,000 3,189,411 (1,855)

(146,148) 3,041,408 28 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 The annual maturities of long-term debt (excluding commercial paper, unamortized mini-revenue bond accretion, and unamortized bond discount/premium) as of April 30, 2008, due in fiscal years ending April 30, are as follows (in thousands):

Revenue Finance Bonds Lease 2 0 0 9....................................................................................................................................

1 5 2,9 6 8 1 7,7 8 0 2 0 1 0.......

1....

1 67........

0__

1 1 5,8 5 5 1 6,7 9 0 2 0 1 1............................................................................................................

1 0 8,4 8 0 1 9,9 5 0 2 0 1 2................

2 2

1 0 3,4 3 0 1 7,4 5 5 2 0 1 3.......................................................................................................................................................................

7 8,4 9 5 2 2,9 9 5 T h e re a fte r 2.................................................

2,5 1 5,7 0 0 1 5 5,3 9 5 3,074,928 250,365 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 bond resolution. Under the terms of the amended and restated bond resolution, effective in January 2003, the District is no longer required to make monthly deposits to an externally trusteed debt service fund for the payment of future principal and interest. However, the District is continuing to make debt service deposits to a non-trusteed segregated fund. Included in segregated funds in the accompanying Combined Balance Sheets are $181.3 million and $150.7 million of debt service related funds as of April 30, 2008 and 2007, respectively.

The District has $38.5 million of mini-revenue bonds outstanding, which are redeemable at the option of the bondholder under certain circumstances. Based on historical redemptions made on these bonds, management believes there are sufficient funds available to cover potential redemptions in any year.

The debt service coverage ratio, as defined in the Bond Resolution, is used by bond rating agencies to help evaluate the financial viability of the District. For the years ended April 30, 2008 and 2007, the debt service coverage ratio was 2.82 and 3.09, respectively.

Interest and the amortization of the bond discount, premium and, issue expense on the various issues results in an effective rate of 4.93% over the remaining term of the bonds.

The District has authorization to issue additional Electric System Revenue Bonds totaling $384.0 million principal amount and Electric System Refunding Revenue Bonds totaling $4.0 billion principal amount, and has an application pending with the Arizona Corporation Commission for additional authorization in the principal amounts of $1.9 billion and $2.1 billion, respectively.

In July 2006, the District issued $296.0 million Electric System Revenue Bonds. The net proceeds from these bonds were used to fund distribution capital requirements. In March 2008, the District issued an additional $8 16.7 million Electric System Revenue Bonds, the net proceeds of which are being used to finance additional capital improvements to the electric system pursuant to the District's Capital Improvement Program.

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 Basinl located in central Arizona. In a concurrent transaction, $282.7 million in fixed-rate Certificates of Participation (COPs) were issued pursuant to a Trust Indenture, between Wilmington Trust Company, as trustee, SRP 2008 ANNUAL REPORT 29

Notes to Combined Financial Statements April 30, 2008 and 2007 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.

In connection with the issuance of the COPs, the District entered into a six-year, $75 million fixed-to-floating interest rate swap transaction with Morgan Stanley Capital Services. The notional value of the swap is $50 million, with

$25 million notional maturities expiring on December 1, 2008 and 2009, respectively. The floating rate on the swap is based on the Securities Industry and Financial Markets Association (SIFMA) Municipal Index and the fixed-receiver rate on the swap is 3.00 1%. Through the swap, the District was able to create synthetic variable rate debt and take advantage of the relationship between intermediate-term, tax-exempt borrowing costs and SIFMA-based, fixed-receiver swap rates. In addition, the swap to variable rate also enables the District to increase its short-term, variable rate debt portfolio. The interest rate swap is accounted for as a derivative. (For further explanation of the effects of SFAS No. 133 on the District's financial results see Note 13), Accounting for Derivative Instruments and Hedging Activities.)

Commercial Paper - The District has outstanding $475.0 million of commercial paper consisting of $375.0 million Series B Commercial Paper and $100.0 million Series C Commercial Paper. The issues have an average weighted interest rate to the District of 1.74%.

The commercial paper matures not more than 270 days from the date of issuance and is an unsecured obligation of the District. The District has the ability to refinance the outstanding commercial paper on a long-term basis in connection with its revolving line of credit that supports the commercial paper and is available through December 7, 2009. As such, the District has classified the commercial paper as long-term debt in the Combined Balance Sheets as of April 30, 2008.

The revolving credit agreement contains 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 District never has borrowed under the agreement and management does not expect to do so in the future. 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.

Line-of-Credit Agreements - The District has a $475.0 million revolving line-of-credit agreement that supports the

$475.0 million commercial paper program. The agreement has various covenants, with which management believes the District was in compliance at April 30, 2008.

(6)

IFADI VIAL~UE OF FDINJANCHAD ONDfUHM~~:

The following methods and assumptions were used to estimate the fair value for each class of financial instruments identified in the following items in the accompanying Combined Balance Sheets.

Investments in Marketable Securities - The District invests in U.S. government obligations, certificates of deposit and other marketable investments. Such investments are classified as other investments, segregated funds, cash and cash equivalents or temporary investments in the accompanying Combined Balance Sheets depending on the purpose and duration of the investment. The fair value of marketable securities.with original maturities greater than one year is based on published market data. The carrying amount of marketable securities with original maturities of one year or less approximates their fair value because of their short-term maturities.

30 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 ond 2007 Long-Term Debt - 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 the fair value because of its short-term maturity. As of April 30, 2008 and 2007, the carrying amounts, including accrued interest, were $3.8.billion and $3.2 billion, respectively, and the estimated fair values were $4.0 billion and $3.3 billion, respectively.

Other Current Assets and Liabilities - The carrying amounts of receivables, accounts payable, customers' deposits and other current liabilities in the accompanying Combined Balance Sheets approximate fair value because of their short-term maturities.

Accounting for Debt and Equity Securities - The District applies SFAS No. 115 in accounting for its investments in debt and equity securities. The following table summarizes the District's investments in debt and equity securities at April 30 (in thousands):

2008 2007 C a sh a nd ca sh e q u iva le nts..........................................................................................................................

4 0 4,0 9 1 4 6 7,6 3 7 N on-utility property and other investm ents..........................................................................................

119,590 6 1,500 Seg regated fund s, net of current po rtio n...............................................................................................

1,153,803 877,171 R a te S ta b iliz a tio n F u n d................................................

8 2,2 7 3 Te m p o ra ry inv e stm e n ts.....................................................................................................................

10 6,5 5 6 13 7,0 5 8 C urrent po rtio n o f seg reg a ted fund s 8................................................

98,765 83,000 To ta l 1,8 8 2,8 0 5 1,7 0 8,6 3 9 Segregated funds include legally restricted amounts of $412.8 million and $166.1 million at April 30, 2008 and 2007, respectively, which are used to fund capital improvements to the electric system pursuant to the District's Capital Improvement Program. The remaining segregated funds are segregated due to management intent and support various purposes. The District's investments in debt securities are reported at amortized cost if the intent is to hold the security to maturity. The District's amortized cost and fair value of held-to-maturity securities were $65 1.4 million and

$653.8 million, respectively, at April 30, 2008 and $603.8 million and $604.7 million, respectively, at April 30, 2007. At April 30, 2008, the District's investments in debt securities have maturity dates ranging from May 7, 2008, to January 9, 20]14. Other debt and. equity securities are reported at market, with unrealized gains or losses included as a separate component of accumulated net revenues and other comprehensive income or deferred charges and other assets. (See Note 12), Significant Accounting Policies: Asset Retirement Obligation, 'for discussion on accounting for the unrealized gains or losses on decommissioning fund assets.)

The amortized cost, gross unrealized gains and losses, and fair value of available-for-sale debt and marketable equity securities at April 30, 2008 and 2007 were (in thousands):

2008 Gross Gross Amortized Unrealized Unrealized Cost Gains Losses Fair Value Equity securities.......................................................

944,116 25,127 (12,979) 956,264 Fixed-income securities.........................................

262,643 12,544 275,187 Total available-for-sale securities....................

1,206,759 37,671 (12,979) 1,231,451 SRP 2008 ANNUAL REPORT 31

Notes to Combined Financial Statements April 30, 2008 and 2007 2007 Amortized Cost Eq u ity secu rities.......................................................

8 16,5 2 1 Fixed-incom e securities.........................................

234,195 Total available-for-sale securities....................

1,050,716 Gross Unrealized Gains 53,992 8,148 62,140 Gross Unrealized Losses (6,334)

(1,929)

(8,263)

Fair Value 864,179 240,414 1,104,593 At April 30, 2008 and 2007, net unrealized gains (losses) on available-for-sale debt and marketable equity securities, excluding decommissioning fund assets, were $(25.2) million and $24.9 million, respectively, for the fiscal year and are included in accumulated other comprehensive income in the accompanying Combined Balance Sheets. Unrealized gains (losses) on decommissioning fund assets of $l4.0) million and $11.4 million for the fiscal years ended April 30, 2008 and 2007, respectively, are included in deferred charges and other assets in the accompanying Combined Balance Sheets.

The proceeds from sale of available-for-sale securities were $315.1 million and $344.4 million, and the net realized gains were $39.1 million and $28.0 million, at April 30, 2008 and 2007, respectively. The weighted-average cost basis is applied when computing realized gain or loss on available-for-sale securities.

The following table presents the current fair value and the associated gross unrealized losses only on investments in securities with gross unrealized losses at April 30, 2008 and 2007. The table also discloses whether these securities have had gross unrealized losses for less than twelve months, or for twelve months or longer.

Securities with Gross Unrealized Losses Less than 12 months Gross Fair Unrealized Value Losses 12 months or greater Gross Fair Unrealized Value Losses Total Gross Fair Unrealized Value Losses 81,019 (12,979) 2008 (in thousands)

Available-for-sale securities Equity securities.......................

8 1,0 19 (12,979)

Fixed-incom e securities................................

Total securities with gross unrealized losses $

81,019 (12,979) 81,019 (12,979)

Securities with Gross Unrealized Losses Less than 12 months Gross Fair Unrealized Value Losses 12 months or greater Gross Fair Unrealized Value Losses Total Gross Fair Unrealized Value Losses 2007 (in thousands)

Available-for-sale securities Equity securities..............................................

37,089 (4,218) 5,587 (2,116) 42,676 (6,334)

Fixed-income securities......

Total securities with gross unrealized lo!

117,561 (1,929) ses $

154,650 (6,147) 5,587 (2,116) 117,561 (1,929) 160,237 (8,263) 32 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 Management evaluates securities for other-than-temporary impairment on a quarterly basis considering numerous factors, and their relative significance varies case-by-case. Factors considered when determining whether impairment is other-than-temporary include the length of time and extent to which the fair value has been less than cost; the financial condition and near-term prospects of the issuer; and the District's intent and ability to hold the security in order to allow for an anticipated recovery in fair value. If, based upon an analysis of each of the above factors, it is determined that the impairment is other-than-temporary, the carrying value of the security is written down to fair value, and a loss is recognized through earnings; losses recognized on decommissioning trust securities are recorded as a regulatory asset in accordance with SFAS No. 71. The District recognized a $20.9 million other-than-temporary impairment in fiscal year 2008 of which $10.4 million is included in other income in the accompanying Combined Statements of Net Revenues and Comprehensive Income and $10.5 million is included in deferred charges and other assets in the accompanying Combined Balance Sheets.

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EMPLOYEE BENEFIT PLANS AND INCENTIVE PROGRAMS:

Defined Benefit Pension Plan and Other Post-Retirement Benefits - SRP's Employees' Retirement Plan (the Plan) covers substantially all employees. The Plan is funded entirely from SRP contributions and the income earned on invested Plan assets. The District made a contribution of $50.0 million and $70.0 million in fiscal years 2008 and 2007, respectively.

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 120 years for those hired January 1, 2000 or later).

The funding policy is discretionary and is based on actuarial determinations. The unrecognized transition obligation is being amortized over 20 years, beginning in 1994.

In September 2006, the FASB issued SFAS No. 158, which requires employers to recognize the overfunded or underfunded positions of defined benefit pension and other post-retirement plans as an asset and liability in their balance sheet. Under SFAS No. 158, any actuarial gains and losses, prior service costs and transition assets or obligations that were not recognized under previous accounting standards 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. SFAS No. 158 does not change how net periodic pension and post-retirement costs are accounted for and reported in the income statement. The District adopted the provisions for SFAS No. 158 as of April 30, 2008. (See Note (2), Significant Accounting Policies: Recently Issued Accounting Standards, for further discussion of SFAS No. 158.)

SRP 2008 ANNUAL REPORT 33

Notes to Combined Financial Statements April 30, 2008 and 2007 In fiscal year 2008, in accordance with SFAS No. 71, the Board authorized the establishment of a regulatory asset for the portion of the total 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 assetsor obligations pertaining to the regulatory asset will be 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 following.table discloses the incremental effect of applying the provisions of SFAS No. 158 (and SFAS No. 71) to individual line items in the balance sheet as of April 30, 2008 (in thousands):

Assets Deferred charges and other assets............................

Capitalization and Liabilities O the r cu rre nt lia b ilities.................................................

Deferred credits and other non-current liabilities.

Total capitalization and liabilities Before Application of SFAS No. 158 138,192 338,869 338,869 SFAS No. 158 Adjustments 278,435 20,065 258,370 278,435 After Application of SFAS No. 158 416,627 20,065 597,239 617,304 34 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 The following tables outline changes in benefit obligations, plan assets, the funded status of the plans and amounts included in the combined financial statements as of April 30, based on January 3 1 valuation dates (in thousands):

Pension Benefits 2008 2007 Post-Retirement Benefits 2008 2007 Change in benefit obligation:

Benefit obligation at beginning of year.................... $

1,130,845 S e rv ic e c o st.........................................................................

3 3,6 3 8 In te re st c o st..........................................................................

6 6,6 2 5 A m e n d m e n ts.......................................................................

A ctu a ria l lo ss..................................

(2 4,4 6 7 )

B e n e fits p a id....................................

(4 0,5 0 0 )

Benefit obligation at end of year............................ $

1,166,141 Change in plan assets:

Fair value of plan assets at beginning of year....... $

1,062,644 Actual return on plan assets..........................................

10,036 Em ployer contributions.................................................

50,000 B e n e fits p a id.....................................

(4 0,5 0 0 )

Fair value of plan assets at end of year............... $

1,082,180 Funded status at end of year...........................

(83,961) $

Unrecognized transition obligation............................

Unrecognized net actuarial loss..................................

Unrecognized prior service cost..................................

Post January 31 contributions......................................

Net asset (liability) recognized................................

(83,961) $

Amounts recognized in Combined Balance Sheets:

Deferred charges and other assets............................. $

O the r cu rre nt lia b ilitie s...................................................

Deferred credits and other non-current liabilities (83,961)

Accumulated other comprehensive income.............

Net asset (liability) recognized................................

(83,961) $

Additional detail of amounts as a regulatory asset:

Tra nsitio n o b lig a tio n........................................................

P rio r se rv ice co st...............................................................

13,9 4 9 N et a ctua ria l lo ss...............................

208,205 N et regulatory asset....................................................

222,154 1,096,700 32,800 62,000 500 (24,100)

(37,100) 1,130,800 513,503 $

11,342 30,263 510,700 12,000 28,500 (1,159)

(23,500)

(20,607)

(14,200) 533,342 $

513,500 928,900 100,800 70,000 (37,100) 1,062,600 (68,200) 171,600 16,300 119,700 20,607 14,300 (20,607)

(14,300)

(533,342) $

(513,500) 18,700 183,500 6,800 4,500 (533,342) $

(300,000) 119,700 (20,064)

(513,278)

(300,000) 119,700 (533,342) $

(300,000) 15,594 6,025 172,854 194,473 The following table represents the amortization amounts expected ending April 30, 2009, based on January 3 1 valuation dates (in to be recognized or paid during the fiscal year thousands):

N et transition obligation....................

Prior service cost.....................................................................................

N e t a c tu a r ia l............................................................................................

Pension Benefits 2,3 15 7,9 0 0 Post-Retirement Benefits 3,117 769 9,703 SRP 2008 ANNUAL REPORT 35

Notes to Combined Financial Statements April 30, 2008 and 2007 The following table outlines the projected benefit obligation and accumulated benefit obligation in excess of Plan assets as of April 30, based on January 3 1 valuation dates (in thousands):

2008

.Projected benefit obligation.....................

1,166,141 Accumulated benefit obligation.................................................................................................................

1,005,783 Fa ir v a lu e o f P la n a sse ts............

1,0 8 2,18 0 2007 1,130,800 966,400 1,062,600 The District internally funds its other post-retirement benefits obligation. At April 30, 2008 and 2007, $445.5 million and $424.7 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 Post-Retirement Benefits 2008 2007 2008 2007 D isco unt ra te.............................................................

6.25%

6.00%

6.2.

Rate of compensation increase..........................

4.00%

4.00%

N/

Weighted average assumptions used to calculate net periodic benefit costs were as follows:

5%

'A 6.00%

N/A Pension Benefits Post-Retirement Benefits 2008 2007 2008 2007 D isc o u n t ra te...........................................................

Expected return on Plan assets..........................

Rate of compensation increase.........................

6.00%

8.25%

4.00%

5.75%

8.25%

4.00%

6.00%

N/A N/A 5.75%

N/A N/A For employees who retire at age 65 or younger, for measurement purposes, a 9% annual increase before attainment of age 65 and an 11 % annual increase on and after attainment of age 65 in per capita costs of health care benefits were assumed during 2006; these rates were assumed to decrease uniformly until equaling 5% in all future years.

36 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 Components of net periodic benefit costs for the years ended April 30, are as follows (in thousands):

Pension Benefits Post-Retirement Benefits 2008 S e rv ic e c o st...............................................................

In te re s t c o s t...............................................................

Expected return on Plan assets...........................

Amortization of transition obligation.............

Recognized net actuarial loss............................

Amortization of prior service cost.....................

33,638 66,625 (82,262) 2007 32,800 62,000 (73,300) 16,000 2,300 39,800 2008 11,342 30,262 2007 12,000 28,500 3,117 10,328 3,100 12,600 11,124 2,365 769 700 56,900 Net periodic benefit cost...............................

31,490 55,818 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 (in thousands):

One-Percentage-Point Increase 6,5 0 0 74,6 0 0 One-Percentage-Point Decrease (5,600)

(65,100)

Effect on total service cost and interest cost components..........

Effect on post-retirement benefit obligation...............................

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 Plan's weighted-average asset allocations at April 30, based on January 3 1 valuations, are as follows:

Target Allocations Equity securities.................................................................................................

65.0%

2008 60.0%

2007 65.8%

Debt securities.........

Real estate................

To ta l.........................

25.0%

10.0%

27.6%

23.6%

12.4%

100.0%

10.6%

100.0%

100.0%

The investment policy allows for a tolerance range of plus or minus 5% from the stated target asset allocation.

SRP 2008 ANNUAL REPORT 37

Notes to Combined Financial Statements April 30, 2008 and 2007 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. As history has demonstrated, markets may decline and increase dramatically; however, the expected rate of return on the Plan assets is reasonable given its asset allocation in relation to historical and expected future performance.

Employer Contributions - The District expects to contribute $50.0 million to the Plan over the next valuation period.

Benefits Payments - The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Prescription Drug Act) authorized a federal subsidy to be provided to plan sponsors for certain prescription drug benefits under Medicare. SRP has adopted FASB Staff Position SFAS No. 106-2 for the effects of the Prescription Drug Act, effective July 1, 2004.

The District expects to pay benefits in the amounts as follows (in thousands):

Pension Benefits Post-Retirement Benefits Before Subsidy Net 2 0 0 9....................................................................................................

4 5,9 6 8 2 0,10 0 19,5 4 5 2 0 1 0.....................................................................................................

4 9,4 7 4 2 2,4 1 7 2 1,7 9 7 2 0 1 1.....................................................................................................

5 3,3 3 7 2 4,6 7 9 2 3,9 8 1 2 0 1 2.....................................................................................................

5 7,2 2 2 2 6,9 9 4 2 6,2 14 2 0 1 3.....................................................................................................

6 1,7 4 6 2 9,1 14 2 8,2 2 8 20 14 throug h 20 18........................................................................

376,263 180,170 174,36 1 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 have one year of service in which 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 $0.80 on every dollar contributed up to the first 6% of their base pay that they contribute to the 401 (k) Plan. Employer matching contributions to the 401 (k) Plan were

$12.9 million and $12.3 million during fiscal years 2008 and 2007, respectively.

Employee Incentive Compensation Program - SRP has an incentive compensation program covering substantially all regular employees. The incentive compensation amount is based on achievement of pre-established targets. An accrual of $16.6 million and $29.2 million for fiscal years ended April 30, 2008 and 2007, respectively, is included in other current liabilities in the accompanying Combined Balance Sheets. This liability is stated net of receivables from participants in jointly-owned electric plants of $1.6 million and $1.5 million at April 30, 2008 and 2007, respectively.

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INTERESTS IN JOINTLY-OWNED ELECTRIC UTILITY PLANTS:

The District has entered into various agreements with other electric utilities for the joint ownership of electric generating and transmission facilities. Each participating owner in these facilities must provide for the cost of its ownership share.

The District's share of expenses of the jointly-owned plants is included in operating expenses in the accompanying Combined Statements of Net Revenues.

38 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 The following table reflects the District's ownership interest in jointly-owned electric utility plants as of April 30, 2008 (in thousands):

Construction Ownership Plant in Accumulated Work in Generating Stations Share Service Depreciation Progress Four Corners (NM) (Units 4 & 5)...............

10.00%

108,951 (96,353) 6,996 Mohave (NV) (Units 1 & 2)..........................

20.00%

131,803 (129,491)

Navajo (AZ) (Units 1, 2 & 3).......................

21.70%

356,900 (303,301) 5,869 Hayden (CO ) (Unit 2).....................................

50.00%

117,682 (97,076) 1,246 Craig (CO ) (Units 1 & 2)...............................

29.00%

268,911 (186,908) 4,272 PVNGS (AZ) (Units 1, 2 & 3)......................

17.49%

1,274,003 (932,272) 17,746 2,258,250 (1,745,401) 36,129 The Mohave Generating Station (Mohave) ceased operations on December 3 1, 2005, pending installation of new environmental controls and resolution of other operating issues. It is unlikely the plant will reopen as a coal-fired generation source. (See Note (9), Regulatory Issues: Mohave Generating Station, for a discussion of matters pertaining to Mohave.) There remains approximately $2.3 million in net plant value at Mohave for the switchyard and transmission line still used to route power to other inter-tied systems.

(9)

REGULATORY ISSUES:

Fundamental Changes in the Electric Utility Industry - The District historically operated in a highly regulated environment in which it had an obligation to deliver electric service to customers within its service area. In 1998, the Arizona Electric Power Competition Act (the Act) 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, there were only a few customers who chose an alternative energy provider. 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. However, during the past two years, two 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 energy in Arizona. New West Energy intervened in the sole application for which a procedural order has been issued, asking that the application be dismissed until the ACC has held a general rulemaking procedure for retail competition.

All of the applications are pending.

In 1996, the Federal Energy Regulatory Commission (FERC), which regulates the wholesale electric utility industry under the authority of various statutes, issued Orders 888 and 889 requiring transmitting "public utilities" (as defined in the Federal Power Act), to provide nondiscriminatory transmission services to entities seeking to effect wholesale power transactions, and to grant equal access to information concerning the pricing and availability of transmission services. The District is not a public utility under the Federal Power Act but historically has complied with these requirements voluntarily. The Energy Policy Act of 2005 (Energy Policy Act) expanded FERC jurisdiction by granting FERC discretionary authority to regulate the non-rate terms and conditions, and to a lesser extent, rates, under which unregulated transmitting utilities (including the District) provide wholesale transmission services. The Energy Policy Act explicitly prohibits FERC from requiring unregulated transmitting utilities to take actions that would violate a private activity bond rule.

SRP 2008 ANNUAL REPORT 39

Notes to Combined Financial Statements April 30, 2008 and 2007 In its Order 890, issued in February 2007, FERC declined to generically implement its discretionary authority over unregulated transmitting utilities (including the District). FERC determined the authority would be used on a case-by-case basis. The District does not expect Order 890 to result in significant adverse impacts on its operations.

The Changing Regulatory Environment - The District has fully opened its service area to competition in generation and billing, metering and meter reading. The District's electric distribution area remains regulated by its Board, and the District will not provide distribution services in the distribution areas of other utilities.

The District's price plans have been unbundled since 1999. In May 2002, the District implemented a Fuel and Purchased Power Adjustment Mechanism (FPPAM) to allow for semi-annual rate adjustments to recover increases in actual fuel costs. The District has had several increases in the price of fuel and purchased power since the FPPAM was implemented. (See Note (2), Significant Accounting Policies: Rate Stabilization Fund, for additional information.)

In June 2004, the District introduced a Transmission Cost Adjustment Factor (TCAF) to recover costs the District would incur if the District were required to participate in regional transmission organizations. To date, no costs have been incurred or recovered through the TCAF.

On October 1, 2007, the District Board approved a 4.7% system average increase for fuel and purchased power under the FPPAM beginning November 1, 2007. The increase was needed to address an under-recovery of retail fuel and purchased power expenses. The increase is expected to generate annual revenues of approximately $103.7 million.

On March 17, 2008, the District Board approved a 3.9% system average price increase effective May 1, 2008.

The increase was comprised of 2. 1% related to a fuel and purchased power adjustment and 1.8% related to changes in base prices. The increase is expected to generate $91.1 million annually. The new price plans incorporate design changes that better reflect the District's underlying seasonal costs and promote energy efficiency and conservation.

Through a 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 the elderly or impoverished, efficiency programs, demand-side management measures, renewable energy programs, economic development, research and development, and nuclear decommissioning, including the cost of spent fuel storage. In its October 2005 pricing approval, the Board approved additional funding for renewable energy programs, energy efficiency and energy conservation effective beginning November 1, 2005. These surcharges continue to be separately identified and included in the District's price plans for the regulated portion of its operations.

Mohave Generating Station (Mohave) - In 1999, the District and the other Participants in Mohave entered into a settlement with the Sierra Club, the Grand Canyon Trust, and the National Parks Conservation Association, that required the installation of certain pollution abatement equipment by the end of 2005 for the plant to continue operating as a coal-fired electric generating facility. (See Note (11), Contingencies: Air Quality, for additional information on air quality issues.) In addition, the initial term of the agreement with Peabody Western Coal Company (Peabody) to supply coal to Mohave expired at the end of 2005, and the Navajo Nation and the Hopi Tribe demanded that the pumping of water from the Navajo Aquifer for the slurry pipeline serving Mohave cease. The Mohave Participants refused to commit to install pollution abatement equipment without reasonable assurance that water would be available to enable the delivery of coal to the plant. Consequently, the plant suspended operations at the end of 2005.

The Mohave Participants, the Navajo Nation, the Hopi Tribe and Peabody participated in mediation for an alternative source of water for the mine and the slurry pipeline if the life of Mohave were extended, and to resolve other related issues. However, Southern California Edison Company ISCE), operating agent for Mohave, as well as the other two Participants, the Los Angeles Department of Water and Power (LADWP), and Nevada Power Company, advised 40 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 the District in June 2006 that they did not-intend to proceed with efforts to extend the life of Mohave. The mediation efforts continued, but subsequent efforts of SCE to sell the plant as a coal-fired plant, and the District's efforts to acquire the other Participants' interests in the plant, were unsuccessful. Although the District continues to evaluate its options, it is unlikely that the plant will return to service as a coal-fired generation source. The District has included funding in its Capital Improvement Program to cover the costs of alternate resources and has already replaced a portion of the energy it would have received had Mohave continued operations. The District is considering several options for replacing the balance of its energy supply from Mohave including self-build options and purchases from others. (See Note (11 l, Contingencies: Coal Supply Litigation, for a discussion of other related issues.)

During fiscal year 2003, faced.with the complex and contentious issues involved in the mediation noted above, and the potential closure of the plant at the end of 2005, the Board authorized the recovery of the balance of the District's investment in Mohave in its revenue requirements prior to the closure of the plant. Consequently, a write-down of the plant's carrying value of $66.2 million was recorded in fiscal year 2003, and an additional $5.2 million and

$6.6 million of impairment was recorded in fiscal years 2005 and 2004, respectively. In accordance with accounting standards for rate-regulated enterprises (SFAS No. 71 1, a regulatory asset was established for $78.0 million, based on the District's expectation that any unrecovered book value at the end of 2005 would be recovered in future prices.

At April 30, 2008 and 2007, the Mohave net regulatory asset was $59.8 million and $67.6 million, respectively, and is included in deferred charges and other assets on the accompanying Combined Balance Sheets. The Mohave asset is being recovered over a ten-year period which began in fiscal year 2006.

Deferred Charges and Deferred Credits - Deferred charges and other assets consist primarily of the following at April 30 (in thousands):

2008 2007 Bo nd d efea sa nce reg ula to ry a sset............................................................................................................

82,459 86,638 M ohave G enerating Station regulatory asset.......................................................................................

59,804 67,605 N uclear decom m issioning regulatory asset..........................................................................................

10,924 2 1,753 D e riva tive s m a rket va lua tio n.......................................................................................................................

5 8,5 2 0 4 0,8 13 P re p a id p e n sio n b e n e fit co st........................................................................................................................

1 19,7 0 0 D e fe rre d le a se a sse t...................................................................................................................

3 3,2 5 2 3 2,6 3 9 S FA S N o. 15 8 reg u la to ry a sse t.................................................................................................................

4 16,6 2 7 O th e r...................................................................................................................................................................

5 3,5 0 7 5 3,1 1 8 715,093 422,266 Bond defeasance regulatory assets are amortized over different periods, beginning in fiscal year 1997 and ending in fiscal year 203 1. The nuclear decommissioning regulatory asset is being deferred over the life of PVNGS and is being collected through a component of the system benefits charge.

Based on actions of the Board, the District 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, the District would be required to write off the remaining balance of such assets as a one-time charge to net revenues.

SRP 2008 ANNUAL REPORT 41

Notes to Combined Financial Statements April 30, 2008 and 2007 Deferred credits and other non-current liabilities consist primarily of the following at April 30 (in thousands):

2008 2007 A sset re tire m e nt o b lig a tio n..........................................................................................................................

17 7,3 3 1 19 5,0 0 5 A ccrued post-retirem ent benefit lia b ility................................................................................................

597,239 300,000 A ccru ed d e co m m issio n ing co sts..............................................................

17,0 4 5 Pro v isio n fo r co ntra ct lo sse s........................................................................................................................

3 9,7 78 5 3,0 5 9 D e fe rre d le a se in co m e..................................................................................................................................

3 3,5 3 5 3 2,4 4 0 D e riva tive s m a rket va lua tio n......................................................................................................................

5 8 3 9,0 8 5 A ccrued spent nuclea r fuel sto ra g e...............................................

25,0 15 24,586 A ccrued e nviro n m e nta l issues....................................................................

8 7,8 64 83,9 73 O th e r...................................................................................................................................................................

7 1,4 4 0 6 0,6 2 5 1,032,785 775,818 (10)

COMMITMENTS:

Improvement Program - The Improvement Program represents the District's six-year plan for major construction projects and capital expenditures for. existing generation, transmission, distribution and irrigation assets. For the 2009-20 14 time period, the District estimates capital expenditures of approximately $6.3 billion. Major construction projects include construction of Unit 4 at Springerville Generating Station, support for the Coronado Generating Station (CGS)

Emissions Control Project, funding for future generation peaking units, continued participation in the Southeast Valley Transmission Project and other key generation, distribution and transmission projects.

Long-Term Power Contracts - The District entered into three contracts, collectively, with the United States Bureau of Reclamation (United States),. the Western Area Power Administration (WAPA) and the Central Arizona Water Conservation District (CAWCD) for the long-term sale, through September 2011, of power and energy associated with the United States' entitlement to NGS. The amount of energy available to the District varies annually and is expected to decline over the life of the contracts. The District pays a fixed amount under the contracts, pays the cost of NGS generation and other related costs, and supplies energy at cost to CAWCD for Central Arizona Project facilities. The fixed portion of the District's payment obligations under the three contracts totals $47.0 million annually through fiscal year 2011, and $19.6 million in fiscal year 2012. Of the total obligation, $25.2 million annually through fiscal year 2011 and $10.5 million in fiscal year 2012 are unconditionally payable regardless of the availability of power.

Payments under these contracts totaled $92.7 million and $94.4 million in fiscal years 2008 and 2007, respectively.

The District entered into an additional 20-year contract with WAPA, executed September 28, 2007, to purchase NGS surplus power with deliveries to begin June 1, 2012. This purchase is for 300 MW during the eight super-peak hours of the day, June through August, and the term runs through September 30, 203 1. Energy deliveries are contingent on NGS generation and payments are made only for actual energy delivered. There is no minimum payment obligation for this contract.

The District entered into two other long-term power purchase agreements to obtain a portion of its projected load requirements through 201 1 and has an agreement in place for the extension of one of the agreements through May 2016, with the possibility of a further extension to 2021 if certain conditions are met. Minimum payments under these contracts are $37.6 million annually through fiscal year 2011 and $1.9 million thereafter. Total payments under these two contracts, including the minimum payments, were $76.4 million and $71.0 million in fiscal years 2008 and 2007, respectively. In conjunction with the impairment analysis performed on generation-related operations, the District 42 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 has recorded provisions for losses on these contracts. The provisions recorded in August 1998, of $163.7 million, are being amortized over the life of the contracts, commencing January 1, 1999. Amortization of $13.3 million has been reflected as a reduction in purchased power expense in fiscal years 2008 and 2007. The remaining liability at April 30, 2008 of $39.8 million is included in deferred credits and other non-current liabilities in the Combined Balance Sheets.

Beginning on September 1, 2006, the District has 1 00 MW of capacity from Springerville Generating Station Unit 3, pursuant to a 30-year power purchase agreement. Minimum payments under this contract are $26.0 million annually through fiscal year 2012 and $636.0 million thereafter. Total payments on this contract during the year ended April 30, 2008 were $42.7 million, including minimum payments.

The District has entered into a 20-year power purchase agreement with Snowflake White Mountain Power, LLC, which is a renewable energy resource utilizing biomass products to produce power. The agreement requires the District to purchase a minimum of 78,840 MWh during fiscal years 2008 through 2023 and to purchase the full energy output, approximately 20 MW, during fiscal years 2024 through 2028. The District is obligated to pay only if the facility produces power under this agreement. The facility began commercial power production in June 2008.

Fuel Supply - At April 30, 2008, minimum payments under long-term coal supply contract commitments are estimated to be $180.8 million in fiscal year 2009, $180.8 million in fiscal year 2010, $181.8 million in fiscal year 2011,

$125.6 million in fiscal year 2012, $120.3 million in fiscal year 2013, and $343.7 million thereafter.

In May 2006, the District sold a natural gas pipeline to El Paso Natural Gas Company (EPNG). The District maintains options to purchase an ownership interest in the pipeline and also holds a perpetual right of first refusal with EPNG if EPNG desires to sell the pipeline. Accordingly, the District recorded a deferred asset and an offsetting deferred income amount in the accounting records. The deferred asset will be depreciated and the deferred income recognized over the life of the Santan Generating Station, which is the generating station served by the pipeline. The balance of the deferred asset at April 30, 2008 and 2007, was $33.3 million and $32.6 million, respectively, and included in deferred charges and other assets in the Combined Balance Sheets. The balance of the deferred income at April 30, 2008 and 2007,was $33.5 million and $32.4 million, respectively, and included in deferred credits and other non-current liabilities in the Combined Balance Sheets.

Long-Term Natural Gas Purchase Agreement - In October 2007, the District entered into a 30-year gas purchase agreement (Gas Purchase Agreement) with Salt Verde Financial Corporation (SVFC), an Arizona nonprofit corporation formed for the primary purpose of supplying natural gas to the District. Under the agreement, the District is committed to purchase 294,550,000 MMBtu (million of British thermal units) of natural gas, which is expected to supply approximately 20% of its projected natural gas requirements needed to serve retail customers over the 30-year period. The District receives a discount off of market prices and is obligated to pay only for gas delivered. To fulfill its obligation, SVFC entered into a 30-year prepaid gas agreement with Citigroup Energy Inc. SVFC financed the purchase by the issuance of its special obligation gas revenue bonds (Bonds). The Bonds do not constitute a debt, liability or obligation of the District.

The District has evaluated the prepaid gas transaction under FIN No. 46R, "Consolidation of Variable Interest Entities, an Interpretation of Account Research Bulletin No. 5 1" (FIN No. 46R), which provides guidance on the identification and consolidation of entities for which control is achieved through means other than voting rights. Under FIN No. 46R, SVFC is deemed a variable interest entity. However, while the District retains rights to any residual assets in SVFC, the majority of the risk from the transaction is absorbed by parties other than the District and, therefore, the District is not SRP 2008 ANNUAL REPORT 43

Notes to Combined Financial Statements April 30, 2008 and 2007 deemed SVFC's primary beneficiary for purposes of FIN No. 46R. Accordingly, the District accounts for the transaction under the equity method. Other than the District's commitment to purchase gas supplied under the Gas Purchase Agreement, its maximum exposure under this transaction is $100,000.

Springerville Generating Station - In 2001 the District entered into an agreement with UniSource Energy Development Company (UniSource) for the joint development of two additional coal-fired generating units (Units 3 and 4), approximately 400 MW each in size, to be located at the existing Springerville Generating Station. Under an amendment to the agreement, dated October 20, 2003, the District entered into a 30-year power. purchase agreement (the PPA) to purchase 100 MW of capacity from Unit 3, which was developed by Tri-State Generation and Transmission Association, Inc. Unit 3 was placed in service in September 2006, beginning the 30-year term of the PPA. In addition, the District received the right to construct the fourth unit (Unit 4) at any time during the term of the PPA. The District originally held such rights in a wholly-owned subsidiary, Springerville Four, LLC, but such rights were assigned to the District on February 1, 2007, and Springerville Four was dissolved in April 2007. The District has begun construction of Unit 4 and expects it to be in service b.y the end of calendar year 2009. As of April 30, 2008, the District has recognized $500.9 million of construction costs which are included in construction work in progress in the Combined Balance Sheets. The Springerville 4 Project is anticipated to cost approximately $1.0 billion.

UniSource's affiliate, Tucson Electric Power Company (TEP), operates Units 1, 2 and 3 and will operate Unit 4 upon completion. (See Note (11), Contingencies: Air Quality, for a discussion of a challenge to the Unit 4 air permit by the Sierra Club.)

Nuclear Insurance - Under existing law, public liability claims arising from a single nuclear incident are limited to $10.8 billion. PVNGS Participants insure for this potential liability through commercial insurance carriers to the maximum amount available ($300.0 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 $ 100.6 million including a 5% surcharge; applicable in certain circumstances, but not more than $15.0 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 $52.8 million, including the 5% surcharge, but would be limited to $7.9 million per incident in any one year.

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). The DOE was responsible for the selection and development of a repository for permanent storage and disposal of spent nuclear fuel not later than December 31, 1998. However, the DOE delayed submitting an application to construct a permanent repository at Yucca Mountain Nevada until June 2008. A decision on licensing is not expected until at least 2010 and the facility is unlikely to open until at least 2017. Because of the significant delays in the DOE's schedule, it cannot be determined when the DOE will accept waste from PVNGS or from the other owners of spent nuclear fuel. It is unlikely, due to PVNGS' position in DOE's queue for receiving spent fuel, that Arizona Public Service Company (APS), the operating agent of PVNGS, will be able to initiate shipments to DOE during the licensed life of PVNGS. Accordingly, APS has constructed an on-site dry cask storage facility to receive and store PVNGS spent fuel. The facility stored its first cask in March 2003. Fifty-three casks are now stored on site.

The District's share of on-site interim storage at PVNGS is estimated to be $37.1 million for costs to store spent nuclear fuel from inception of the plant through fiscal year-end 2008, and $2.8 million per year going forward. These costs have been included in the District's regulated operations price plans for transmission and distribution.

44 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 Coal Supply Litigation - Navajo Nation v. Peabody (U.S. Dist. Court, D.C. District - RICO Case) - In 1999, the Navajo Nation filed a lawsuit in the United States District Court in Washington D.C. (the "U.S. District Court") in which the Hopi Tribe later was joined as a plaintiff. The lawsuit arises out of negotiations culminating in 1987 with amendments to the coal leases and relatdd agreements. The Navajo Nation and the Hopi Tribe allege that 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, had improperly induced the U.S. Department of the Interior to not approve the coal royalty rate proposed by the Navajo Nation in violation of the federal racketeering statutes. They further alleged that the Department's failure to approve the rate caused the tribes to negotiate and settle upon a substantially lower royalty rate. The suit alleges $600.0 million in damages. The plaintiffs also seek treble damages against the defendants, measured by any amounts awarded under the racketeering statutes. In addition, the plaintiffs claim punitive damages of not less than $1.0 billion. In 2001, the claims of both the Navajo Nation and the Hopi Tribe were dismissed in their entirety with respect to the District, but the dismissal is appealable.

On February 9, 2005, the U.S. District Court granted a motion to stay the litigation until further order of the court while the parties were in mediation with respect to this litigation and related business issues. In November 2007, the parties jointly filed a status report in the District Court, stating that they had failed to resolve the lawsuit and terminating the District Court mediation. Hence, the parties have requested that the District Court terminate the stay and restore the case to the active docket.

Navajo Nation v. United States (Court of Federal Claims) - In an earlier case filed by the Navajo Nation against the United States and based on allegations similar to those raised in the RICO Case, the U.S. Court of Appeals for the Federal Circuit held that the Navajo Nation had a cognizable money-mandating claim against the United States for breach of trust and that the United States had breached its duties to the Navajo Nation. The Court of Appeals remanded the case to the Court of Claims for proceedings consistent with its ruling. The Court of Claims again found that the United States had not breached any compensable duty of trust owed to the Navajo Nation. On appeal, the Court of Appeals again reversed the Court of Claims. The United States then sought, but was denied, rehearing of the order of the Court of Appeals. In May 2008, the United States filed its petition for a writ of certiorari with the U.S.

Supreme Court seeking reversal of the Federal Circuit Court Appeals decision in this matter.

Peabody Legal Fees Cases - Peabody claims it is entitled to reimbursement under both the NGS Coal Supply Agreement and the Mohave Coal Supply Agreement for its costs associated with the defense of the challenges by the Navajo Nation and Hopi Tribe to these coal leases (see above matters). Peabody has filed two separate lawsuits in the Superior Court of Arizona against the NGS and Mohave Participants, respectively, seeking recovery of these fees. The Mohave and NGS Participants dispute Peabody's attempt to recover its legal costs under the coal supply agreements.

In the NGS legal fees case, the Maricopa County Superior Court dismissed Peabody's claims for legal fees against the NGS Participants. The Arizona Court of Appeals affirmed the dismissal and a petition for review to the Arizona Supreme Court was denied. Thus the decision is final.

As for the Mohave legal fees case, the Mohave Participants and Peabody had executed a settlement agreement pursuant to which Peabody had granted the Mohave Participants a waiver for fees incurred prior to January 2006.

However, the lawsuit for fees arising after December 2005 remained until December 17, 2007, when the court ruled among other matters that the Mohave Participants were not responsible for Peabody's legal fees incurred in the RICO Case. The District has agreed to dismiss without prejudice its counterclaims relating to Peabody's alleged agency until the RICO Case has been completed.

Peabody v. the District (the St. Louis Case) - In October 2004, Peabody also filed suit in St. Louis, Missouri, against the District and the other owners of NGS. Peabody asserted claims of tortious interference with contracts and tortious SRP 2008 ANNUAL REPORT 45

Notes to Combined Financial Statements April 30, 2008 and 2007 interference with business expectancies against the District and claims against all NGS Participants for reimbursement of any damages relating to liability associated with the RICO Case; alleged breach of the NGS Coal Supply Agreement; and breach of indemnity obligations owed to Peabody as the alleged agent of the NGS Participants. Peabody seeks

$500.0 million in damages for the breach of contract claim and unspecified compensatory damages, prejudgment interest, attorneys' fees and costs on the other claims. This case is in its discovery phase and is still pending. The District and Peabody have agreed to dismiss this case without prejudice until completion of the RICO Case.

District v. Peabody (the RHCC/FRC Case) - The NGS Participants are contesting their alleged liability for mine closing, final reclamation, mine decommissioning and environmental monitoring costs, and certain post-retirement health care and life insurance benefits that Peabody will pay or provide to its employees after termination of the NGS Coal Supply Agreement and associated closure of the Kayenta Mine. On December 3, 2007, the District approved and executed, on behalf of the NGS Participants, a proposed settlement and mutual release agreement with Peabody.

All the Participants have approved the settlement, but it awaits the final signature of one Participant.

Except as indicated, the District is unable to predict the likely outcome of the coal supply litigation matters at this time but does not believe that the final resolution of these matters will have material adverse effects on its operations or financial condition.

Environmental - SRP is subject to numerous legislative, administrative and regulatory requirements relative to air quality, water quality, hazardous waste disposal and other environmental matters. SRP conducts ongoing environmental reviews of its properties for compliance and to identify those properties it believes may require remediation. Such requirements have resulted, and will continue to result, in increased costs associated with the operation of existing properties.

In September 2003, the District received notice from the U.S. Environmental Protection Agency (EPA) that it is potentially liable under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) as an owner and operator of a facility (the 1 6th St. facility) within the Motorola 52nd Street Superfund Site. The District may be liable for past costs incurred and for future work to be conducted within the Superfund Site. Investigation and evaluation of this potential liability are in the preliminary stages, but initial soil vapor investigations indicate minimal contamination on site. The District is unable at this time to predict the outcome, but believes that it has adequate reserves for this potential liability.

The EPA is continuing its national enforcement initiative under the New Source Review (NSR) provisions of the Clean Air Act (CAA). This initiative is focused on determining whether companies had failed to disclose major repairs or alterations to facilities that, in the opinion of the EPA, would have required the installation of new pollution control equipment. As part of this initiative, the District received four letters from the EPA, requesting.information on CGS. In March 2004, the District entered into negotiations with the EPA regarding possible additional control technology to reduce emission levels from District generating units. To date, the EPA has taken no enforcement action against the District for alleged violations of NSR regulations at CGS. The District anticipates a resolution with the EPA that would require installation of additional controls at CGS. Any additional controls would also be consistent with Best Available Retrofit Technology (BART) requirements for the generating station. The District is unable at this time to predict the outcome, but believes that it has adequate reserves for this potential liability.

Several species listed under the Endangered Species Act IESA) have been discovered in and around Roosevelt and Horseshoe Dams. The District entered into formal negotiations for an Incidental Take Permit (ITP) with the U.S. Fish and Wildlife Service (USFWS), and developed a Habitat Conservation Plan (HCP), which allows full operation of Roosevelt Dam and Reservoir, provided the District established habitats for the species in other areas or 46 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 through other measures. The District engaged in similar negotiations with the USFWS to obtain a permit for operation of the Horseshoe and Bartlett Dams on the Verde River. The USFWS issued a permit for operation of Roosevelt Dam in 2003 and a separate permit for operations on the Verde River in May 2008. Pursuant to the ITP with the USFWS, the District established a Trust Fund as of May 2008 to pay mitigation expenses related to the HCP. The Trust was funded with $13.2 million, and is expected to pay mitigation expenses into perpetuity.

Air Quality - In December 1999, the Participants in Mohave Generating Station settled a lawsuit alleging numerous and continuing violations of opacity and sulfur dioxide standards. Under the terms of the settlement, the Participants were required to install by January 1, 2006, a sulfur dioxide scrubber and other pollution control equipment. Major plant modifications, including emissions controls, are required for continued operation as a coal-fired plant. Capital costs were estimated at $1.0 billion, of which the District's share would be $211.3 million. These costs were included in the capital contingencies portion of the 2007-2012 Improvement Program. However, as discussed in Note (91, Regulatory Issues: Mohave Generating Station, the uncertainty in post-2005 coal and water supply caused the Mohave Participants to be unwilling to make the necessary investments and funding was removed from the District's 2008-2013 Improvement Program.

Electric utilities are subject to continuing environmental regulation. Federal, state and local standards and procedures that regulate the environmental impact of electric utilities are subject to change. These changes may arise from continuing legislative, regulatory and judicial action regarding such standards and procedures. Consequently, there is no assurance that facilities owned by the District will remain subject to the regulations currently in effect, will always be in compliance with future regulations, or will always be able to obtain all required operating permits. An inability to comply with environmental standards could result in additional capital expenditures to comply, reduced operating levels, or the complete shutdown of individual electric generating units not in compliance. Although the prospect for new CAA legislation in 2008 is low, as a result of the legislative and regulatory initiatives, the District is planning emission reductions at its coal-fired power plants.

The EPA issued regulations for the control of mercury emissions from coal-fired generating stations in 2005. Arizona opted into the federal mercury program in 2006 and imposed additional mercury emissions limitations which would have required the District to install additional controls at CGS and Springerville Unit 4 to achieve 90% mercury removal. In addition, the District has been participating with the EPA in the development of a plan to control mercury emissions on the Navajo Reservation, where the District owns an interest in two generating stations, NGS and Four Corners. However, on February 7, 2008, the U.S. Court of Appeals, D.C. Circuit, vacated the EPA rules in response to a suit by 11 states that had challenged the rules as not protective enough of public health and contrary to the CAA. The EPA will promulgate new mercury rules in response to the court's decision. While the District is evaluating the implications of the decision, it is likely that additional controls will be required at all coal-fired plants in which the District has an interest. The District is still evaluating compliance options and cannot yet estimate the associated costs.

On May 6, 2008, pursuant to the citizen suit provision of the CAA, the Sierra Club challenged the issuance of the air permit for Units 3 and 4 of the Springerville Generating Station. The Sierra Club stated that the owners of the units had violated the CAA by having received a permit without a determination of the maximum achievable control technology IMACTI standards. While it is too soon to predict the outcome of this matter, the District believes that all necessary environmental permits and determinations have been obtained, including the required MACT determination.

In June 2005, the EPA also issued final amendments to its July 1999 regional haze rule. These amendments apply to the provisions of the regional haze rule that require emissions controls known as BART for coal-fired power plants and other industrial facilities that emit air pollutants that reduce visibility. The amendments include final guidelines for states to use in determining which facilities must install controls and the types of controls that facilities must use. States and SRP 2008 ANNUAL REPORT 47

Notes to Combined Financial Statements April 30, 2008 and 2007 tribes were required to complete BART determinations for eligible facilities by the end of 2007, although Arizona did not meet that deadline and it is uncertain whether it will do so by the end of 2008 or in 2009. BART controls must be installed five years after the EPA has approved a state's BART determination. The District has financial interests in several coal-fired power plants that may be subject to the new BART requirements. The District submitted a BART analysis to the EPA in Hovember 2007 for NGS, and to the Arizona Department of Environmental Quality (ADEQ) in February 2008 for CGS. BART analyses have also been completed for several other coal-fired plants in which the District has financial interest. The District cannot predict whether the EPA will approve Arizona's BART determination, and if approved what its financial impact will be on the District.

The District recognizes the growing importance of the issues concerning climate change (global warming) and the implications they could have on its operations, so it is closely monitoring related developments at the federal, state and regional levels. Efforts to cap or tax emissions of carbon dioxide from fossil fuel power plants will substantially increase the cost 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. 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 is assessing the risk of policy initiatives on its generation assets and is developing'contingency plans to comply with 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 California Legislature has enacted laws that could impact the District. Under one such law, the California Public Utilities Commission ICPUC) and the California Energy Commission (CEC) must implement regulations that, among other things, prohibit procurement of electricity from a coal-fired power plant for five years or longer and restrict investments in coal-fired plants. LADWP, one of the participants in NGS, and SCE, a participant in Four Corners Units 4 and 5, are subject to the regulations and may be precluded from approving certain expenditures at the plants, including capital improvements. The regulations except expenditures for "routine maintenance"; however, no definition is provided. SCE has petitioned the CPUC to exclude financial contributions required under pre-existing contract obligations for Four Corners; the petition is pending. The California Air Resource Board is also developing an economy wide cap-and-trade program for greenhouse gases. The CPUC and CEC released joint recommendations on how to regulate emissions from the electricity sector. The regulations could impact the District's ability to sell excess generation into California. If the implementing regulations prohibit or penalize the sale of energy generated by a coal-fired plant, the District could lose California as a market for its wholesale generation; however, the District has other options for marketing its wholesale generation. The District is monitoring and participating in the development of these regulations to determine the full extent of their impact on the District and the plants in which it has an interest. Based on available information, the District cannot estimate or predict the impact of the California laws on it at this time.

Voluntary Contributions in Lieu of Taxes - The Arizona Department of Revenue (ADOR) challenged the District's exclusion of contributions in aid of construction (CIAC) in calculating the total value of District property for purposes of computing voluntary contributions in lieu of taxes (in-lieu contributions) paid by the District. While the District obtained a favorable ruling from the Arizona State Board of Equalization, the Arizona Tax Court subsequently rendered a favorable decision to the ADOR on appeal. The District appealed the decision of the Arizona Tax Court to the Arizona Court of Appeals. The Court of Appeals ruled in the District's favor on January 19, 2006. The ADOR then filed a petition for review of this decision with the Arizona Supreme Court, which was denied. The denial ended the litigation. At issue had been the District's liability for approximately $13.8 million plus interest for fiscal years 2003 (four months), 2004 (12 months), and 2005 (eight months). In fiscal year 2007, the District recognized $15.5 million 48 SRP 2008 ANNUAL REPORT

Notes to Combined Financial Statements April 30, 2008 and 2007 of income due to the reversal of previously recorded reserves resulting in the reduction of other operating expenses in the accompanying combined financial statements as of April 30. For calendar years 2005 and forward, legislation was passed that codifies the exclusion of CIAC from the in-lieu contributions formula. In addition, the State of Arizona in 2005 reduced the assessment ratio for calculation of in-lieu contributions in Arizona beginning in calendar year 2006. The rate of 25% that was in effect prior to calendar year 2006 was reduced to 20% over a 1 0-year period.

Because the tax year was based on a calendar year, the first reduction for in-lieu contributions affected only four months of the District's fiscal year 2006. Fiscal year 2007 was the first full fiscal year for the District, with the continual reduction through fiscal year 2016, when the assessment ratio was to reach 20%. Reduction of the assessment ratio to 20% was expected to produce a cumulative savings of approximately $1.5 million per year.

However, in 2007, Arizona accelerated the assessment ratio reduction from 10 years to six years by reducing the rate 1 % per tax year (for each of the remaining four years) instead of the 1/2% reduction that had been in place, thus achieving the reduced rate of 20% by calendar year 201 1. The accelerated reduction is expected to result in an additional cumulative savings of approximately $6.4 million in voluntary contribution expense from fiscal year 2008 through fiscal year 2013.

California Energy Market Issues - Numerous FERC proceedings are addressing various aspects of the California energy market crisis of 2000 through 2001. Several of these proceedings involve potential refunds. Because the District bought from and sold power to the California energy market, the District has been drawn into many of the proceedings. However, the District was a net buyer in the California market during the time periods being scrutinized, and believes it is entitled to refunds if any are ordered. The District has received approximately $22.2 million in refunds as of April 30, 2008. In May and June 2008, FERC approved an additional $1.6 million in refunds which the District received in June 2008.

Indian Matters - From time to time, SRP is involved in litigation and disputes with various Indian tribes on issues concerning regulatory jurisdiction, royalty payments, taxes and water rights, among others (see Coal Supply Litigation and Air Quality above). Resolution of these matters may result in increased operating expenses.

Water Rights - The District and the Association are parties to a state water rights adjudication proceeding encompassing 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.

The United States, on behalf of the Gila River Indian Community (GRI Community), filed a lawsuit in 1982 in the Federal District Court, District of Arizona, to protect the water right claims of the GRI Community. The Association is among the many defendants named in this lawsuit. The lawsuit claims that the defendants' use of surface water and groundwater violates the GRI Community's rights to water in certain specified areas, and requests a decree specifying the GRI Community's rights, injunctive relief to stop the alleged illegal use of water by the defendants, and damages for increased costs to the GRI Community from, among other things, having to deepen its wells. In 2004, the United States enacted the Arizona Water Rights Settlement Act, which resolves the claims of the GRI Community listed above as well as many of the claims in the Gila River Adjudication.

In 1978, a water rights adjudication was initiated in the Apache County Superior Court with regard to the Little SRP 2008 ANNUAL REPORT 49

Notes to Combined Financial Statements April 30, 2008 and 2007 Colorado River System. TheDistrict 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.

The cities of Prescott and Prescott Valley, together with the Town of Chino Valley, have announced 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. SRP opposes these plans because it believes that such pumping would deplete the base flow of the Verde River, which is captured and stored by two reservoirs on the Verde River for delivery to Association shareholders. This dispute is still in its early stages and SRP cannot predict the outcome at this time. SRP has agreed to engage in formal mediation with the cities in an attempt to resolve its concerns about the water supply. However, SRP does not believe the dispute will have a significant financial impact on the District or the Association.

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 - The District maintains various self-insurance retentions for certain casualty and property exposures.

In addition, the District has insurance coverage for amounts in excess of its self-insurance retention levels. The District 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 the District's financial position or results of operations.

50 SRP 2008 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 Water Users' Association In our opinion, the accompanying combined balance sheets and the related combined statements of net revenues and comprehensive income (loss), and cash flows present fairly, in all material respects, the financial position of Salt River Project Agricultural Improvement and Power District and its subsidiaries and the Salt River Valley Water Users' Association (collectively, "SRP") at April 30, 2008 and 2007, 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 thesestatements 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.

As discussed in Note 7 to the combined financial statements, SRP changed the manner in which it accounts for defined benefit postretirement plans in fiscal 2008.

A,ý r - £cdf4 PricewaterhouseCoopers LLP 400 Campus Drive P.O. Box 988 Florham Park, NJ 07932 Telephone (973) 236-4000 Facsimile 1973) 236-5000 June 12, 2008 SRP 2008 ANNUAL REPORT 51

SRP Boards DistriE/Division 5 Carl E. Weiler District/Division 8 Deborah S. Hendrickson Director-at-large, seat 14 Wendy L. Marshall The two Boards work with management to establish policies to further the business affairs of SRP The Salt River Valley Water Users' Association (the Association) is SRP's private water corporation, which administers the water rights of SRP's 375-square-mile water service area, and operates and maintains the irrigation and drainage system.

The 10 members of the Association Board of Governors serve staggered four-year terms and are elected from voting districts by the landowners within the water service territory.

The 10 SRP voting areas for SRP Boards and Councils are included in the Salt River Reservoir District boundaries.

The Salt River Project Agricultural Improvement and Power District (the District) is SRP's public power utility and a political subdivision of Arizona. The 14 members of the District Board of Directors serve staggered four-year terms. Ten District Board members are elected from voting divisions and four are elected at-large by landowners within the District's boundaries. Most often, candidates seek election to both Boards.

Notes: Robert G. Kemptan District/Division 8 Board member, resigned September 28, 200 Dale C. Riggins Jr.

District/Division 9 Board member, term ended May 5, 2008.

• Resigned March 31, 2008; vacant seat.

52 SRP 2008 ANNUAL REPORT

SRP Councils The two Councils enact and amend bylaws relating to the governance of SRP and also serve as liaisons to District electors and Association shareholders.

As with the SRP Boards, there is one Council for the Association and one for the District. The 30 Association Council members are elected to staggered four-year terms from 10 districts. The 30 District Council members are elected to staggered four-year terms from 10 divisions. Most often, candidates seek election to both Councils.

District/

Division 1 District/

Division 2 Kevin J. Johnson District/

Division 3 District/

Division 4 District/

Division 5 District/

Division 6 Aft District/

Division 7 Harmen Tjaarcd Jr.

Mark A. Lewis District/

Division 8 Mark L. Farmer District/

Division 9 District/

Division 10 W. Curtis Dana Notes: Edward E. Johnson District/Division 9 Council member, term ended May 5, 2008.

• • Vacant seat.

Orland R. Hatch William P. Schrader Jr.

SRP 2008 ANNUAL REPORT 53

D. Michael Rappoport David G. Areghini Jane D. Alfano Richard M. Hayslip Mark B. Bonsall Barbara M. Hoffnagle John F Sullivan Corporate Officers Corporate Headquarters John M. Williams Jr.

President David Rousseau Vice President Terrill A. Lonon Secretary Steven J. Hulet Treasurer Executive Management Richard H. Silverman General Manager David G. Areghini Associate General Manager Power, Construction & Engineering Services Mark B. Bonsall Associate General Manager Commercial & Customer Services Richard M. Hayslip Associate General Manager Environmental, HR, Land/PPC, Risk Management & Telecom D. Michael Rappoport Associate General Manager Public & Communications Services John F. Sullivan Associate General Manager Water Group Jane D. Alfano Corporate Counsel Barbara M. Hoffnagle Assistant General Manager Information Technology & Operations Support Services Street address SRP 1521 N. Project Drive Tempe, Arizona Mailing address SRP PO. Box 52025 Phoenix, AZ 85072-2025 Financial Inquiries Dean Yee, Manager, SRP Financial Services (602) 236-5231 Requests for Annual Reports For additional copies of this report, or SRP quarterly reports, call SRP at (602) 236-2598.

Changes to Mailing List For corrections or other changes to the mailing list for this report, call SRP at (602) 236-2564.

Bondholder Information For all bond information, call the SRP Treasury Department at (602) 236-2222.

www.srpnet.com 54 SRP 2008 ANNUAL REPORT

A minute or two, please. Your thoughts are important to us.

We would appreciate your completing this survey or your feedback online at www.srpnet.com/reportsurvey.

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[] Power customer D] Financial analyst F1 Elected official D] SRP employee

[] Other 1 =Strongly disagree 2=Disagree 3=Neutral 4=Agree 5=Strongly agree

2. I look forward to receiving the SRP Annual Report.

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4. The Annual Report gave me a better picture of what's going on at SRP 1

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7. I prefer to receive Annual Report information online.

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8. I read all or a significant portion of the (check all that apply):

E] Letter to Electric Customers, Water Shareholders & Bondholders D] Letter from the General Manager D] Power, Water, Environmental & Community Features ED Management's Financial & Operational Summary ED Combined Financial Statements and Notes 00 L71 10 CD "0

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U4 mn c-M (D)

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Five-Year Operational and Statistical Review Financial Data ($000) 2008 2007 2006 2005 2004 Total operating revenues............

$ 2,739,123

$2,630,733

$2,521,970

$2,251,723

$2,077,314 Retail electric revenues.......

2,212,807 2,054,652 1,885,912 1,709,213 1,622,305 W ater revenues..........

14,339 12,893 12,036 12,786 11,818 O ther revenues...........

511,977 563,188 624,022 529,724 443,191 Total operating expenses 2,416,908 2,213,544 2,139,702 1,815,538 1,867,397 Total other income, net........

58,104 90,224 158,966 31,902 28,615 Net financing costs..................

123,216 139,623 125,834 105,637 115,605 Net revenues for the year.................

257,103 367,790 415,400 362,450 112,220 Taxes and tax equivalents...........

93,376 97,607 100,953 105,475 100,693 Utility plant, gross...

1....

10,866,410 9,912,865 9,384,134 9,043,377 8,726,559 Long-term debt.......................

3,679,929 3,041,408 2,893,017 2,727,348 2,912,849 Electric revenue contributions to support water operations 47,017 34,792 34,161 56,672 62,925 Selected Data Debt service coverage ratio..............

2.82 3.09 2.42 2.39 2.00 Debt ratio (percent).....

48.9 45.7 47.9 50.1 55.2 Total electric sales (million kW h).........

33,998 33,872 32,658 32,577 31,714 Peak-SRP retail customers (kW)...

6,578,000 6,590,000 6,044,000 5,665,000 5,673,000 Water deliveries (acre-feet)*.....

854,093 870,165 860,584 890,424 Runoff (acre-feet)*

696,550 456,318 2,055,554 702,974 Employees at year end.............

4,431 4,388 4,328 4,336 4,267 Customers at year end 928,992 919,422 892,875 858,314 824,416

• Water data is by calendar year; all other data is by fiscal year ending April 30.

Pw-a www.srpnet corn 08-0522-01 Printed on recycled paper.

77 tý 1 1, j

i -U+/-

20 UAL: REPORT I

I I if

'~

f*~ Af; 1ý i

I Pinedale Natural Gas Reserves Project WYOMING NEVADA

'(

Lake Tahoe C%

Salt Lake City 0 Intermountain Converter Station I

UTAH Southern Transmission System Las

[

San Juan Unit 3 0 Farmington NEW MEXICO Los Barnett Natu[l Gas Reserves Project TEXAS Anaheim -

Azusa -

Southern Transmission System Project Mead-Phoenix Transmission Project Mead-Adelanto Transmission Project I

Palo Verde Nuclear Generating Station Hoover Uprating Project San Juan Generating Station

-i Magnolia Power Project Ormat Geothermal Project Pinedale Natural Gas Reserves Project l

Barnett Natural Gas Reserves Project Member Agencies I

W hat is SC PPA ?..............................

2 M ission Statem ent.............................

2 V isio n

.......................................2 SCPPA Officers and Staff........................

3 President's Letter..............................

4 Executive Director's Letter......................

5 SCPPA's Quest for New Energy Sources...........

6 TABLE OF CO\\

N S Operations and Projects Palo Verde Project..........................

8 San Juan Unit 3 Project.....................

10 Mead-Phoenix/Mead-Adelanto Transm ission Projects...................

12 Hoover Uprating Project....................

14 Southern Transmission System Project........ 16 Magnolia Power Project....................

18 Pinedale Natural Gas Reserves Project....... 20 Barnett Natural Gas Reserves Project......... 22 Ormat Geothermal Project.................

24 Financing Activities...........................

26 Legislative Report.............................

27 M unicipalities................................

30 Selected Financial Data and Statistics...........

32 Combined Summary of Financial Conditions..... 33 Accounting and Investment Group..............

33 Statistics of SCPPA Members...................

34

What sSI PPA?

outhern California Public Power Authority (SCPPA), with headquarters in Pasadena California, is a joint powers agency comprising eleven municipal utilities and one irrigation district. SCPPA's members consist of the municipal utilities of Anaheim, Azusa, Banning, Burbank, Cerritos, Colton, Glendale, Los Angeles, Pasadena, Riverside, Vernon, and the Imperial Irrigation District.

Together they deliver electricity to over two million customers in the southern California basin, spanning an area of 7,000 square miles, and with a total population that exceeds five million. Formed in 1980, SCPPA was created for the purpose of providing joint financing, con-struction and operation of trans-mission and generation projects.

Today, SCPPA fulfills a wide range of services for its members by providing effective forums of collaboration through commit-tees such as Customer Service, q,

Finance, Public Benefit Programs, Resource Planning, Transmission and Distribution, Engineering and Operations, Natural Gas, and Renewable Energy Resources.

mission SCPPA provides financing and oversight for large joint projects in the electric utility industry and through coordinated efforts, facilitates, imple-ments, and communicates information relative to issues and projects of mutual interest to its mem-bers as determined by the Board of Directors.

In order to support its primary purpose, SCPPA is also involved in legislative advocacy, contracting for support services, information sharing, training and regulatory monitoring on behalf of its mem-bers. To accomplish its mission, SCPPA is:

• Not-for-profit (public agency)

• Governed locally (locally elected officials)

• Customer owned (no stockholders seeking high profits)

" Vertically integrated (focuses on and remains responsible for power supply, transmission, dis-tribution, and customer service)

" Meeting local mandates of obligation to serve by planning to meet long-term needs of cus-tomers through ownership of generation and/or transmission and long-and-short term contracts for power supplies or transmission

• Providing diversity of power supplies, including renewable resources (solar, wind, and electric generation from geothermal, and landfill gas)

" Optimizing its energy resources, and

• Providing aggressive, local demand-side man-agement programs.

The Authority currently has five generation proj-ects and three transmission projects in operation, generating and bringing power from Arizona, New Mexico, Utah, and Nevada.

In addition, SCPPA has interest in two natural

• [**

gas reserve projects. Its latest gen-eration project, a combined cycle natural gas-fired generating plant with a nominally rated net base capacity of 242 megawatts, is whol-ly owned by the Authority and began commercial operation in 2005.

vision SCPPA will provide cost-effective joint action services that supplement member programs and activities, and that secure long-term physical supplies at predictable pricing levels for usage in power generation to assure continued member success.

SCPPA's projects have been financed through the issuance of tax-exempt bonds, backed by the combined credit of the SCPPA members partici-pating in each project. As of June 30, 2007, SCPPA had issued $10.4 billion in bonds, notes, and refunding bonds, of which $1.9 billion was outstanding. It is backed by one the highest credit ratings, and is rated AAA-by Moody's and Standard and Poor's.

(I 2l

/

From left to right:

Bill Carnahan, Executive Director; Marcie Edwards, Vice President; David Wright, President I

From left to right: Richard Helgeson, General Counsel; Craig Koehler, Finance and Accounting Manager; Steve Homer, Project Administrator; Salpi Bouboushian, Administrative Analyst; Manny Robledo, Energy Systems Manager; Phyllis Brown, Government Affairs Manager; Bill Carnahan, Executive Director; and Geri Mitchell, Office Manager.

3

I President alifornia has called on utili-ties to increase renewable resources in their total power mix by the year 2010. SCPPA's j

~members have made the commit-ment to meet or exceed this goal, and currently receive renewable energy each year through Green Power agreements, including land-fill gas, wind, solar, and geothermal. SCPPA's members are striving to attain a renewable power mix of 20% by 2010, and 33% by 2020. SCPPA is committed to sustainable, renewable resources like solar and wind, and is continuing to find new ways for its members to ensure that energy supplies remain abundant.

One of the ways SCPPA has been successful, is developing a common vision for its members and a basis for joint action through its strategic planning process. Over the years, SCPPA's success has been largely attributable to the mem-ber's effective use of joint action. In its visionary planning, SCPPA's members have added locally-owned generation, with the addition of the Magnolia Power Project (MPP), its first wholly-owned' and operated power plant that began operation in 2005. MPP operates under the most stringent environmental standards in the nation, and serves the com-munities of Anaheim, Burbank, Cerritos, Colton, Glendale, and Pasadena. The members also realized a need to hedge the volatile natural gas prices and invested in natural gas reserves. SCPPA also continues its commitment in renew-able energy with its latest request for proposals and consid-eration for additional renewable resource supplies.

SCPPA has evolved from its historical role of providing financing for our members' generation and transmission projects. SCPPA serves the members in many other ways by providing effective forums of collaboration through commit-tees such as Customer Service, Finance, Public Benefit

Programs, Resource

Planning, Transmission and Distribution, Engineering and Operations, Natural Gas, and Renewable Energy. In addition to assisting the members with best practices, it also serves as a conduit for joint con-tracting for services and fuel acquisition for power genera-tion, as well as, acquisition of natural gas reserves, and renewable supplies such as wind and geothermal. Today, SCPPA participates in five major generation projects and three transmission projects, bringing electricity to Southern California from Arizona, Nevada, New Mexico and Utah.

SCPPA also has interests in two natural gas reserve projects, providing a secure source of gas for its participants. On a combined basis, SCPPA's members currently deliver electric-ity and services to over five million people.

SCPPA remains alstrn a* oate on t Z ua9rfot ont~ner:*2*

yfronts asw l,

n 1 \\

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v ve eJ

• DýJ-s t t aswelldcontes d fed-eral levels to protect represented customersby!zassuring adequate resources, reliabiit',.x. and/re/onsibilit'ytlto the

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\\1 ý communities we proud iy-serve.P-'SCPPA:.membersb*.elieve that local contrkois at the heart of utility governance with local elected bodi- 'est able to make decisions regarding electric provicd thaýt\\,serve their commd1ites SFCPPA members also w6oko ersure that state and',national/regula-tion is in the best-interest ofntheir customers and t4h6envi-ronment. SCPPFr

,emrers hel,'ed shpth '"

eg4inl"

,Gors elp

• pe the "energy\\lnde-pendence" bilI tultimatey.pa.ssedthelHouse and Senate, by advocatlngknJee-ded refor'msandexpansios to the Clean Rerewable Energy Bond (CREB) programIand seeking sponsors forkey Blls to achieve those goals. SCP'PA

" If I ý,'K 10 tI s.

advocated for tDe-eetension\\of tax1 credits for commerciaI and residenmtial.building--efficie `y-msuresan'-ýincentl ves for plug-inhybtid'electtic vehicles (PHEVs) and urged their legislators /tsupportinclusion of those measures. SCP(PA also joined the Amer~icanPublic Power Associbtion (APPA) and othern tility organizationsinyopposing anteffor{ inthe House toxep'eal provis*ons in theEPct 05 th6ft directed five federal agenciý,to jointly designt'orridor over'fede'ral lands for, gas pipelines aand electric transmission and' distri-bution lines.

Designation of these fede'ral 'orridors is important to SCPPA.and other consumer-owned electric utilities in Califorinia'that are engaged in efforts to build, new transmission facilities to increase electric reliability and facij-itate development of geothermal resources located near the'

,Salton: Sea.

By working together, SCPPA members are providing and delivering reliable service, at competitive and stable' rates.

Whether it is pioaictive advoc'acy, impa'cting energy legisla-tion and regulation-in California or at the Federal level, or collectively meeting our commitments for green power and renewable energy resources, SCPPA members are working together to successfully meet the challenges in California's electric energy industry. By taking the necessary steps today, we can assure that we are in a position to serve and meet the energy demands of our customers in the future. We look forward to taking these steps together.

David H. Wright President

Execut ve D© f"",Sputhern California Public Power Authority continues in its role to meet the challenges facing the electric

• industry by acquiring additional reliable energy sources, for its members. In meeting the renewable power mandat6,'wind energy power was added to its portfolio with the addition of two wind projects: the Milford Wind Corridor, and Pebb'le" Springs Wind Projects. The Milford Wind Corridor Phiase I Projict c6nsisting of 200 MW, will be locat-ed in Utah. Wind pow.er will be delivered to SCPPA through the IPP switching statia

'r.I ated in Delta, Utah. The term of theoproject is for 20d,eafs with commercial operation expect-

.ed 'tb' omner ce.i Ki' I~late'ý ý2008..Th-Pebble Springs.Wind Project is approximktely 100 MW and will be located in Oregon. ThIe, wind power is scheduled to be delivered to SCPPA through the p rojci substation by late 2008. The term of the project is for 18 yearý, including a right of first offer fol-lowing the tenth contract year. Both wind projects are in the final planning stages, and participant approval is expected in the near future.

SCPPA is acquiring additional reliable energy sources, con-tinuing in its commitment to its members. Following the suc-cessful completion'o.0f-,Rha§s6e Iof the acquisitionof.in-.ground reserves this past yer in.Wyoming and Texas,'zSCPPA devel-oped 6" Natural G as Preayment Program'e'signed.to add additional stabili tyin the-paicipant's fuel: pbrtfolios. The Natural Gas Prepayment Program consists of the acq isition of the right to receive an ag~re'ate amouf't oaf proirmate-ly 129 billion cubic.feet :.of..natural gas over 30 years from a supplier pursuant to the terms of Prepaid Natural Gas Sales Agreements. Te Gas Prepay'ment Program was divided into two projetý';,!ith the cities '46f1,naheiiýn, Burbank, Co0ton, Glendale, and Pasadenaas Project No' 1 'and Los1'Angeles Departmentlof Water Power as% Proje'&t No..2: Project NO.1 is expected tetcompleted l6atK this2year, wi Pbroject No 2 following I inearly 2008. This strucurer'will pr6vid' flexibility and will benefit the participants ri severalways.'

rst it wYil lock in natural gas prices on a discounted, basis. It, will enhance the reliablity of supply through a long-term prepaid contract and.supplier diversification{,.and provide substantial

.:savings ov e r time It also'oo'idesJf& a favorab*.e isk alloca-tion so that.all debt service payments

'by.SPPA'associated with the, issuance of tax.-exempt bonds' for ithe prepayment' and gas'*ýpayments by SCPPA pati cipants 'are contingent.

upon the idelivery of the gas. It includes several termination events to unwind the structure atao.cstto SCPPA. Rj*atingt agenicis haepoie

aoal, eiw of natural 'gas pr~e-pay dealsand',

excude

.atural prepay bon.ds from' the calulaio'of 2the"'SCPPA par~ticipants' debt "calculation.

SCPPIA)sl'inthe process, of neggtiating the agreements, on behalfof interested pa'rticipants, and this project is in its final rector's Leotter The Authority consists of its twelve r

members (Anaheim, Azusa, Banning, Burbank, Cerritos, Colton, Glendale, the Imperial Irrigation District, Los Angeles, Pasadena, Riverside, and Vernon), and collectively delivers electricity and provides services to over two million customers. Proudly serving as its Executive Director, now in my eighth year, I am honored to have been associat-ed with SCPPA for most of its existence. Traditionally, SCPPA's investments have been in the areas of coal, hydro-electric, natural gas-fired generation, and nuclear, as well as high voltage transmission to deliver electric energy to California. Over the past year, SCPPA's success has continued with the addition of renewable energy sources as well.

SCPPA continues to grow at a record setting pace with the addition of its latest wind projects and, together with the Natural Gas Prepayment Project, will experience another 30% in growth. Over the past two years, the number of proj-ects has almost doubled.

This phenomenal growth and continued success has been attributable to the member's effective use of joint action.

Through visionary planning, SCPPA's members have not only added locally-owned generation.with the addition of the Magnolia Power Project, but investment in natural gas reserves to hedge against volatile natural gas prices as well.

SCPPA also continues its commitment in renewable energy with its latest request for laroposals and consideration for additional renewable resource supplies, such as wind, and geothermal.

The success and growth of SCPPA has provided the mem-bers with the ability to maintain the local demand for energy.

With the continued uncertainty in California's electricity

industry, SCPPA will continue to proactively assist its mem-bers in aggressively meeting new challenges. Over the years, SCPPA's success has been attributable to the collective and visionary leadership of its members. Working together, we know that we will be positioned to face the new challenges Within our industry.

K~i79 BillID. Carnahan Executive Director

outhern California Public Power Authority continues in its commitment to acquire additional reliable energy sources for its members. Following the successful acquisition of the in-ground reserves this past year, SCPPA developed a natural gas prepayment program designed to add an additional layer of stability in the Participant's fuel portfolios and address the volatility and unpredictability of the natural gas market. Following an extensive Request for Proposals process, Goldman Sachs & Co., in con-junction with their commodities division, J. Aron, was selected as the gas supplier for their industry experience, to assist SCPPA in putting together a long-term natural gas prepayment structure.

SCPPA formed a separate Gas Prepayment Project solely for the purpose of issuing natural gas prepayment debt, differentiating it from all other SCPPA Project debt. The Natural Gas Prepayment Program consists primarily of the acquisition of the right to receive an aggregate amount of approximately 129 billion cubic feet of natural gas from the supiplier over a 30-year peri-od pursuant to the terms of Prepaid Natural Gas Sales Agreements. SCPPA will be able to offer discounted gas to the Project Participants through separate Gas Supply Contracts with each Project Participant.

To effectuate the prepayment, SCPPA will issue tax exempt bonds to prepay the gas supply.

Payment from the Participants for the natural gas supply, when delivered, will be sufficient to pay bond debt service. Safeguards have been built in so that payment obligation to bondholders shifts to the gas supplier if the supplier defaults or fails to deliver the gas. By entering into a gas price swap, the participants convert their discounted fixed price to a discounted index price. The swap eliminates price risk and the participants can hedge gas price exposure for various terms at advantageous times in the market, entirely out-side of the gas prepayment transaction. The Gas Prepayment Program was bifurcated into two projects; with the cities of Anaheim, Burbank, Colton, Glendale, and Pasadena as Project No. 1, and Los Angeles Department of Water & Power as Project No. 2. Project No. 1 is expected to be completed later this year, with Project No. 2 fol-lowing in early 2008. SCPPA is in the process of negotiating the agreements, and this project is in its final stages of completion.

In response to the renewable energy mandate of 20% by 2020, SCPPA's participants have been positioning their portfolios to add renewable energy sources as well. To assist the members, SCPPA has issued Request for Proposals for

Renewable Energy Projects to solicit competitive proposals for up to 300 megawatts (MW) of renewable energy, through facility ownership or power purchase agreements with an early buyout option, in one or more renewable energy facili-ties. In response to the RFP, SCPPA is pursuing several renewable energy projects.

Two such projects, the Milford Wind Corridor, and Pebble Springs Wind Project, are currently being planned. The Milford Wind Corridor Phase I Project is a 200 MW wind power project planned to be located in the Beaver and Millard Counties of Utah. The wind power will be delivered to SCPPA through the Intermountain Power Project switching station located in Delta, Utah. The term of the project is 20 years with an expected com-mercial operation in late 2008. An early buyout option is included in the agreement after the tenth contract year. There is an anticipated pres-ent value cost savings of approximately $42 mil-lion as compared to a straight purchase of the facility on the commercial operation date. Similar to other SCPPA projects, the Milford Wind Corridor project will be paid for entirely by the participants (LADWP, Burbank, and Pasadena).

The project will have no fiscal impact on non-par-ticipating members, with the exception of a small decrease in administrative and general expenses.

A second wind project, Pebble Springs Wind Project, is a 98.7 MW wind project, and is planned to be located in Gilliam County, Oregon. The wind power is scheduled to be delivered to SCPPA through the project substa-tion by late 2008. SCPPA, along with LADWP, Burbank, and Glendale, will be responsible for transporting and scheduling the energy from the project substation to the Project Participants at the Nevada Oregon Border (NOB) through either an agency agreement with LADWP or other means. The term of the project is for 18 years with a right of first offer after the tenth contract year, which allows SCPPA the right of first offer to purchase the project prior to it being offered for sale to another party. Both wind projects are in the final planning stages, with approval by the participants expected in the near future.

In addition, SCPPA is also considering other renewable energy projects, including biomass and geothermal projects, which are in the early stages of development. As a Joint Action Agency, SCPPA continues to find new ways to bring value to its members so they remain posi-tioned to meet the challenges within our indus-try. Working together, SCPPA's member utilities continue to leverage their talents, resources, and financial strength to collectively bring sustainable and reliable energy sources to their customers.

PRODUCTION COST (Operation and Maintenance plus Nuclear Fuel)

Calendar Year Cents per kWh 1993 2.02 1994 1.93 1995 1.61 1996 1.45 1997 1.33 1998 1.28 1999 1.25 2000 1.25 2001 1.27 2002 1.28 2003 1.32 2004 1.45 2005 1.63 2006 2.07 2006-2007 OPERATIONS Burbank/Glendale/Pasadena (4.4% each)

Azusa/Banning/Colton (1% each)

Percentage of SCPPA member participation in Palo Verde Project Generation (Millions of MWHs)

Capacity Utilization

(%)

Vernon ----

1]

Imperial Irrigation District --

m Unit 1 Unit 2 Unit 3 Aggregate 8.9 9.6 9.7 28.2 77.0%

83.5%

89.2%

83.2%

Riverside -z Los Angeles --

% 10%

2 I

3 I

0% 10% 20% 30% 40%

50% 60%

T he steam generators in Unit 1 were successfully replaced during the fall of 2005. Unit 2's steam genera-tors were replaced in 2003, and Unit 3's steam genera-tors will be replaced in 2007.

UNDT 3 OPERATUONS r

"pi

F ive SCPPA participants own 41.8% of Unit 3 at the San Juan Generating Station, a coal-fired plant in New Mexico. A series of Interim Invoicing Agreements for fuel has led to high capacity factors and lower per unit fuel costs.

The underground mine is performing well, and the plant is embarking on a major environmental upgrade project.

Unit 3's major work is scheduled for January 2008.

Glenale -in Percentage of SCPPA member participation Banning in San Juan Project Cnton -

Azusa -

impedal Imgafon Distict I

I I

I I

I 6

0% 10% 20% 30% 40% 50% 60% 70%

he two 500-kV transmission lines, which connect Phoenix to Las Vegas, and Las Vegas to Southern California, completed their ninth year of dependable operation for the nine SCPPA members who participate in the projects.

Pasadena -

Percentage of SCPPA Glendale -

member participation in Mead-Phoenix Project Burbank -

Azusa/Banning/Colton (1% each)

Riverside -

Anaheim -

Los Angeles -

0% I I

I I

I 0%

!0%

20% 30% 40% 50% 60% 70%

Pasadena --

Glendale -

Burbank -

Colton -

Banning -

Azusa -

Anaheim/Riverside (13.5%

each)

Lvs Angeles Percentage of SCPPA member participation in Mead-Adelanto Project I

I I

I I

I I

0%

10% 20% 30% 40% 50% 60% 70%

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T he Hoover Uprating Project continues to provide six SCPPA members with low-cost, renewable energy (hydro). A SCPPA representative is active in the implementation of the Lower Colorado River Multi-Species Conservation Program.

Burbank -

Percentage of SCPPA member participation in Coton --

Hoover Uprating Project Banning -

I Azusa --

Riverside -

Anaheim --

I I

I I

I I I 0% 10% 20% 30% 40% 50% 60% 70%

s usual, the STS operated with near-perfect availability (99.02%), delivering over 14.2 million MWHs to the six SCPPA members who are participants. The power comes 488 miles from the Intermountain Power Project, in Utah, over the +/- 500-kv DC line.

Pasadena -

Percentage of SCPPA member participation in Southern Glendale -

Transmission System Project Burbank Riverside -

Anaheinm Los Angeles -

0% 10% 20% 30% 40% 50% 60% 70%

16

d, Pasadena Glendale Burbank Colton Anlaheim Cermno m

Percentage of SCPPA member participation in Magnolia Power Project

-1 0

I I

I I

I I

I 0% 10% 20% 30% 40% 50% 60% 70%

C onstruction was completed on the Magnolia Power Project, a 240 megawatt natural gas-fired, combined cycle plant, located on the site of an existing plant in the City of Burbank. This is the first project to be wholly-owned and operated by SCPPA members.

The Participants are Anaheim, Burbank, Cerritos, Colton, Glendale, and Pasadena.

Anaheim -

Burbank -

Colton -

Glendale -

Pasadena -

Los Angeles -

Turlock Percentage of SCPPA member participation in Pinedale Natural Gas Reserves Project Los Angeles and Turlock hold their interests individually. Anaheim, Burbank, Colton, Glendale, and Pasadena have ownership through SCPPA. Los Angeles serves as Project Manager for the overall project, and SCPPA provides services for Los Angeles and Turlock under agency agreements.

I I

I I I I

0%

10% 20% 30% 40% 50% 60% 70% 80%

CPPA negotiated its first pur-chase of gas in the ground, with the deal closing July 1, 2005.

SCPPA Members Los Angeles, Anaheim, Burbank, Colton, Glendale, and Pasadena joined together with the Turlock Irrigation District to purchase shares of exist-ing natural gas wells in the Pinedale area of Wyoming. This purchase, along with similar future purchases, will provide a secure source of gas for the participants, and hedge against volatile prices in the market.

4L I

//

l

I n 2006, SCPPA members purchased a share of natural gas leases in the Barnett Shale area of Texas.

Anaheim h

Burbank --

Percentage of SCPPA member participation in Barnett Natural Gas Reserves Project Colton --IU Glendale -

Pasadena -411 LosAngeles -

Turlock -

I I

I I

I I

I 0% 10% 20% 30% 40% 50% 60% 70% 80%

Turlock holds its interest individually. Anaheim, Burbank, Colton, and Pasadena have ownership through SCPPA.

SCPPA receives net revenues through a joint operating agreement with Devon Energy Production Company, L.P.

WOM--

nl

..1 CPPA Members Anaheim, Banning, Glendale, and Pasadena began receiving a total of five MW of geothermal energy from the Gould Geothermal Plant in Heber, California, on a long-term purchase contract with Ormat.

Additional megawatts are to become available in the near future.

Percentage of SCPPA member participation in Ormat Geothermal Project Glendale Banning Anaheim -

Pasadena -

0%

I I

I I

I 5

0% n0% 20% 30% 40% 50% 60% 70%

F,.

i 4'k

n July 2006, SCPPA executed an amendment to the Southern Transmission System Project

$100 million, floating-to-floating Fixed-Spread basis swap originally entered into in 2004, with the issuance of a Constant Maturity Swap (CMS).

Under the amended swap transaction, SCPPA will continue to pay the swap counterparty, JPMorgan, the BMA index but will receive 58.99% of the 10-Year LIBOR plus 616.4 basis points in lieu of the 1-month 65% of LIBOR. The amended swap terms will become effective August 2007. The notional amount of the swap remains at $100 million and the swap will expire in July 2023. The expected gross savings to SCPPA are estimated at $24.3 million.

For the primary purpose of completing the Magnolia Power Project, SCPPA issued $37.7 mil-lion par value Magnolia Power Project A, Revenue Bonds, Series 2006-1. The bonds, issued at a premium, generated $38.6 million of new money proceeds and received a True Interest Cost of 4.13%.

In connection with its outstanding Mead-Adelanto Transmission Project bonds, SCPPA executed a CMS in January 2007 with Bear Stearns Financial Products, Inc. (BSFP). BSFP was selected as the swap counterparty based on the results of a competitively bid RFQ for swap provider and request for gross spread bids. The transaction consisted of a $100 million CMS, with an effective forward starting date of February 2008, whereby SCPPA pays BSFP 100% of 1-month LIBOR in exchange for receiving 100% of the ten-year Constant Maturity LIBOR swap rate minus 41.4 basis points. The swap expires in September 2030. Based on historic averages, the expected gross savings are $29.2 million.

In April 2007, SCPPA entered into an interest rate swap in connection with the issuance of variable-rate Magnolia Power Project A, Refunding Revenue Bonds, Series 2007-1. The swap created synthetic fixed-rate debt, and consisted of a $223 million, 29-year floating-to-fixed interest rate swap allocated equally between two counterpar-ties, Citigroup and Bear Stearns Financial Products, Inc. (BSFP). SCPPA pays each of the counterparties a fixed rate of 3.912% in exchange for receiving 98.9% of the BMA Index minus 6 basis points. The swap's effective date is July 13, 2007, with a forward starting date of July 1, 2008 for the variable interest and swap payments. The swap expires on July 1, 2036.

SCPPA issued $223.3 million of Magnolia Power Project A, Refunding Revenue Bonds, 2007-1 Series as variable rate demand obligations that will initially bear interest at a weekly interest rate.

The bonds were issued in June 2007, and were used to refund $202.4 million of the Magnolia Power Project A Bonds, Revenue Series 2003-1.

For this transaction, SCPPA also entered into two separate floating-to-fixed interest rate swap agreements that effectively fixed the rate of the 2007-1 Bonds. The expected gross savings to SCPPA are estimated at $22.5 million.

Other Refunding and Financing Transactions SCPPA's Finance Committee continues to look for new financing opportunities and to lower financing costs through bond refundings. At fis-cal year-end, financing to complete a Prepaid Gas Program, takeout for the gas reserves bridge loan, upgrade to the Southern Transmission System Project, and several renewable energy projects were under way or anticipated.

he policy direction of the 2007-08 Session Tof the California State Legislature contin-Tued where the prior session ended, focus-ing on the environment, climate change and the reduction of greenhouse gas emissions. While less dramatic than 2006 and with the perennial challenges to public power's local control, surpris-ingly legislative results were mixed at the conclu-sion of this first year of the two-year session.

Geological Survey, to develop and adopt stan-dards and regulations governing geologic car-bon sequestration; the bill remains in the Assembly Natural Resources Committee. Both bills could see legislative activity early next year.

The effort to increase California's Renewable Portfolio Standard (RPS) for the generation of electricity from 20% by 2010 to 33% by 2020 stalled this year for a variety of reasons, including iinuw~~V REO RT Of notable importance is the California Global Warming Solutions Act state law, which requires technologically feasi-ble and cost-effective green-house gas emissions reduc-tions to the 1990 level by 2020.

Addressing transportation-related carbon emissions, Assembly Bill 118 authored by Speaker Fabian Nunez would retire high polluting vehicles and fund air quality improve-ment projects. Successfully surviving the legislative process, the Governor signed the Speaker's bill on October 14th, 2007.

Related

bills, Assembly Bill 114 by Assemblymember Sam Blakeslee and Assembly Bill 705 by Assemblymember Jared Huffman, addressed carbon capture and carbon seques-tration, respectively, but failed to move out of their House of origin. Specifically, Assembly Bill 114 would require the California Energy Commission to recommend containment scrub-bing and capture technologies to decrease car-bon dioxide emissions from thermal power plants; the bill was held in the Assembly Appropriations Cornmittee. Assembly Bill 705 would require the Division of Oil, Gas and Geothermal Resources, with the California Environmental Protection Agency and the the state's well-know transmis-sion challenges. With both bills, SCPPA members suc-Scessfully fought off attempts to change current law that authorizes each locally pub-licly-owned electric utility to implement and enforce its own RPS while recognizing the state's commitment to invest in renewables.

Assembly-member Lloyd Levine's Assembly Bill 94 and Senator Joe Simitian's Senate Bill 411 are parked in the Assembly. Both bills could see legislative activity early next year. Assembly Bill 809, authored by Assemblymember Blakeslee, relaxed the definition of eligible renewable resources and would allow incremental increases, due to energy efficiency measures, in electricity generated from existing small and large hydro facilities count toward the RPS. Assembly Bill 809 was signed by Governor Schwarzenegger on October 14th and becomes law on January 1,2008.

Attempting to address the challenges of sitting and permitting solar facilities and associated transmission, Assemblymember Paul Krekorian's Assembly Bill 940 remains in the Assembly Appropriations Committee with the possibility of action next year. Relying on solar, an eligible 27

legls atl renewable for RPS purposes, for heat-ing hot water was the subject of Assemblymember Huffman's Assembly Bill 1470. With SCPPA conveying to the Governor's office words of support for Assembly Bill 1470, the bill received his signature on October 12th, 2007. Of equal importance, is the goal to reduce the amount of electricity consumed by replacing incandescent light bulbs with compact fluorescents and was the sub-ject of two bills introduced by Assembly members Levine and Huffman. Levine's bill, Assembly Bill 772, and Huffman's bill, Assembly Bill 1109, both sought to prohibit the sale of incandescent light bulbs. Assembly Bill 1109 additionally would require manufacturers, where pos-sible, to eliminate the use of toxic heavy metals such as lead and mercury. On October 12th, the Governor signed Assembly Bill 1109 which becomes effective on January 1, 2008.

Without doubt, this year's greatest chall local control was presented in Senate The bill would apply only to municipal utilities, largely SCPPA members, anc have transferred authority to evaluate Ioc bution systems from local governing b the state, specifically the California Commission. SCPPA member cities fou unwarranted legislative move and, in E Senate and Assembly, Republicans vote in opposition, both activities culminati likely veto by the Governor with the col the proponents' attempt in a matter of September 5th, 2007. While SB 980's pro abandoned their effort for the year, if ti revived in 2008, it is certain SCPPA mem continue their commitment to local gov and perseverance to maintain over the local distribution system.

In Washington, D.C., the November, 2(

gressional elections gave Democrats a ve Report (continued) in both the House of Representatives and Senate and the new leaders quickly announced that "energy independ-ence and climate change initiatives would be at the top of their legislative agenda. House Speaker Nancy Pelosi (D-CA) and Senate Majority Leader Harry Reid (D-NV) listed enactment of a federal Renewable Portfolio Standard (RPS), increasing Corporate Average Fuel Economy (CAFE) requirements, more tax incentives for renewable resources and mandatory carbon diox-ide (C02) emissions controls as high pri-orities for the 110th Congress.

Although there was an initial blizzard of introduced bills, hearings and other activities on global warming, key legis-lators soon realized that there were sig-nificant barriers to swift passage of a comprehensive climate change pro-gram, including concerns about the lack of commercial-scale carbon capture and enge to sequestration technology, the impact on the U.S.

Bill 980.

economy and participation by developing electric nations. For that reason, congressional leaders would decided to postpone drafting a comprehensive

al distri-climate change policy and, instead, develop a bill oards to that would take "smaller steps" towards reduc-Energy ing greenhouse gas emissions, increasing energy ught the efficiency and promoting domestic renewable

)oth the energy resources.

d solidly ng in a Under the leadership of Board President Dave lapse of Wright, SCPPA members helped shape the hours on "energy independence" bills that ultimately ponents passed the House and Senate, by advocating he bill is needed reforms and expansions to the Clean bers will Renewable Energy Bond (CREB) program and

'ernance seeking sponsors for key bills to achieve those ir cities' goals, H.R. 1821, introduced by Rep. Jim McDermott (D-WA) and S. 1870, sponsored by Sen. Maria Cantwell (D-WA). The CREB program,

)06 con-authorized in the Energy Policy Act of 2005 majority (EPAct 05), provides a financial incentive, through

Legislatve R the tax code, for consumer-owned utilities to develop clean renewable resources. The fact that both H.R. 1821 and S. 1870 garnered significant numbers of co-sponsors was key to the adoption of provisions to reform and expand CREB bond-ing authority in the House and Senate Finance Committee-passed energy tax titles. SCPPA also advocated for the extension of tax credits for commercial and residential building efficiency measures and incentives for plug-in hybrid elec-tric vehicles (PHEVs) and urged their legislators to support inclusion of those measures.

Provisions on both issues were included in both the House and Senate committee-passed ver-sions of the energy independence bills.

SCPPA joined the American Public Power Association (APPA) and other utility organizations in opposing an effort in the House to repeal pro-visions in the EPAct 05, which directed five feder-al agencies to jointly designate corridors over federal lands for gas pipelines and electric trans-mission and distribution lines. Designation of these federal corridors is important to SCPPA and other consumer-owned electric utilities in California that are engaged in efforts to build new transmission facilities to increase electric reliability and facilitate development of geother-mal resources located near the Salton Sea. This effort on federal lands also complemented suc-cessful efforts by SCPPA who worked, again with APPA, to defeat an amendment advanced by Reps. Maurice Hinchey (D-NY) and Frank Wolf (R-VA) to prohibit the Department of Energy (DOE) and the Federal Energy Regulatory Commission (FERC) from using any funds for the implementa-tion of Section 1221 (a) of the EPAct 05 designat-ing National Interest Electric Transmission Corridors (NEITC) and providing FERC with fed-eral backstop transmission sitting. As a result, the Hinchey-Wolf amendment was defeated on the House floor, by a vote of 257-174.

SCPPA worked to inform and educate federal legislators on the impacts of state legislation --

AB 32 and SB 1368 -- on consumers served by the e p o r t (coo tued) six SCPPA members that are participants in the Intermountain Power Project. SCPPA representa-tives urged Members of Congress and staff to consider carefully California's programs as they craft federal climate change legislation, to avoid imposing duplicative or conflicting requirements on SCPPA member utilities. SCPPA advocated an "economy wide" approach to federal and state greenhouse gas emissions controls, to ensure that the electric customers do not bear a dispro-portionate share of the costs of climate change initiatives. SCPPA also informed its congressional delegation about active efforts by SCPPA mem-bers to encourage energy efficiency and acquire renewable resources. Further, SCPPA educated offices about its proposed transmission projects, including the Green Path North Project, under-taken with the Los Angeles Department of Water and Power, and the proposed Southern Transmission System (STS) upgrade, among oth-ers. As the end of the first session of the 110th Congress approached, Congress had not yet rec-onciled the differing versions of the House and Senate "energy independence" bills. Decisions about whether to include in the final bill a feder-al RPS, mandate increased production of alterna-tive fuels, and higher vehicle efficiency standards were among the controversies remaining to be resolved. Also undecided were a number of tax issues, with legislators divided on how to transfer the amount of federal incentives from the oil and gas industries to developers of renewable resources and energy efficiency'measures.

M UN IC IPAL IT IES Marcie L. Edwards General Manager Anaheim Public Utilities Dept.

Joseph F. Hsu Director of Utilities City of Azusa Light & Water City of Anaheim Since 1894, Anaheim Public Utilities' vision for serving customers has extended well beyond a responsibility to provide reliable, cost-effective electricity and water. Whether we are planning a new substation; building a renewable energy resource; replacing overhead electrical facilities with underground trans-mission, distribution and service cables; or offering new efficiency incentives, we seek long-term solutions to issues that will strengthen Anaheim's neighborhoods, schools and businesses far into the future. The business decisions we make are about providing multiple benefits that are in the best interests of our entire community. We find that outreach is a contagious philosophy as well. The more people we involve in the process, the greater our capability for turning obstacles into opportunities. We reach out to businesses to produce partnerships that create energy savings, reduce demand and save money. We team up with other City departments to increase efficiency and improve operations. Our residential electric rates average more than 25 percent less than in surrounding cities while our Electric System revenue bond rating was raised to AA-.

City of Azusa The City's electric utility was established in 1898 after the City purchased a private power company. The foresight and planning of those early pioneers continues to be the cornerstone of Azusa Light

& Water today. It is the mission of Azusa Light & Water to provide reliable and cost effective electric and water util-ities to the citizens and businesses within its service area, Azusa Light & Water continues to be proactive in pro-moting energy and water conservation programs to its customers, and to its future customers by continual fund-ing of a resource conservation education program with the local school district.

City of Banning The City of Banning Electric Utility provides electric service to more than 12,200 metered accounts covering an area of over 22 square miles. The Public Utility was established in 1922 and has an energy resource base including portions of coal, nuclear, hydro, and geothermal generating plants, which pro-vide the majority of electricity required to meet the City's summer peak demand of 48 MW. The Utility has numer-ous Public Benefit programs promoting energy conservation and renewable resources. In addition, the City sup-ports clean energy and is committed to increasing its renewable resource mix to meet and exceed its RPS require-ments. The Utility is dedicated to continue providing quality service to its customers in a safe and reliable man-ner, at reasonable rates.

City of Burbank Burbank Water and Power (BWP) began serving both water and electric customers in 1913 and installing on-site power generation in the 1 940s. BWP is committed to providing reliable electric serv-ices and safe water supply to its customers while keeping rates stable and competitive. BWP's power supply comes from a variety of resources including hydro, natural gas, coal, nuclear facilites and renewable projects throughout the West. Today, BWP independently operates about 135 MW of gas-fired capacity. The most recent development at BWP is the Magnolia Power Plant, a combined cycle generating unit owned and financed through Southern California Public Power Authority (SCPPA) on behalf of its six municipal utility members. BWP is the oper-ating agent for the Magnolia Power Project (MPP) and has a 90 MW share of the jointly owned Magnolia facility.

MPP has a nominal capacity of 242 MW and a peaking capacity of 310 MW.

City of Cerritos The first new member to join Southern California Public Power Authority in over 20 years, the City of Cerritos is preparing to serve the electricity demands of its residential and. business communi-ties. To further these efforts, Cerritos is participating in the Magnolia Power Project. With the goal of providing a stable and affordable supply of electricity, Cerritos intends on developing a diverse portfolio of power to be deliv-ered as competitively and economically as possible.

James D. Earhart Electric Utility Director City of Banning Ronald E. Davis General Manager Burbank Water and Power Art Gallucci City Manager ciy of Cerritos CJ

City of Colton Colton Electric Utility continually looks for ways to improve electric service to our cus-tomers. We remain focused on communication, education, and reliability. We strive to improve the quality of com-munication with our customers, keeping our customers informed on issues such as climate change, and improve the reliability of our service through a myriad of programs designed to strengthen both our team of employees and our electric system. Colton Electric Utility is proud to serve the long term energy needs of our community.

City of Glendale Incorporated in 1906, Glendale purchased its electric utility in 1909, obtaining power from outside suppliers. In 1937, it began receiving power from the Hoover Dam and inaugurated the first unit of its own steam generating plant units with 258 MW of gas-fired steam and combustion generating capac-ity. Glendale Water & Power (GWP) has a diversified portfolio that also includes coal, nuclear, and hydro generat-ing resources, as well as a comprehensive renewables resource program in landfill gas, wind, and geothermal projects. Today, GWP provides reliable electric services to over 83,600 residential, commercial and industrial cus-tomers within a 33 square mile area. GWP continues to invest in improving the system infrastructure to ensure its long-term reliability.

Imperial Irrigation District The Imperial Irrigation District (LID) was established in 1911 and entered the power business in 1936. Proudly serving Imperial and Coachella valleys and a portion of San Diego County, liD's 6,571-square mile service area is one of the fastest growing regions in California. liD controls over 1,100 MW of energy derived from a diverse resource portfolio that includes native generation, SCPPA partner-ships, and long-and short-term power purchases. A valuable public resource, lID is regarded as an affordable and reliable service provider serving over 140,000 customers.

Los Angeles Department of Water and Power Providing service for more than a century, the Los Angeles Department of Water and Power began delivering water to the city in 1902, and with the water came power. In 1916, LADWP first delivered electicity to the city purchased from the Pasadena Municipal Plant. A year later, LADWP began generating its own hydroelectric power at the San Francisquito Power Plant No. 1. After purchasing the remaining distribution system of Southern California Edison within the city limits in 1922, LADWP became the sole water and electricity provider for the City of Los Angeles. It is now the largest municipally owned electric utility in the nation, serving a population of 4.0 million residents over a 465 square mile area. LADWP remains on firm financial footing and serves as a valuable asset to the City of Los Angeles.

City of Pasadena PWP has been providing electricity since 1906 and began delivering water to customers in 1912. The city built its first electric generating steam plant in 1907 and took over operation of its municipal street lighting from Edison Electric. In 1909, Pasadena began the extension of its operations to com-mercial and residential customers that resulted in the replacement of all Edison Electric service in the city by 1920.

While a lot has changed over the years, PWP's strong connection to its customer/owner base remains constant.

Today, PWP provides electric service to more than 62,000 metered accounts over a 23 square-mile service area at competitive rates. PWP's success is a result of its commitment to remain a valued community asset, an excep-tional employer, and a partner in Pasadena's prosperous future.

City of Riverside The City of Riverside Public Utilities began serving both electric and water cus-tomers in 1883. Today we serve 105,200 metered electric customers and 63,400 metered water customers, rep-resenting a service area population of over 287,800. The utility is committed to the highest quality water and elec-tric services at the lowest possible rates to benefit the community. To maintain their commitment, Riverside has positioned itself well in the electric market by utilizing short, mid and long-term contracts from power suppliers, and by building power generation sources within its own power grid, including a 40 MW power plant in 2002 and the completion of a 99.6 MW power plant in June 2006. Riverside's portfolio includes 27 MW of renewable resources, which includes 523 kW of photovoltaic systems within the city.

City of Vernon Vernon's Utilities Department began serving industrial customers in 1933, with com-pletion of its diesel generating plant. In addition to its own power from diesel units and gas turbines, Vernon also receives power from Palo Verde, Hoover, and various suppliers. Vernon recently completed (October 2005) the con-struction of its Malburg Generating Station, a gas-fired combined cycle power plant with a net generating capac-ity of 134 MW. The Malburg Generating Station resides within the city limits. Vernon is part the California Independent System Operator (CAISO) Control Area and is a Participating Transmission Owner.

Participant Ownership Interests The Authority's participants may elect to participate in the projects. As of June 30, 2007, the members have the following participation percentages in the Authority's operating projects:

GENERATION TRANSMISSION NATURAL GAS Ormat Palo Hoover San Magnolia Geo-Mead-Mead-Verde Uprating Juan Power thermal STS Phoenix Adelanto Participants Pinedale Barnett City of Los Angeles City of Anaheim City of Riverside Imperial Irrigation District City of Vernon City of Azusa City of Banning City of Colton City of Burbank City of Glendale City of Cerritos City of Pasadena 67.0%

5.4%

6.5%

4.9%

1.0%

1.0%

1.0%

4.4%

4.4%

42.6%

31.9%

4.2%

2.1%

3.2%

16.0%

59.5%

38.0%

60.0%

17.6%

S -

10.2%

24.8%

24.2%

4.0%

51.0%

35.7%

13.5%

13.5%

2.2%

1.3%

2.6%

11.5%

11.1%

35.7%

45.4%

14.7%

9.8%

14.7%

4.2%

31.0%

9.8%

16,5%

4.2%

1.0%

10.0%

1.0%

1.0%

4.5%

15.4%

15.0%

2.3%

14.8%

7.1%

14.3%

28.6%

9.1%

27.3%

4.4%

100.0%

100.0%

100.0%

6.1%

15.0%

5.9%

100.0%

100.0%

100.0%

13.8%

100.0%

8.6%

100.0%

14.3%

100.0%

18.2%

100.0%

The Authority has entered into power sales, natural gas sales, and transmission service agree-ments with the above project participants. Under the terms of the contracts, the participants are entitled to power output, natural gas, or transmission service, as applicable. The participants are obligated to make payments on a "take or pay" basis for their proportionate share of operating and maintenance expenses and debt service. The contracts cannot be terminated or amended in any manner that will impair or adversely affect the rights of the bondholders as long as any bonds issued by the specific project remain outstanding.

The contracts expire as follows:

Palo Verde Project Southern Transmission System Project Hoover Uprating Project Mead-Phoenix Project Mead-Adelanto Project San Juan Project Magnolia Power Project Natural Gas Project - Pinedale Natural Gas Project - Barnett Ormat Geothermal Project 2030 2027 2018 2030 2030 2030 2036 2030 2030 2031 32

SCPPA Combined Summary of Financial Condition and Changes in Net Assets (Deficit)

(In Thousands) kl* "J i'*i Assets Net utility plant Investments Cash and cash equivalents Other Total assets Liabilities and Net Assets (Deficit)

Noncurrent liabilities Current liabilities Total liabilities 2007 1,006,994 556,518 149,740 103,290 1,816,542 1,842,488 191,137 2,033,625 (742,312) 429,686 95,543 (217,083) 1,816,542 390,005 (291,202) 98,803 JUI'IE QU, 2006 995,599 558,497 80,778 112,223 1,747,097 Net Assets (Deficit)

Invested in capital assets, net of related debt Restricted net assets Unrestricted net assets Total net deficit Total liabilities and net assets (deficit)

Revenues, Expenses and Changes in Net Assets (Deficit)

Operating revenues Operating expenses Operating income 1,806,660 186,969 1,993,629 (715,204) 361,732 106,940 (246,532) 1,747,097 330,987 (248,507) 82,480 18,932 (106,198)

(4,786)

(233,031)

(8,715)

(246,532) 2005 986,292 689,286 108,240 88,015 1,871,833 1,961,741 143,123 2,104,864 (657,908) 332,426 92,451 (233,031) 1,871,833 220,813 (171,926) 48,887 36,631 (106,083)

(85,827)

(106,392)

(125,131)

(22,503) 20,995 (233,031)

Investment income Debt expense Loss on extinguisment of debt Change in net deficit 33,622 (113,028) 19,397 Net Deficit - beginning of year Release of Over Billings From Prior Years Net Contributions (Withdrawals) By Participants Net Deficit - end of year (246,532) 10,052 (217,083)

SCPPA Accounting and Investment Group From left to right: Jocelyn Mariano, Senior Utility Accountant, Margarita Estrella, Lead Utility Accountant, Alice Tong, Administrative Assistant, Therese Savery, Manager, SCPPA Accounting and Investments, Yolanda

Pantig, Assistant Manager, SCPPA Accounting, Joan Ilagan, Investment Manager, and Nina Sanchez, Assistant Investment Manager.

CITY OF ANAHEIM Customers - Retail..................

111,319 Power Generated and Purchased (in Megawatt Hours)

Self-Generated 696,563 Purchased....................

2,780,318 Total........................

3,476,881 Total Revenues (000s)..............

$330,421 Operating Costs (000s).............

$315,267*

'Unaudited CITY OF BURBANK Customers - Retail............

Power Generated and Purchased (in Megawato-Hours)

.50,762 Self-Generated................

19,878 Purchased....................

1,311,973 Total.....................

.. 1,331,851 Total Revenues (O00s)..............

$161,501 Operating Costs (000s)..............

$141,835*

teaudited and excludeS wholesale transactions.

CITY OF GLENDALE Customers - Retail....

i.....

83,644 Power Generated and Purchased (in Megawatt-Hours)

Self-Generated....

185,033 Purchased..

1,330,794 Total........................

1,515,827 Total Revenues (000s)..............

$178,979 Operating Costs (000s)............. $170,967 CITY OF PASADENA Customers Served................

62,793 Power Generated and Purchased (in Megawatt-Hours)

Self-Generated................

55,976 Purchased.................

1,496,824 Total....................

1,552,600 Total Revenues (000s)..............

$187,527 Operating Costs (000s)............

$141,185 CITY OF AZUSA Customers Served........

15,524 Power Generated and Purchased (in Megawatt-Hours)

Self-Generated........................

0 Purchased.....................

281,367 Sales Retail.........................

264,485 Total Revenues (000s)...............

$34,785*

Operating Costs (000s)...........

. $33,816*

• Uaudited CITY OF CERRITOS Customers - Retail.........

186 Power Generated and Purchased (in Megawatt-Hours)

Self-Generated...................

49,815 Purchased......................

14,575 Total 64,390 Total Revenues (000s)................

$6,478*

Operating Costs (OOOs)

.$6,643*

• Unaedited IMPERIAL IRRIGATION DISTRICT Customers Served..................

140,631 Power Generated and Purchased (in Megawant-Hours)

Self Generated..................

988,223 Purchased....................

2,785,205 Total...................

.... 3,773,428 Total Revenues (000s)..............

$406,331 Operating Costs (000s)..............

$395,725 CITY OF RIVERSIDE Customers Served..................

105,226 Power Generated and Purchased (in Megawatt-Hours)

Self-Generated..................

375,000 Purchased....................

2,276,000 Total........................

2,651,000 Total Revenues (000s).............

$278,00*

Operating Costs (000s)..............

$244,453*

• Ueaudited CITY OF BANNING Customers - Retail....................

12,200 Power Generated and Purchased (in Megawatt-Hours)

Self-Generated.....

...... 0 Purchased..............

...... 162,280 Total..........................

16 2,28 0 Total Revenues (000s)...............

$22,719*

Operating Costs (000s)...............

$23,601

• Unauoited CITY OF COLTON Customers - Retail...................

18,553 Power Generated and Purchased (in Megawatt-Hours)

Self-Generated......

..... 32,776 Purchased.....................

367,869 Total..........................

400,645 Total Revenues (000s)...............

$54,131 Operating Costs (000s).............

$53,248*

• Uraedited LOS ANGELES DEPARTMENT OF WATER AND POWER Customers Served................

1,448,176 Power Generated and Purchased (in Megawatt-Hours)

Self-Generated...............

14,365,617 Purchased...................

13,636,318 Total.................

28,001,935 Total Revenues (000s).............

$2,600,055" Operating Costs (000s)............

$2,266,236*

Unoaudited I

CITY OF VERNON Customers Served....

Power Generated and Purchased (in Megawat-Hours)

.,1,911 Selt-Generated..................

90 4,839 Purchased.....................

345,684 Total.......................

1,2 50,523 Total Revenues (000s)...........

$138,057 Operating Costs (000s).............

$123,561