ML14329A147

Submittal of Annual Financial Reports

ML14329A147
Person / Time
Site:	Palo Verde
Issue date:	11/19/2014
From:	Weber T Arizona Public Service Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
102-06966-TNW/TMJ
Download: ML14329A147 (202)

Text

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10 CFR 50.71(b) 10 CFR 72.80(b)

Oaps Palo Verde Nuclear Generating Station P0 Box 52034 102-06966-TNW/TMJ Phoenix, Arizona 85072-2034 November 19, 2014 Mail Station 7636 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 50-528/529/530 Submittal of Annual Financial Reports Pursuant to 10 CFR 50.71(b) and 10 CFR 72.80(b), enclosed please find the 2013 Annual Financial Reports for the Participants who jointly own PVNGS and do not file a Form 10-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 10-Q with the Securities and Exchange Commission or a Form 1 with the Federal Energy Regulatory Commission and therefore do not have to file an Annual Financial Report in accordance with 10 CFR 50.71(b) or 10 CFR 72.80(b). These Participants are El Paso Electric Company, Arizona Public Service Company, Southern California Edison Company and Public Service Company of New Mexico.

No commitments are being made to the NRC by this letter. Should you need further information regarding this submittal, please contact Thomas N. Weber, Regulatory Affairs Department Leader, at (623) 393-5764.

Sincerely, 6Wq ý.

Thomas N. Weber Department Leader, Regulatory Affairs TNW/TMJ/hsc

Enclosure:

PVNGS 2013 Annual Financial Reports Salt River Project, Southern California Public Power Authority, Los Angeles Department of Water and Power cc: M. L. Dapas NRC Region IV Regional Administrator B. K. Singal NRC NRR Project Manager for PVNGS M. M. Watford NRC NRR Project Manager D. R. Reinert NRC Acting Senior Resident Inspector for PVNGS A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway

• Comanche Peak

• Diablo Canyon

• Palo Verde

• Wolf Creek P AUU-Fýq

Enclosure PALO VERDE NUCLEAR GENERATING STATION 2013 ANNUAL FINANCIAL REPORTS Salt River Project Southern California Public Power Authority Los Angeles Department of Water and Power

2013 Sfrl' ANNUAL REPORT SALT RIVER PROJECT Combined Financial Statements Notes to Combined Financial Statements Report of Independent Auditors Results as of April 30, 2013

2 2013 SP ANNUAL REPORT SALT RIVER PROJECT COMBINED BALANCE SHEETS APRIL 30, 2013 AND 2012 (THOUSANDS)

ASSETS 2013 2012 Utility Plant Plant in service -

Electric $ 12,611,442 $ 11,967,748 Irrigation 371,185 351,449 Common 600,527 561,291 Total plant in service 13,583,154 12,880,488 Less - Accumulated depreciation on plant in service (6,232,557) (5,883,430) 7,350,597 6,997,058 Plant held for future use 41,044 40,179 Construction work in progress 498,303 417,323 Nuclear fuel, net 137,537 149,745 8,027,481 7,604,305 Other Property and Investments Non-utility property and other investments 294,713 232,717 Segregated funds, net of current portion 986,946 892,875 1,281,659 1,125,592 Current Assets Cash and cash equivalents 237,724 604,563 Temporary investments 63,074 185,729 Current portion of segregated funds 105,928 155,305 Receivables, net of allowance for doubtful accounts 236,542 192,619 Fuel stocks 82,340 74,537 Materials and supplies 148,508 156,018 Current commodity derivative assets 16,483 12,757 Other current assets 26,421 14,272 917,020 1,395,800 Deferred Charges and Other Assets Regulatory assets 1,203,751 1,038,306 Non-current commodity derivative assets 9,204 8,784 Other deferred charges and other assets 49,653 58,866 1,262,608 1,105,956

$ 11,488,768 $ 11,231,653 The accompanying notes are an integral part of these Combined Financial Statements.

2013 S"? ANNUAL REPORT 3 SALT RIVER PROJECT COMBINED BALANCE SHEETS APRIL 30, 2013 AND 2012 (THOUSANDS)

CAPITALIZATION AND LIABILITIES 2013 2012 Long-term Debt and Capital Lease Obligation $ 4,624,547 $ 4,786,995 Accumulated Net Revenues 4,523,812 4,288,792 Total Capitalization 9,148,359 9,075,787 Current Liabilities Current portion of long-term debt and capital lease obligation 143,360 155,142 Accounts payable 186,384 151,548 Accrued taxes and tax equivalents 50,881 89,172 Accrued interest 69,738 67,050 Customers' deposits 88,506 85,195 Current commodity derivative liabilities 20,180 50,940 Other current liabilities 217,256 207,868 776,305 806,915 Deferred Credits and Other Non-current Liabilities Accrued postretirement liability 1,074,592 872,635 Asset retirement obligations 131,764 109,149 Non-current commodity derivative liabilities 72,548 116,485 Other deferred credits and other non-current liabilities 285,200 250,682 1,564,104 1,348,951 Commitments and Contingencies (Notes 7, 9, 11, 12, and 13)

$11,488,768 $11,231,653 The accompanying notes are an integral part of these Combined Financial Statements.

4 2013 S*P ANNUAL REPORT SALT RIVER PROJECT COMBINED STATEMENTS OF NET REVENUES FOR THE YEARS ENDED APRIL 30, 2013 AND 2012 (THOUSANDS) 2013 2012 Operating Revenues Retail electric $2,566,464 $2,488,906 Other electric 68,076 67,614 Wholesale 174,093 181,563 Water 15,163 14,868 Total operating revenues 2,823,796 2,752,951 Operating Expenses Power purchased 318,598 268,155 Fuel used in electric generation 555,566 768,272 Other operating expenses 672,049 644,907 Maintenance 321,192 281,049 Depreciation and amortization 441,371 417,924 Taxes and tax equivalents 141,788 129,383 Total operating expenses 2,450,564 2,509,690 Net operating revenues 373,232 243,261 Other Income Investment income (loss), net 70,371 (1,322)

Other income (deductions), net (11,775) (19,028)

Total other income (loss), net 58,596 (20,350)

Net revenues before financing costs 431,828 222,911 Financing Costs Interest on bonds, net 183,434 191,353 Capitalized interest (15,859) (21,941)

Amortization of bond discount/premium and issuance expenses (18,979) (15,798)

Interest on other obligations 48,212 49,854 Net financing costs 196,808 203,468 Net Revenues $ 235,020 $ 19,443 The accompanying notes are an integral part of these Combined Financial Statements.

2013 SR*I ANNUAL REPORT 5 SALT RIVER PROJECT COMBINED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED APRIL 30, 2013 AND 2012 (THOUSANDS) 2013 2012 Cash Flows from Operating Activities Net Revenues $ 235,020 $ 19,443 Adjustments to reconcile net revenues to net cash provided by operating activities:

Depreciation and amortization 441,371 417,924 Amortization of nuclear fuel 45,362 41,227 Amortization of bond discount/premium and issuance expenses (18,979) (15,798)

Change in fair value of derivative instruments (78,843) 110,039 Change in fair value of investment securities (71,732) 26,475 Other 2,743 9,505 Decrease (increase) in:

Fuel stocks and materials and supplies 3,413 (34,8871 Receivables, net of allowance far doubtful accounts (56,823) 38,880 Other current assets (12,149) 1,283 Deferred charges and other assets 3,367 2,521 Increase (decrease) in:

Accounts payable 25,470 (95,668)

Accrued taxes and tax equivalents (38,291) 12,030 Accrued interest 2,688 4,203 Customer deposits and other current liabilities 12,699 (128,253)

Deferred credits and other non-current liabilities 46,901 (42,051)

Net cash provided by operating activities 542,217 366,873 Cash Flows from Investing Activities Additions to utility plant, net (520,562) (429,823)

Plant acquisition (370,182)

Proceeds from disposition of assets 13,460 3,848 Purchases of investments (2,129,241) (1,842,316)

Sales of investments 1,769,216 1,451,215 Maturities of investments 465,481 615,941 Net change in short-term investments related to segregated funds 5,014 145,700 Insurance proceeds 12,900 Net cash used for investing activities (753,914) (55,435)

Cash Flows from Financing Activities Proceeds from issuance of revenue bonds 971 Capital lease principal payments (12,117) (11,213)

Repayment of long-term debt, including refundings (143,025) (139,6351 Net cash used for financing activities (155,142) (149,877)

Net Increase (Decrease) in Cash and Cash Equivalents (366,839) 161,561 Balance at Beginning of Year in Cash and Cash Equivalents 604,563 443,002 Balance at End of Year in Cash and Cash Equivalents $ 237,724 $ 604,563 Supplemental Information Cash paid for interest $ 213,099 $ 225,386 The accompanying notes are an integral part of these Combined Financial Statements.

6 2013 Sa0 ANNUAL REPORT SALT RIVER PROJECT NOTES TO COMBINED FINANCIAL STATEMENTS APRIL 30, 2013 AND 2012 (1) BASIS OF PRESENTATION:

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. The District and the Association are together referred to as SRP.

Principles of Combination The accompanying Combined Financial Statements reflect the combined accounts of the Association and the District.

The District's financial statements are consolidated with its wholly owned taxable subsidiaries: SRP Captive Risk Solutions, Limited (CRS), Papago Park Center, Inc. (PPC) and New West Energy Corporation (New West Energy). CRS is a domestic captive insurer incorporated primarily to access property/boiler and machinery insurance coverage under the federal Terrorism Risk Insurance Act of 2002 for certified acts of terrorism. PPC is a real estate management company. New West Energy was used to market, at retail, energy available to the District that was surplus to the needs of its retail customers and energy that might have been rendered surplus in Arizona by retail competition in the supply of generation but is now largely inactive. All material intercompany transactions and balances have been eliminated.

Possession and Use of Utility Plant The United States of America retains a paramount right or claim in the Project that arises from the original construction and operation of certain of the Project's electric and water facilities as a federal reclamation project. Rights to the possession and use of, and to all revenues produced by, these facilities are evidenced by contractual arrangements with the United States of America.

Basis of Accounting The accompanying Combined Financial Statements are presented in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP). The preparation of financial statements in compliance with U.S.

GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and disclosures of contingencies. Actual results could differ from the estimates.

By virtue of SRP operating a federal reclamation project under contract, with the federal government's paramount rights, asset ownership and certain approval rights, SRP is subject to accounting standards as set forth by the Federal Accounting Standards Advisory Board (FASAB). Entities reporting in accordance with the standards issued by the Financial Accounting Standards Board (FASBI prior to October 19, 1999 (the date the American Institute of Certified Public Accountants (AICPA) designated the FASAB as the accounting standard setting body for entities under the federal government) are permitted to

2013 SIRP ANNUAL REPORT 7 continue to report in accordance with those standards. As permitted, SRP has elected to report its financial statements in accordance with FASB standards.

(2) SIGNIFICANT ACCOUNTING POLICIES:

Utility Plant Utility plant is stated at the historical cost of construction. Capitalized construction costs include labor, materials, services purchased under contract, and allocations of indirect charges for engineering, supervision, transportation, and administrative expenses and an allowance for funds used during construction (AFUDC). The cost of property that is replaced, removed or abandoned, less salvage, is charged to accumulated depreciation. Repairs and maintenance costs are charged to maintenance expense.

The District is the recipient of various federal grants under the American Recovery and Reinvestment Act of 2009 (ARRA) and accounts for the majority of these funds as a reduction to the related assets included in utility property in the accompanying Combined Balance Sheets and as an investing activity in the Statements of Cash Flows. The remaining funds are recorded as a reduction to other operating expenses in the Combined Statements of Net Revenues and as operating activities in the Statements of Cash Flows. During the years ended April 30, 2013 and 2012, the amounts recorded related to federal grants were $11.3 million and $170 million, respectively.

Depreciation expense is computed on a straight-line basis over recovery periods of the various classes of plant assets. The recovery periods are established to recover costs through the District's price plans and may differ from the assets' estimated useful lives. Depreciation expense for utility plant totaled $426.1 million and $403.5 million for the years ended April 30, 2013 and 2012, respectively. The following table reflects the District's average depreciation rates on the average cost of depreciable assets for the fiscal years ended April 30:

2013 2012 Average electric depreciation rate ......................................... 3.13% 3.20%

Average irrigation depreciation rate ...................................... 1.60% 1.73%

Average common depreciation rate ....................................... 6.13% 6.62%

In February 2013, SRP purchased power block 1 of the Mesquite Generating Station (Mesquite) from an independent power producer (Seller). Mesquite, which entered commercial service in 2003, consists of two combined-cycle gas-fired generating power blocks, each nominally rated at 625 MW. Mesquite is located approximately 40 miles west of Phoenix, Arizona. SRP purchased 100% of power block 1, a 50% ownership interest in most of the facility's common assets and a 32.05% interest in the adjacent switchyard for approximately $370.2 million. Assets acquired include $364.7 million of plant and $5.5 million of inventory, land and other assets. In addition, the District recorded in asset retirement obligations in the accompanying Combined Balance Sheets an asset retirement obligation of $16.0 million related to legal obligations associated with the assets acquired (see Asset Retirement Obligations for additional information). The Seller will continue to own 100% of power block 2 and SRP will serve as operator for the entire facility. SRP believes this plant will meet long term load growth and customer needs at a reasonable cost.

For the years ended April 30, 2013 and 2012, there was $9.4 million and $25.0 million of non-cash investing activities related to property, plant and equipment purchases within accounts payable.

8 2013 SRP ANNUAL REPORT Allowance for Funds Used During Construction AFUDC is the estimated cost of funds used to finance plant additions and is recovered in prices through depreciation expense over the useful life of the related asset. AFUDC is capitalized during certain plant construction and included in capitalized interest in the accompanying Combined Statements of Net Revenue. Composite rates of 4.53% and 4.50%

were applied in fiscal years 2013 and 2012 to calculate interest on funds used to finance construction work in progress, resulting in $15.9 million and $21.9 million of interest capitalized, respectively.

Nuclear Fuel SRP amortizes the cost of nuclear fuel using the units-of-production method. The units-of-production method is an amortization method based on actual physical usage. The nuclear fuel amortization and accrued expenses for both the interim and permanent disposal of spent nuclear fuel are components of fuel expense. Nuclear fuel amortization was

$45.4 million and $41.2 million in fiscal years 2013 and 2012, respectively. Accumulated amortization of nuclear fuel at April 30, 2013 and 2012 was $594.2 million and $548.8 million, respectively. (See Note [13], CONTINGENCIES, Spent Nuclear Fuel, for additional information.)

Asset Retirement Obligations SRP accounts for its asset retirement obligations in accordance with authoritative guidance which requires the recognition and measurement of liabilities for legal obligations associated with the retirement of tangible long-lived assets. Liabilities for asset retirement obligations are recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities, due to the passage of time, is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. Retirement obligations associated with long-lived assets are those for which a legal obligation exists under enacted laws, statutes, and contracts, including obligations arising under the doctrine of promissory estoppel.

The District has identified retirement obligations for Palo Verde Nuclear Generating Station (PVNGS), Navajo Generating Station (NGS), Four Corners Generating Station (Four Corners), Mesquite, and certain other assets. Amounts recorded for asset retirement obligations are subject to various assumptions and determinations, such as determining whether an obligation exists to remove assets, estimating the fair value of the costs of removal, estimating when final removal will occur, and determining the credit-adjusted, risk-free interest rates to be utilized on discounting future liabilities. Subsequent to the initial recognition, the liability is adjusted for any revisions to the estimated future cash flows associated with the asset retirement obligation (with corresponding adjustments to utility plant), which can occur due to a number of factors, including, but not limited to, cost escalation, changes in technology applicable to the assets to be retired, changes in federal, state and local regulations, and changes to the estimated decommissioning date of the assets, as well as for accretion of the liability due to the passage of time until the obligation is settled.

The following table summarizes the asset retirement obligation activity of the District at April 30 (inthousands):

2013 2012 Beginning balance, May 1 $ 109,149 $ 100,212 Additions for Mesquite 16,000 Accretion expense 6,615 8,937 Ending balance, April 30 $ 131,764 $ 109,149

2013 SRP ANNUAL REPORT 9 Investments in Debt and Equity Securities SRP invests in various debt and equity securities. Debt securities that SRP has the positive intent and ability to hold to maturity are classified as held-to-maturity securities and reported at amortized cost. Debt and equity securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and reported at fair value, with unrealized gains and losses included in investment income, net. SRP has adopted the fair value option for all debt and equity securities other than those classified as held-to-maturity securities. All such securities are reported at fair value, with unrealized gains and losses included in investment income, net. SRP does not classify any securities as available-for-sale. (See Note [4] FAIR VALUE OF FINANCIAL INSTRUMENTS.)

Segregated Funds The District sets aside funds that are segregated due to management intent and to support various purposes. The District also has certain segregated funds that are legally restricted. The following amounts are included in segregated funds in the accompanying Combined Balance Sheets at April 30 (inthousands):

2013 2012 Segregated funds - legally restricted Nuclear Decommissioning Trust $ 287,975 $ 257,114 Debt Reserve Fund 80,598 80,598 Other 25,780 23,656 Total segregated funds - legally restricted 394,353 361,368 Segregated funds - other Benefits funds 584,858 525,715 Debt Service Fund 105,928 109,605 Rate Stabilization Fund 45,700 Other 7,735 5,792 Total segregated funds - other 698,521 686,812 Total segregated funds, including current portion $1,092,874 $1,048,180 Nuclear Decommissioning In accordance with regulations of the Nuclear Regulatory Commission (NRC), the District maintains a trust for the decommissioning of PVNGS. The Nuclear Decommissioning Trust (NDT) funds are invested in debt and equity securities.

SRP has elected the fair value option for all NDT securities, and such securities are reported as trading securities.

Changes in fair value related to the NDT securities are included in the nuclear decommissioning regulatory asset or liability with no impact to net income. (See Note [3] REGULATORY MATTERS, for additional information about the nuclear decommissioning regulatory asset or liability.) The NDT funds, stated at fair value, as of April 30, 2013 and 2012, were

$288.0 million and $2571 million, respectively. The NDT funds are classified as segregated funds in the accompanying Combined Balance Sheets and are exempt from federal and state income taxes. (See Note [4] FAIR VALUE OF FINANCIAL INSTRUMENTS, for additional information about the NDT.)

10 2013 SCP ANNUAL REPORT Cash Equivalents Cash equivalents include money market funds and highly liquid short-term investments with original maturities of three months or less, excluding negative account balances due to outstanding checks that are included in accounts payable, those short-term investments included as part of the segregated funds, and investments included in non-utility property and other investments in the accompanying Combined Balance Sheets. [For further discussion of financial instruments, see Note

[6], FAIR VALUE MEASUREMENTS.)

Allowance for Doubtful Accounts Allowance for doubtful accounts is provided for electric customer accounts and other non-energy receivables balances based upon a historical experience rate of write-offs of accounts receivable as compared to retail electric revenues. The allowance account is adjusted periodically for this experience rate and is maintained until either receipt of payment or the likelihood of collection is considered remote, at which time the allowance account and corresponding receivable balance are written off. SRP has provided for an allowance for doubtful accounts of $1.7 million and $3.2 million as of April 30, 2013 and 2012, respectively.

Fuel Stocks and Materials and Supplies Fuel stocks and materials and supplies are stated at weighted average cost, and are valued using the average cost method.

Other Current Liabilities The accompanying Combined Balance Sheets include the following other current liabilities as of April 30:

2013 2012 Sick, vacation and holiday (SVHL) accrual $ 87,940 $ 85,098 Budget billing plan 43,084 45,258 Employee Performance Incentive Compensation (EPIC) 25,505 27,534 Postretirement benefits 23,969 22,519 Other 36,758 27,459 Total other current liabilities $ 217,256 $ 207,868 Other Income (Deductions), Net Other income (deductions), net, includes non-operating income and expense items. In fiscal years 2013 and 2012, this line includes a loss on the retirement of mechanical meters of $4.3 million and $10.1 million, respectively. The mechanical meters were retired early due to the accelerated installation of smart meters funded by the Smart Grid Investment Grant Program established pursuant to the ARRA.

Financing Costs Bond discount, premium and issuance expenses are deferred and amortized using the effective interest method over the terms of the related bond issues.

2013 SRP ANNUAL REPORT 11 Voluntary Contributions in Lieu of Taxes In accordance with Arizona law, the District makes voluntary contributions each year to the State of Arizona, school districts, cities, counties, towns and other political subdivisions of the State of Arizona, for which property taxes are levied and within whose boundaries the District has property included in its electric system. As a political subdivision of the State of Arizona, the District is exempt from property taxation. The amount paid is computed on the same basis as ad valorem taxes paid by a private utility corporation with allowance for certain water-related deductions. Contributions based on the costs of construction work in progress are capitalized, and those based on plant-in-service are expensed.

Revenue Recognition SRP recognizes revenue when billed and accrues estimated revenue for electricity delivered to customers that has not yet been billed. The estimated revenue for electricity delivered but not yet billed is included in retail electric revenue and receivables, net, and was $775 million and $74.6 million at April 30, 2013 and 2012, respectively. Other operating revenue consists primarily of revenue from marketing and trading electricity.

The electric industry engages in an activity called "book-out", under which some energy purchases are netted against sales and power does not actually flow in settlement of the contract. SRP presents the impacts of these financially settled contracts on a net basis, which resulted in a net reduction to revenue and purchased power expense of $39.8 million and

$50.2 million for fiscal years 2013 and 2012, respectively, but which did not affect net revenues or cash flows.

Sales and Use Taxes The District is required by various government authorities, including states and municipalities, to collect and remit taxes on certain retail sales. Such taxes are presented on a net basis and excluded from revenues and expenses in the accompanying Combined Financial Statements.

Income Taxes The District, as a political subdivision of the State of Arizona, is exempt from federal and Arizona state income taxes. The Association, as a private corporation, is not exempt from federal and Arizona state income taxes. However, the Association is not liable for income taxes on operations relating to its acting as an agent for the District on the basis of a settlement with the Commissioner of Internal Revenue in 1949, which was approved by the Secretary of the Treasury. The Association is liable for income taxes on activities where it is not acting as an agent of the District. The tax effect of the District's wholly owned taxable subsidiaries' operations is immaterial to the accompanying Combined Financial Statements.

Concentrations of Credit Risk Financial instruments that potentially subject SRP to credit risk consist of cash and cash equivalents, temporary and other investments, and segregated funds. Certain balances exceed Federal Deposit Insurance Corporation (FDIC) insured limits or are invested in money market accounts with investment banks that are not FDIC insured. SRP's cash and cash equivalents, temporary and other investments, and segregated funds are placed in creditworthy financial institutions, and certain money market accounts invest in U.S. Treasury Securities or other obligations issued or guaranteed by the U.S. government, or its agencies or instrumentalities.

The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risks resulting from the possibility of nonperformance by counterparties pursuant to the terms of their contractual obligations. In addition, volatile energy prices can create significant credit exposure from energy market receivables and mark-to-market valuations. The District has a credit policy for wholesale counterparties, continuously monitors credit exposures, and routinely assesses the financial strength of its counterparties. The District minimizes credit risk by dealing

12 2013 SZP ANNUAL REPORT primarily with creditworthy counterparties, entering into standardized agreements that allow netting of exposures to and from a single counterparty, and requiring letters of credit, parent guarantees or other collateral when it does not consider the financial strength of the counterparty sufficient.

Revision In 2013, SRP identified an error in its historical accounting for medical, dental and prescription expenses that resulted in an excess accrual of approximately $26.6 million as of April 30, 2012. The excess accrual was the result of expenses recorded over an approximate 10 year period. SRP determined that the adjustment to correct the error was not material to any prior period financial results, but the cumulative adjustment to correct the error in the current period would have been material to fiscal year 2013 net revenues and would not appropriately reflect the net revenue impact of the adjustment for fiscal years 2013 and 2012, respectively. Accordingly, SRP revised its April 30, 2012 Combined Balance Sheet, Combined Statement of Net Revenues and Combined Statement of Cash Flows to appropriately reflect the accrual for medical, dental, and prescription expenses. This revision resulted in an increase in beginning of the fiscal year 2012 accumulated net revenues of $171 million and an increase to April 30, 2012 accumulated net revenues of $18.4 million.

Operating expenses were reduced by $1.3 million, resulting in a corresponding increase to net revenues for the year ended April 30, 2012. Utility plant decreased by $3.9 million, regulatory assets decreased by $4.3 million and other current liabilities decreased by $26.6 million as of April 30, 2012. The net increase in cash and cash equivalents for the year ended April 30, 2012 did not change; however, net cash provided by operating activities decreased by $0.3 million and net cash used for investing activities decreased by $0.3 million.

Recently Issued Accounting Standards In October 2012, the FASB issued ASU 2012-04, Technical Corrections and Improvements. This standard includes: 1) source literature amendments to conform the language between current accounting literature and legacy source literature;

2) clarification of guidance and reference corrections; and 3) relocation of guidance to a more appropriate location. The adoption of this standard did not have an impact on SRP's financial statements or disclosures.

In December 2011, the FASB issued ASU 2011-11, Disclosures about Offsetting Assets and Liabilities, to enhance disclosure requirements for offsetting (netting) assets and liabilities in order to facilitate comparison between those entities that prepare their financial statements on the basis of U.S. GAAP and those entities that prepare their financial statements on the basis of International Financial Reporting Standards (IFRS). The guidance is effective for SRP on May 1, 2013. The adoption of this new guidance will result in additional disclosures, but will not impact the accompanying Combined Financial Statements.

In May 2011, the FASB issued amended guidance to converge fair value measurement and disclosure requirements for U.S. GAAP and International Financial Reporting Standards (IFRS). The amended guidance clarifies how certain fair value measurement principles should be applied and requires enhanced fair value disclosures. The guidance was effective for SRP on May 1, 2012. The adoption of this new guidance has resulted in additional fair value disclosures, but did not affect the accompanying Combined Financial Statements.

Subsequent Events SRP follows authoritative guidance which requires an entity to evaluate subsequent events through the date that the financial statements are either issued or available to be issued. The amendment also requires an entity to disclose the date through which the subsequent events have been evaluated and whether that date represents the date the financial statements were issued or the date they were available to be issued. SRP adopted the subsequent event guidance effective May 1, 2010.

Subsequent events for SRP have been evaluated through July 19, 2013, which is the date that the financial statements were issued.

2013 S-RPANNUAL REPORT 13 (3) REGULATORY MATTERS:

The Electric Utility Industry The District operates in a highly regulated environment in which it has an obligation to deliver electric service to customers within its service area. In 1998, Arizona enacted the Arizona Electric Power Competition Act (the Act), which authorized competition in the retail sales of electric generation, recovery of stranded costs, and competition in billing, metering and meter reading. While retail competition was available to all customers by 2001, only a few customers chose an alternative energy provider and those customers have since returned to their incumbent utilities. At this time, there is no active retail competition within the District's service territory or, to the knowledge of the District, within the State of Arizona, and the District's Direct Access Program is suspended.

Since 2006, various energy service, meter reading and meter service providers, as well as brokers have applied to the Arizona Corporation Commission (ACC) for authorization to sell competitive services in Arizona, but the ACC has not ruled on any of the applications. However, effective July 1, 2012, the ACC approved another major Arizona utility's proposed buy-through pilot program whereby a limited number of large industrial customers are now allowed to purchase generation from other providers. In addition, energy service providers, large industrial customers and merchant power plant owners have been urging the ACC to reinstate some form of retail competition.

At the request of the ACC and after a lengthy public process, the ACC staff issued a report in August 2010 recommending that, should the ACC choose to revisit competition, it should do so cautiously and determine if it is in the public interest.

In May 2013, in response to various applications received, the ACC opened a further inquiry into retail competition, requesting that interested parties provide comments on a series of ACC-issued questions. The District is participating in this inquiry. As the inquiry is in its early stages, it is unclear what direction the ACC will eventually take or the specific time frame for the initial decision. Ifthe ACC were to decide to reinstitute retail competition, the District would anticipate multiple legal challenges to such a decision and that the ACC, among others, would have to rewrite the existing rules regarding competition.

Regulation and Pricing Policies Under Arizona law, the District's publicly elected Board of Directors has the authority to establish electric prices. The District is required to follow certain public notice and special Board meeting procedures before implementing any changes in the standard electric price plans. The financial statements reflect the pricing policies of the District's Board.

The District's price plans include a base price component, a Fuel and Purchased Power Adjustment Mechanism (FPPAM) and an Environmental Programs Cost Adjustment Factor (EPCAF). Base prices recover costs for generation, transmission, distribution, customer services, metering, meter reading, billing and collections, and system benefits charges that are not otherwise recovered through the FPPAM or EPCAF. The FPPAM was implemented inMay 2002 to adjust for increases and decreases infuel costs.

The EPCAF was implemented in November 2009 to cover costs incurred by the District to comply with requirements imposed by mandate that are related to renewable-energy, energy efficiency and climate change. Through a system benefits surcharge to the District's transmission and distribution customers, the District recovers the costs of programs benefiting the general public, such as discounted rates for low income customers and nuclear decommissioning, including the cost of spent fuel storage.

On September 27 2012, the District Board approved an overall 3.9% system average increase effective with the November 2012 billing cycle. This overall increase was comprised of a 3.9% base increase and a 2.4% EPCAF increase that were partially offset by a 2.4% decrease to the FPPAM.

In March 2013, the District Board approved an overall 1.2% temporary summer system average decrease effective with the May 2013 billing cycle. This overall temporary decrease was comprised of a 0.8% EPCAF decrease and a 0.4%

decrease to the FPPAM, effective for the six summer billing months. Prices will return to their November 2012 level effective with the November 2013 billing cycle.

14 2013 S.'. ANNUAL REPORT Rate Stabilization Fund In accordance with Board action taken on March 11, 2010, SRP transferred $45.7 million into the Rate Stabilization Fund (RSF) inJuly 2010. The funds were available to stabilize future prices or for any other corporate purpose approved by the Board. On March 27 2012, the Board approved the release of the entire balance to the General Fund for general corporate purposes, effective May 1, 2012.

Regulatory Accounting SRP accounts for the financial effects of the regulated portion of its operations in accordance with the provisions of authoritative guidance for regulated enterprises, which requires cost-based, rate-regulated utilities to reflect the impacts of regulatory decisions in their financial statements. SRP records regulatory assets, which represent probable future recovery of certain costs from customers through the pricing process, and regulatory liabilities, which represent probable future credits to customers through the ratemaking process. Based on actions of the Board, SRP believes the future collection of costs deferred through regulatory assets is probable. If events were to occur making full recovery of these regulatory assets no longer probable, SRP would be required to write off the remaining balance of such assets as a one-time charge to net revenues. None of the regulatory assets earn a rate of return.

The accompanying Combined Balance Sheets include the following regulatory assets and liabilities as of April 30:

Assets 2013 2012 Pension and other postretirement benefits (Note [9]) $ 1,085,753 $ 906,060 Bond defeasance 97,197 103,644 Mohave Generating Station 20,801 28,602 Total regulatory assets $ 1,203,751 $ 1,038,306 Liabilities 2013 2012 Nuclear decommissioning $ 80,932 $ 45,960 Total regulatory liabilities $ 80,932 $ 45,960 The pension and other postretirement benefits regulatory asset is adjusted as changes in actuarial gains and losses, prior service costs, and transition assets or obligations are recognized as components of net periodic pension costs each year and is recovered through prices charged to customers.

Bond defeasance regulatory assets are recovered over the remaining original amortization periods of the reacquired debt ending in various years through fiscal year 2032.

The Mohave Generating Station regulatory asset is being recovered on a straight-line basis over a ten-year period ending in fiscal year 2016.

2013 s.W ANNUAL REPORT 15 The nuclear decommissioning regulatory asset or liability is being deferred over the life of PVNGS and is being recovered through a component of the system benefits charge. Any difference between current year costs, revenues associated with nuclear decommissioning, and earnings (losses) on the NDT is deferred inaccordance with authoritative guidance for regulated enterprises and has no impact to SRP's earnings.

(4) FAIR VALUE OF FINANCIAL INSTRUMENTS:

SRP invests in U.S. government obligations, certificates of deposit and other marketable investments. Such investments are classified as cash and cash equivalents, temporary investments, other investments, and segregated funds in the accompanying Combined Balance Sheets depending on the purpose and duration of the investment.

Fair Value Option SRP adopted authoritative guidance which permits an entity to choose to measure many financial instruments and certain other items at fair value. SRP has elected the fair value option for all investment securities other than those classified as held-to-maturity. Election of the fair value option requires the security to be reported as a trading security.

The fair value option was elected because management believes that fair value best represents the nature of the investments. While the investment securities held in these funds are reported as trading securities, the investments continue to be managed with a long-term focus. Accordingly, all purchases and sales within these funds are presented separately in the accompanying Combined Statements of Cash Flows as investing cash flows, consistent with the nature and purpose for which the securities are acquired.

Realized and unrealized gains and losses on these investments are included in investment income, net in the accompanying Combined Statements of Net Revenues.

The following table summarizes line items included in the accompanying Combined Balance Sheets at April 30 that include amounts recorded at fair value pursuant to the fair value option:

16 2013 SRP' ANNUAL REPORT Measurement (in thousands) Attribute* 2013 2012 Cash and cash equivalents Cash N/A $ 13,654 $ 39,043 Money market funds Fair value 224,070 565,520 Total cash and cash equivalents 237,724 604,563 Non-utility property and other investments Money market funds Fair value 3,006 3,085 Trading investments Fair value 34,579 31,477 Held-to-maturity investments Amortized cost 166,830 110,500 Non-utility property N/A 90,298 87,655 Total non-utility property and other investments 294,713 232,717 Segregated funds, net of current portion Cash N/A 7,735 5,792 Money market funds Fair value 20,393 60,654 Trading investments Fair value 878,666 787,234 Held-to-maturity investments Amortized cost 80,152 39,195 Total segregated funds, net of current portion 986,946 892,875 Temporary investments Held-to-maturity investments Amortized cost 63,074 185,729 Total temporary investments 63,074 185,729 Current portion of segregated funds Money market funds Fair value 105,928 135,338 Held-to-maturity investments Amortized cost - 19,967 Total current portion of segregated funds $ 105,928 $ 155,305

• N/A - Asset category not eligible for fair value option.

SRP's investments in debt securities are measured and reported at amortized cost when there is positive intent and ability to hold the security to maturity. SRP's amortized cost and fair value of held-to-maturity securities were $310.1 million and $314.5 million, respectively, at April 30, 2013, and $355.4 million and $358.2 million, respectively, at April 30, 2012. At April 30, 2013, SRP's investments in debt securities have maturity dates ranging from May 1, 2013 to December 20, 2027 SRP evaluates the held-to-maturity securities for other-than-temporary impairment on a quarterly basis considering numerous factors. At April 30, 2013 and 2012, SRP did not hold any impaired securities.

2013 S0r ANNUAL REPORT 17 SRP's trading investments are measured at fair value with unrealized trading gains and losses included in investment income, net. Unrealized trading gains and losses on Nuclear Decommissioning Trust investments are included in nuclear decommissioning regulatory liability. The following table summarizes unrealized gains (losses) from fair value changes related to investments still held at April 30 (inthousands):

2013 2012 Segregated funds, net of current portion $69,065 $(26,123)

Non-utility property and other investments 2,667 (352)

Investment income, net $ 71,732 $ (26,475)

(5) DERIVATIVE INSTRUMENTS:

Energy Risk Management Activities The District has an energy risk management program to limit exposure to risks inherent in normal energy business operations. The goal of the energy risk management program is to measure and manage exposure to market risks, credit risks and operational risks. Specific goals of the energy risk management program include reducing the impact of market fluctuations on energy commodity prices associated with customer energy requirements, excess generation and fuel expenses, in addition to meeting customer pricing needs, and maximizing the value of physical generating assets. The District employs established policies and procedures to meet the goals of the energy risk management program using various physical and financial instruments, including forward contracts, futures, swaps and options.

Certain of these transactions are accounted for as commodity derivatives and are recorded in the accompanying Combined Balance Sheets as either an asset or liability measured at their fair value. Derivative instruments and the related collateral accounts, if applicable, that are subject to master netting agreements are presented as a net asset or liability on the Combined Balance Sheets. Changes in the fair value of commodity derivatives are recognized each period in current earnings and included in the accompanying Combined Statements of Net Revenues and classified as part of operating cash flows in the accompanying Combined Statements of Cash Flows. Some of the District's contractual agreements qualify and are designated for the normal purchases and normal sales exception and are not recorded at market value. This exception applies to physical sales and purchases of power or fuel where it is probable that physical delivery will occur; the pricing provisions are clearly and closely related to the underlying asset; and the documentation requirements are met. Ifa contract qualifies for the normal purchases and normal sales scope exception, the District accounts for the contract using settlement accounting (costs and revenues are recorded when physical delivery occurs).

See Note [61, FAIR VALUE MEASUREMENTS, for additional information on derivative valuation.

Segregated Funds Investments The District enters into non-commodity derivative transactions either as a way to gain exposure to certain sectors and countries without having to physically buy securities in that sector or country or as a hedge against downside risk. When the District seeks to gain exposure to certain financial market sectors, it may enter into exchange-traded futures or forward contracts that provide the desired exposure. The contracts may be long or short term, and serve as a risk management tool for the portfolio.

Similarly, the District may enter into option contracts on certain securities or sectors to minimize downside risk in the portfolio.

The District enters into a variety of non-commodity derivative instruments including futures, forwards, swaps and options primarily for trading purposes, with each instrument's primary risk exposure being interest rate, credit, and foreign

18 2013 SUP ANNUAL REPORT exchange. The fair value of these non-commodity derivative instruments is included within the segregated funds, net of current portion, in the accompanying Combined Balance Sheets, with changes in fair value reflected as investment income, net, within the Combined Statements of Net Revenues, and classified as part of investing cash flows in the accompanying Combined Statements of Cash Flows. The investments in futures are settled on a daily basis. As such there are no fair values or unrecognized gains or losses included in the schedules below or in Note [6], FAIR VALUE MEASUREMENTS, as of April 30, 2013 and 2012 for the futures investments.

Derivative Volumes The District has the following gross derivative volumes, by type, at April 30, 2013:

Unit of Sales Purchases Commodity Measure Volumes Volumes Natural gas options, swaps and forward arrangements MMBtu 26,455,000 188,050,000 Electricity options, swaps and forward arrangements MWh 3,815,306 2,981,170 Liquefied fuel swaps Gallon 4,092,020 Unit of Sales Purchases Non-commodity Measure Volumes Volumes Fixed income contracts Shares 172,600,046 18,172,087 Foreign exchange contracts Shares 134,358,996 137,243,762 The District has the following gross derivative volumes, by type, at April 30, 2012:

Unit of Sales Purchases Commodity Measure Volumes Volumes Natural gas options, swaps and forward arrangements MMBtu 2,685,000 170,403,250 Electricity options, swaps and forward arrangements 2,572,000 MWh 3,351,808 Liquefied fuel swaps Gallon 4,095,243 Unit of Sales Purchases Non-commodity Measure Volumes Volumes Fixed income contracts Shares 56,163,038 64,284,290 Foreign exchange contracts Shares 110,408,668 396,228,620 Presentation of Derivative Instruments in the Financial Statements The following tables provide information about the gross fair values, netting, and collateral and margin deposits for derivatives not designated as hedging instruments in the accompanying Combined Balance Sheets (in thousands):

2013 SRP ANNUAL REPORT 19 April 30, 2013 Segregated Current Non-current Current Non-current Funds, net Commodity Commodity Commodity Commodity of Current Derivative Derivative Derivative Derivative Total Assets Portion Assets Assets Liabilities Liabilities (Liabilities)

Commodities $ $ 27,162 $12,877 $ (37,896) $ (76,221) $ (74,078)

Fixed income contracts (1,278) (1,278)

Foreign exchange contracts (170) (170)

Netting (17,716) (3,673) 17,716 3,673 Collateral and margin deposits 7,037 7,037 Total $ (1,448) $ 16,483 $ 9,204 $ (20,180) $ (72,548) $ (68,489)

April 30, 2012 Segregated Current Non-current Current Non-current Funds, net Commodity Commodity Commodity Commodity of Current Derivative Derivative Derivative Derivative Total Assets Portion Assets Assets Liabilities Liabilities (Liabilities)

Commodities $ $ 15,657 $12,401 $ (81,045) $ (120,102) $ (173,089)

Fixed income contracts 1,385 1,385 Foreign exchange contracts (1,196) (1,196)

Netting (9,305) (3,617) 9,305 3,617 Collateral and margin deposits 6,405 - 20,800 27,205 Total $ 189 $12,757 $ 8,784 $ (50,940) $ (116,485) $ (145,695)

The following tables summarize the District's unrealized gains (losses) associated with derivatives not designated as hedging instruments in the accompanying Combined Statements of Net Revenues (in thousands):

April 30, 2013 Fuel Used Net Operating Power in Electric Investment Unrealized Revenues Purchased Generation Income, net Gain (Loss)

Commodities $ (26,968) $2,217 $ 105,421 $ $ 80,670 Fixed income contracts (2,663) (2,663)

Foreign exchange contracts 1,026 1,026 Total $ (26,968) $ 2,217 $105,421 $(1,637) $ 79,033

20 2013 Gr,3 ANNUAL REPORT April 30, 2012 Fuel Used Net Operating Power in Electric Investment Unrealized Revenues Purchased Generation Income, net Gain (Loss)

Commodities $ 1,259 $5,056 $(143,911) $ - $(137,596)

Fixed income contracts - - 202 202 Foreign exchange contracts - - (23) (23)

Total $ 1,259 $5,056 $(143,911) $ 179 $(137,417)

Credit Related Contingent Features Certain of the District's derivative instruments contain provisions that require the District to post additional collateral upon certain credit events. If the District's debt were to fall below investment grade, the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions.

The aggregate fair value of all derivative liabilities with credit-risk-related contingent features as of April 30, 2013, was

$88.8 million, for which the District is not required to.post collateral. If the credit-risk-related contingent features underlying these agreements were triggered on April 30, 2013, the District could be required to post up to $88.8 million of collateral to its counterparties.

(6) FAIR VALUE MEASUREMENTS:

SRP accounts for fair value in accordance with authoritative guidance, which defines fair value, establishes methods for measuring fair value by applying one of three observable market techniques (market approach, income approach or cost approach) and establishes required disclosures about fair value measurements. This standard defines fair value as the price that would be received for on asset, or paid to transfer a liability, in the most advantageous market for the asset or liability in an arms-length transaction between willing market participants at the measurement date. SRP determines fair value of its financial instruments based on the market approach, which is defined as a valuation technique that uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

SRP has categorized its financial instruments, based on the priority of the inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are as follows:

Level 1: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market.

Level 2: Financial assets and liabilities whose values are based on quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in non-active markets, pricing models whose inputs are observable for substantially the full term of the asset or liabilities and pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means.

Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

2013 SRP ANNUAL REPORT 21 The following table sets forth, by level within the fair value hierarchy, SRP's financial assets and liabilities that were accounted for at fair value on a recurring basis as of April 30, 2013 (inthousands):

Netting and Level 1 Level 2 Level 3 Collateral Total Assets Cash and cash equivalents:

Money market funds $ $224,070 $ $ $ 224,070 Total cash and cash equivalents 224,070 224,070 Non-utility property and other investments:

Money market funds - 3,006-- 3,006 Mutual funds 34,579 --- 34,579 Total non-utility property and other investments 34,579 3,006 37,585 Segregated funds, net of current portion:

Money market funds 20,393 20,393 Mutual funds 233,436 233,436 Commingled funds 114,864 4,031 118,895 Common stocks 299,221 299,221 Preferred stocks 162 - 162 Corporate bonds - 109,558 109,558 U.S. government securities - 115,080 115,080 Foreign currency 3,762 - 3,762 Fixed income derivative assets - 647 647 Fixed income derivative liabilities (1,925) (1,925)

Foreign exchange derivative assets -111 111 Foreign exchange derivative liabilities (281) (281)

Total segregated funds, net of current portion 536,581 358,447 4,031 899,059 Current portion of segregated funds:

Money market fund 105,928 105,928 Total current portion of segregated funds 105,928 105,928 Derivative instruments:

Commodities 6,179 23,394 10,466 (14,352) 25,687 Total $ 577,339 $714,845 $ 14,497 $(14,352) $1,292,329 Liabilities Derivative instruments:

Commodities $ (6,351) $ (77,049) $(30,717) $ 21,389 $ (92,728)

Total $ (6,351) $ (77,049) $(30,717) $ 21,389 $ (92,728)

22 2013 SZP ANNUAL REPORT The following table sets forth, by level within the fair value hierarchy, SRP's financial assets and liabilities that were accounted for at fair value on a recurring basis as of April 30, 2012 (inthousands):

Netting and Level 1 Level 2 Level 3 Collateral Total Assets Cash and cash equivalents:

Money market funds $ $ 565,520 $ $ $ 565,520 Total cash and cash equivalents 565,520 565,520 Non-utility property and other investments:

Money market funds 3,085 3,085 Mutual funds 31,477 31,477 Total non-utility property and other investments 31,477 3,085 34,562 Segregated funds, net of current portion:

Money market funds 60,654 60,654 Mutual funds 101,055 101,055 Commingled funds 218,290 4,112 222,402 Common stocks 271,357 271,357 Preferred stocks 158 158 Corporate bonds 96,161 96,161 U.S. government securities 95,813 95,813 Foreign currency 99 99 Fixed income derivative assets 21,046 21,046 Fixed income derivative liabilities (19,661) (19,661)

Foreign exchange derivative assets 6,998 6,998 Foreign exchange derivative liabilities (8,194) (8,194)

Total segregated funds, net of current portion 372,669 471,107 4,112 847,888 Current portion of segregated funds:

Money market fund - 135,338 135,338 Total current portion of segregated funds 135,338 135,338 Derivative instruments:

Commodities 6,984 11,440 9,634 (6,517) 21,541 Total $411,130 $ 1,186,490 $ 13,746 $ l6,517) $ 1,604,849 Liabilities Derivative instruments:

Commodities $ (7,767) $ (135,617) $(57,763) $ 33,722 $ (167,425)

Total $ (7,767) $ (135,617) $ (57,763) $ 33,722 $ (167,425)

2013 SUP° ANNUAL REPORT 23 Valuation Methodologies Securities Money market funds: Investments with maturities of three months or less when purchased, including certain short-term fixed-income securities, are considered cash equivalents. The fair value of shares in money market funds are priced based on inputs obtained from Bloomberg, a pricing service whose prices are obtained from direct feeds from exchanges, that are either directly or indirectly observable. Even though the NAV of the fund(s) is kept at $1 per share, and transactions occur at that price, the underlying value of the securities may or may not be equal to $1 per share; therefore, these funds are classified as Level 2 in the fair value hierarchy.

Mutual funds: The fair values of shares in mutual funds are based on inputs that are quoted prices in active markets for identical assets and, therefore, have been categorized in Level 1 in the fair value hierarchy. Mutual funds are priced using active market exchanges, and sources include Interactive Data Corporation (IDC), Bloomberg, Yahoo Finance and other publicly available venues. This category may include Exchange-Traded Funds (ETF's), which are similar to mutual funds in their structure, but trade actively on exchanges like stocks. Pricing sources for ETF's also include IDC, Bloomberg, Yahoo Finance and other publicly available venues.

Corporate stocks: The fair values of shares in preferred and common corporate stocks are based on inputs that are quoted prices in active markets for identical assets and, therefore, have been categorized in Level 1 in the fair value hierarchy. Equities are priced using active market exchanges. Preferred and common corporate stocks are valued based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges.

Common stocks that are valued based on quoted prices from less active markets, such as over-the-counter (OTC) stocks, are categorized as Level 2 in the fair value hierarchy. Pricing sources include Interactive Data Corporation (IDC), Bloomberg, Yahoo! Finance, or other publicly available venues.

U.S- government securities: The fair value of U.S. government securities is derived from quoted prices on similar assets in active or non-active markets, from pricing models whose inputs are observable for the substantially full term of the asset, or from pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means; therefore, these securities have been categorized as Level 2 in the fair value hierarchy.

Commingled funds: Commingled funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with SRP's overall investment strategy. For equity and fixed-income commingled funds, the fund administrator values the fund using the net asset value (NAV) per fund share, derived from the quoted prices in active markets of the underlying securities. Where adjustments to the NAV are required with respect to interests in funds subject to restrictions on redemption (such as lock-up periods or withdrawal limitations) and/or observable activity for the fund investment is limited, investments are classified within Levels 2 or 3 of the valuation hierarchy. If the ability to redeem the investment is unknown or the investment cannot be redeemed in the near term at NAV, the fair value measurement of the investment will be categorized as a Level 3 in the valuation hierarchy.

Corporate bonds: For fixed-income securities, multiple prices and price types are obtained from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. SRP has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, SRP selectively corroborates the fair values of securities by comparison to other market-based price sources. The fair values of fixed-income securities are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.

24 2013 $R. ANNUAL REPORT Non-commodity derivatives: Non-commodity derivatives include fixed-income and foreign-exchange contracts that are exchange traded derivatives or OTC derivatives. Exchange-traded derivatives are priced based on inputs using quoted prices in the active markets using observable inputs. Observable inputs reflect the assumptions market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the reporting entity. Therefore, these investments have been categorized as Level 1. OTC derivatives are priced based on inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly through corroboration with observable market data. Therefore, these investments have been categorized as Level 2. Pricing sources for these securities include Bloomberg, JDC, JP Morgan, and other commonly-used vendors. The investments in futures are settled on a daily basis. As such there are no fair values or unrecognized gains or losses included in the balance sheet as of April 30, 2013 and 2012 for the futures investments.

Commodity Derivative Instruments The fair values of gas swaps and power swaps that are priced based on inputs using quoted prices of similar exchange traded items have been categorized in Level 1 in the fair value hierarchy. These include gas and power swaps traded on exchanges.

The fair values of gas swaps, power swaps, gas options, power options and power deals that are priced based on inputs obtained through pricing agencies and developed pricing models, using similar observable items in active and inactive markets, are classified as Level 2 in the valuation hierarchy.

The fair values of derivatives assets and liabilities that are valued using pricing models with significant unobservable market data traded in less active or underdeveloped markets are classified as Level 3 in the valuation hierarchy. Level 3 items include gas swaps, power swaps, gas options, power options and power deals. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability (examples include long-dated or complex derivatives).

SRP does periodically transact at locations, market price points, or in time blocks that are non-standard or illiquid for which no prices are available from an independent pricing source. In these cases we apply adjustments based on historical price curve relationships to a more liquid price point as a proxy for market prices. Such transactions are classified as Level 3.

SRP estimates the fair value of its options using Black-Scholes option pricing models which includes inputs such as implied volatility, correlations, interest rates, and forward price curves.

All of the assumptions above include adjustments for counterparty credit risk, using credit default swap data, bond yields, when available, or external credit ratings.

SRP's assessments of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. SRP reviews the assumptions underlying its contracts monthly.

The following table provides quantitative information regarding significant unobservable inputs in SRP's Level 3 fair value measurements:

2013 S*2 ANNUAL REPORT 25 Fair Value at April 30, 2013 (in thousands)

Range of Assets Liabilities Unobservable Inputs Forward contracts: $9,531 $(2,078)

Market price per MWh $29.776- $61.143 Market price per Mmbtu $ 4.297- $ 5.110 Market price per Gallon $ 3.706-$ 3.712 Option contracts: 935 (28,639)

Market price per MWh $33.765 - $44.895 Market price per Mmbtu $ 3.996-$ 4.542 Power Volatility 19.80% -48.45%

Gas Volatility 20.36%- 48.18%

See Note [5], DERIVATIVE INSTRUMENTS, for additional detail of derivatives.

Investments Calculated at Net Asset Value As of April 30, 2013, the fair value measurement of investments calculated at net asset value per share (or its equivalent),

as well as the nature and risks of those instruments, is as follows:

Fair Value Unfunded Redemption Redemption (in thousands) Commitments Frequency Notice Period Mutual funds $268,015 None Daily N/A Commingled funds:

Fixed income funds 114,864 None Daily N/A Domestic long-short equity fund of funds 4,031 None Annual 100 days As of April 30, 2012, the fair value measurement of investments calculated at net asset value per share (or its equivalent),

as well as the nature and risks of those instruments, is as follows:

Fair Value Unfunded Redemption Redemption (in thousands) Commitments Frequency Notice Period Mutual funds $132,532 None Daily N/A Commingled funds:

Fixed income funds 116,445 None Daily N/A International equity funds 101,845 None Monthly 2 days Domestic long-short equity fund of funds 4,112 None Annual 100 days

26 2013 Sr,? ANNUAL REPORT Mutual funds: These are funds invested in either equity or fixed-income securities. They are actively managed funds that seek to outperform their respective benchmarks. The equity funds may invest in large and/or small capitalization stocks and/or growth or value styles, as dictated by their prospectuses. The fixed-income funds will invest in a broad array of securities, including treasuries, agencies, corporate debt, mortgage-backed securities, and some non-U.S. debt.

Fixed-income commingled funds: The funds are actively managed funds used by an investment manager to diversify an overall portfolio of separately managed fixed-income securities. The funds may invest in fixed-income securities of varying duration, maturity, credit quality and geographic location. The securities may be non-U.S. securities.

Internationalequity funds: The funds are actively managed funds that invest in primarily non-U.S. securities. The funds may invest in small and/or large capitalization stocks, as well as developing country securities. The funds seek to outperform their respective benchmarks.

Domestic long-short equity fund of funds The fund is an actively managed fund of funds that primarily invests in managers that invest in domestic and some non-U.S. equities. As a long-short fund, the fund seeks to neutralize market risk by balancing between managers that buy (go long) securities and managers who sell (go short) securities. The fund seeks to outperform a broad equity index over long periods, with less risk.

Collateral and Margin Deposits Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the positions. SRP presents a portion of its margin and cash collateral deposits net with its derivative position on the accompanying Combined Balance Sheets. Amounts recognized as margin and collateral provided to others are included in derivative assets and/or derivative liabilities in the accompanying Combined Balance Sheets. The margin deposits included in derivative assets totaled $70 and $6.4 million at April 30, 2013 and 2012, respectively. The collateral posted with trading counterparties included in derivative liabilities totaled $0 million and $20.8 million at April 30, 2013 and 2012, respectively.

Changes in Level 3 Fair Value Measurements The tables below include the reconciliation of changes to the balance sheet amounts (inthousands) for the years ended April 30 for financial instruments classified within Level 3 of the valuation hierarchy; this determination is based upon unobservable inputs to the overall fair value measurement:

Segregated Funds, net Commodity of Current Fiscal Year 2013 Derivatives Portion Total Beginning balance at May 1 $(48, 129) $ 4,112 $(44,017)

Transfers out of Level 3 24,461 - 24,461 Net realized and unrealized gain/

(loss) included in earnings 3,892 (81) 3,811 Purchases 1,480 - 1,480 Settlements (1,955) (1,955)

Balance at April 30 $ (20,251) $4,031 $ (16,220)

2013 SnP ANNUAL REPORT 27 Segregated Current Funds, net Portion of Commodity of Current Segregated Fiscal Year 2012 Derivatives Portion Funds Total Beginning balance at May 1 $ (5,330) $ 4,043 $161,981 $160,694 Transfers out of Level 3 3,477 3,477 Net realized and unrealized gain/

(loss) included in earnings (24,492) 69 380 (24,043)

Net realized and unrealized gain recorded as regulatory assets or liabilities 249 249 Sales (928,843) (928,843)

Purchases (19,050) 766,233 747,183 Settlements (2,734) (2,734)

Balance at April 30 $ (48,129) $4,112 $ $ (44,017)

Realized and unrealized gains and losses included in earnings identified above are included in wholesale revenues, power purchased, fuel cost, other operating expenses or investment income, as appropriate, in the accompanying Combined Statements of Net Revenues.

Fair Value Disclosures U.S. GAAP requires disclosure of the estimated fair value of certain financial instruments and the methods and significant assumptions used to estimate their fair values. Many but not all of the financial instruments are recorded at fair value on the accompanying Combined Balance Sheets. Financial instruments held by SRP are discussed below.

Financialinstruments for which fair value approximates carrying value: Certain financial instruments that are not carried at fair value on the accompanying Combined Balance Sheets are carried at amounts that approximate fair value due to their short-term nature and generally negligible credit risk. The instruments include receivables, accounts payable, customers' deposits, other current liabilities and commercial paper.

Financialinstruments for which fair value does not approximate carrying value: SRP presents long-term debt at carrying value on the accompanying Combined Balance Sheets. The collective fair value of the District's revenue bonds and the Desert Basin Lease-Purchase Agreement, including the current portion, was estimated by using pricing scales from independent sources. The carrying amount of commercial paper approximates fair value because of its short-term maturity and pricing confirmed through independent sources. As of April 30, 2013 and 2012, the carrying amounts, including current portion and accrued interest, were $4.3 billion and $4.5 billion, respectively, and the estimated fair values were

$4.8 billion and $4.9 billion, respectively. (See Note [7] LONG-TERM DEBT for further discussion of these items.)

28 2013 SM? ANNUAL REPORT (7) LONG-TERM DEBT AND CAPITAL LEASE OBLIGATION:

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

Interest Rate 2013 2012 Revenue bonds 2002 Series C (mature 2014 - 2015) 5.00% $ 50,170 $ 89,175 2004 Series A (mature 2014 - 2024) 4.00 - 5.00% 76,440 89,755 2005 Series A (mature 2027 - 2035) 4.75 - 5.00% 327,090 327,090 2006 Series A (mature 2033 - 2037) 5.00% 296,000 296,000 2008 Series A (mature 2016 - 2038) 5.00% 816,650 816,650 2009 Series A (mature 2014 - 2039) 2.75 - 5.00% 687,930 706,680 2009 Series B (mature 2014 - 2020) 3.00-4.50% 272,665 296,375 2010 Series A (mature 2040 - 2041) 4.839% 500,000 500,000 2010 Series B (mature 2014 - 2027) 2.00 - 5.00% 216,785 216,785 2011 Series A (mature 2013 - 2030) 2.00 - 5.00% 416,250 441,500 2012 Series A (mature 2029 - 2031) 5.00% 236,185 236,185 Total revenue bonds 3,896,165 4,016,195 Unamortized bond (discount) premium 172,722 191,810 Total revenue bonds outstanding 4,068,887 4,208,005 Finance lease 3.70 - 5.25% 155,395 178,390 Commercial paper 50,000 50,000 Total long-term debt 4,274,282 4,436,395 Less: Current portion of long-term (130,265) (143,025)

Total long-term debt, net of current $4,144,017 $ 4,293,370 The annual maturities of long-term debt (excluding unamortized bond discount/premium) as of April 30, 2013, due in fiscal years ending April 30, are as follows (in thousands):

Revenue Bonds Finance Lease 2014 $ 112,765 $ 17,500 2015 116,185 27,715 2016 106,960 16,075 2017 100,850 35,115 2018 102,880 11,345 Thereafter 3,356,525 47,645 Total $3,896,165 $ 155,395

2013 SRP ANNUAL REPORT 29 Revenue Bonds Revenue bonds are secured by a pledge of, and a lien on, the revenues of the electric system, after deducting operating expenses, as defined in the amended and restated bond resolution, effective inJanuary 2003, as amended (Bond Resolution). The Bond Resolution requires the District to charge and collect revenues sufficient to fund the debt reserve account and pay operating expenses, debt service, and all other charges and liens payable out of revenues and income.

Under the terms of the Bond Resolution, the District makes debt service deposits to a non-trusteed segregated fund. Included in segregated funds in the accompanying Combined Balance Sheets are $186.5 million and $190.2 million of debt-service-related funds as of April 30, 2013 and 2012, respectively. Additionally, the Bond Resolution requires the District to maintain a debt service coverage ratio of 1.1 or greater on outstanding revenue bonds. To be eligible to issue additional revenue bonds, the District must anticipate sufficient revenues to maintain that ratio post-issuance. For the years ended April 30, 2013 and 2012, the debt service coverage ratio was 2.56 and 2.59, respectively.

In October 2010, the District issued $500 million 2010 Series A Electric System Revenue Bonds as federally taxable, direct payment "Build America Bonds." Subject to the District's compliance with certain provisions of the ARRA and federal budget sequestration, the District expects to receive cash subsidy payments from the United States Treasury equal to 35% of the interest payable on the 2010 Series A Bonds over the term of the 2010 Series A Bonds. The District accrued $8.2 million and $8.5 million for cash subsidy payments earned from the United States Treasury for the years ending April 30, 2013 and 2012, respectively. The accrued cash subsidy payments are included in the Combined Statements of Net Revenues as a reduction to interest on bonds, net. Interest, Build America Bonds subsidy payments, and the amortization of the bond discount, premium, and issue expense on the various issues result in an effective rate of 4.29%over the remaining term of the bonds.

Due to federal budget sequestration, effective March 2013 the Internal Revenue Service published guidance stating that subsidy amounts claimed by Build America Bonds issuers will be reduced by 8.7% of the amount budgeted for such payments. The reduction rate is applicable until September 30, 2013, or intervening Congressional action, at which time the sequestration reduction rate is subject to change. Accordingly, the District's accrual has been reduced by the 8.7%

since March 2013, and the District's July 1, 2013 subsidy payment, which it received on June 4, 2013, was reduced by the 8.7%. The District receives subsidy amounts semiannually, with the next payment scheduled for January 1, 2014.

In October 2011, the District issued $441.5 million 2011 Series A Electric System Refunding Revenue Bonds, the proceeds of which were used to fund an externally trusteed irrevocable escrow to defease $479.2 million of outstanding Revenue Bonds (the 2011 Refunded Bonds). The funds in the escrow were applied to interest payments occurring after the sale and to the redemption price of the 2011 Refunded Bonds upon their respective call dates of January 1, 2012 and January 1, 2013. The bond defeasance is a non-cash activity on the Combined Statements of Cash Flows, and the 2011 Refunded Bonds have been removed from SRP's balance sheet.

In April 2012, the District issued $236.2 million 2012 Series A Electric System Refunding Revenue Bonds, the proceeds of which were used to fund an externally trusteed irrevocable escrow to defease $261.4 million of outstanding Revenue Bonds (the 2012 Refunded Bonds). The funds in the escrow were applied to interest payments occurring after the sale and to the redemption price of the 2012 Refunded Bonds upon their call date of January 1, 2013.. The bond defeasance is a non-cash activity on the Combined Statements of Cash Flows, and the 2012 Refunded Bonds have been removed from SRP's balance sheet.

The District has authorization to issue additional Electric System Revenue Bonds totaling $1.168 billion principal amount and Electric System Refunding Revenue Bonds totaling $5.007 billion principal amount.

30 2013 S*P ANNUAL REPORT Finance Lease In December 2003, the District entered into a lease-purchase agreement (Desert Basin Lease-Purchase Agreement) with Desert Basin Independent Trust (DBIT) to finance the acquisition of the Desert Basin Generating Station (Desert Basin),

located in central Arizona. In a concurrent transaction, $282.7 million in fixed-rate Certificates of Participation (COPs) were issued pursuant to a Trust Indenture, currently between U.S Bank National Association, as trustee, and DBIT, to fund the acquisition of Desert Basin and other electric system assets of the District. Investors in the COPs obtained an interest in the lease payments made by the District to DBIT under the Desert Basin Lease-Purchase Agreement. Due to the nature of the Desert Basin Lease-Purchase Agreement, the District has recorded a lease-finance liability to DBIT with the same terms as the COPs.

Capital Lease Obligation In May 2008, the District entered into a 20-year power purchase agreement to purchase energy from a 575 megawatt (MW) simple-cycle, natural-gas peaking facility. The commercial operation date of the facility was May 1, 2011. Upon expiration of the contract and with proper notice, the District may renew the agreement for another 10 years, subject to certain conditions. Under the agreement, the District will pay a capacity charge, operation and maintenance costs, and property taxes. The District is also obligated to provide the natural gas needed to operate the facility. The capacity charge is paid monthly and will total approximately $51.9 million yearly. The District has concluded that this power purchase agreement is a capital lease. Accordingly, a capital lease asset and corresponding liability were recorded on May 1, 2011 in the amount of $5170 million. The capital lease asset is being amortized on the straight-line basis over the original 20-year term of the contract. Accumulated amortization as of April 30, 2013 and 2012 is $50.6 million and $24.8 million respectively. The addition of the capital lease asset was excluded from investing activities in the 2012 Statement of Cash Flows as a non-cash item.

Future minimum lease payments, excluding executory costs, under the capital lease as of April 30, 2013 are as follows (in thousands):

2014 $ 51,867 2015 51,867 2016 51,867 2017 51,867 2018 51,867 Thereafter 674,273 Total minimum lease payments 933,608 Less: Imputed interest (425,364)

Less: Imputed lessor profit on executory costs (14,619)

Less: Current portion of capital lease obligation (13,095)

Long-term capital lease obligation $ 480,530 (8) COMMERCIAL PAPER AND CREDIT AGREEMENTS The District is authorized by the Board to issue up to $500.0 million in commercial paper. The District had $50.0 million Series C Commercial Paper outstanding at April 30, 2013 and 2012. At April 30, 2013 and 2012, the Series C issue had an average weighted interest rate to the District of 0.17% and 0.19%, respectively. The commercial paper matures not more than 270 days from the date of issuance and is an unsecured obligation of the District.

2013 SRP ANNUAL REPORT 31 The District has a $100.0 million revolving line-of-credit agreement, $50.0 million of which supported the $50.0 million of outstanding commercial paper at April 30, 2013. The revolving credit agreement expires on May 16, 2017 SRP has classified the commercial paper program as long-term debt in the accompanying Combined Balance Sheets at April 30, 2013 and 2012. On June 25, 2013 SRP finalized another $400.0 million revolving line-of-credit agreement. This revolving credit agreement expires on June 25, 2018. The additional $450.0 million in credit under the two lines of credit may be used to support the issuance of additional commercial paper or for other general corporate purposes.

The revolving line-of-credit agreements contain various conditions precedent to borrowings that include, but are not limited to, compliance with the covenants set forth in the agreements, 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 was in compliance with the various covenants at April 30, 2013 and 2012. The District has never borrowed under the agreements. Alternative sources of funds to support the commercial paper program include existing funds on hand or the issuance of alternative debt, such as revenue bonds.

(9) EMPLOYEE BENEFIT PLANS AND INCENTIVE PROGRAMS:

Defined Benefit Pension Plan and Other Postretirement Benefits SRP's Employees' Retirement Plan (the Plan) covers substantially all employees. The Plan is funded entirely from SRP contributions and the income earned on invested Plan assets. SRP made contributions of $60.0 million and $132.0 million, respectively, in fiscal years 2013 and 2012.

SRP provides a non-contributory defined benefit medical plan for retired employees and their eligible dependents lcontributory 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 at any time after attainment of age 55 with a minimum of ten years of vested service under the Plan (20 years for those hired January 1, 2000 or later). The funding policy is discretionary and is based on actuarial determinations.

U.S. GAAP requires employers to recognize the overfunded or underfunded positions of defined benefit pension and other postretirement plans in their balance sheets. Any actuarial gains and losses, prior service costs, and transition assets or obligations must be recorded on the balance sheet with an offset to accumulated other comprehensive income until the amounts are amortized as a component of net periodic benefit costs.

The Board has authorized the District to collect future amounts associated with the pension and other postretirement plan liabilities as part of the pricing process. The District established a regulatory asset for the amounts otherwise chargeable to accumulated other comprehensive income that are expected to be recovered through prices in future periods. The changes in actuarial gains and losses, prior service costs, and transition assets or obligations pertaining to the regulatory asset are recognized as an adjustment to the regulatory asset or liability accounts, as these amounts are recognized as components of net periodic pension costs each year. The District's amortization amounts for fiscal year 2013 are $1.9 million for prior service cost and $48.5 million for net actuarial loss. The District's amortization amounts for fiscal year 2012 are $2.1 million for prior service cost and $31.1 million for net actuarial loss.

The following tables outline changes in benefit obligations, plan assets, the funded status of Ihe plans and amounts included in the accompanying Combined Financial Statements (in thousands):

32 2013 S*7 ANNUAL REPORT Pension Benefits Postretirement Benefits 2013 2012 2013 2012 Change in benefit obligation Benefit obligation at beginning of year $ 1,736,633 $ 1,486,308 $ 625,399 $ 561,446 Service cost 50,332 42,662 13,020 11,440 Interest cost 83,831 82,881 30,216 31,346 Actuarial loss (gain) 224,247 183,801 94,510 41,402 Benefits paid (81,004) (59,019) (20,358) (20,235)

Benefit obligation at end of year $ 2,014,039 $ 1,736,633 $ 742,787 $ 625,399 Change in plan assets Fair value of plan assets at beginning of year $ 1,466,878 $ 1,352,929 $ $

Actual return on plan assets 212,391 40,968 Employer contributions 60,000 132,000 20,358 20,235 Benefits paid (81,004) (59,019) (20,358) (20,235)

Fair value of plan assets at end of year 1,658,265 1,466,878 Funded status at end of year $ (355,774) $ (269,755) $ (742,787) $ (625,399)

Amounts recognized in Combined Balance Sheets:

Other current liabilities $ $ $ (23,969) $ (22,519)

Accrued post-retirement liability (355,774) (269,755) (718,818) (602,880)

Net asset (liability) recognized $ (355,774) $ (269,755) $ (742,787) $ (625,399)

Amounts recognized as a regulatory asset Transition obligation (asset) $ - $ $ (1) $ (2)

Prior service cost (credit) 1,967 4,108 (6,520) (6,786)

Net actuarial loss (gain) 828,355 733,206 261,952 175,534 Net regulatory asset $ 830,322 $ 737,314 $ 255,431 $ 168,746 The following table represents the amortization amounts expected to be recognized or paid during the fiscal year ending April 30, 2014 (inthousands):

Pension Postretirement Benefits Benefits Prior service cost/(credit) $ 1,619 $ (270)

Net actuarial $54,100 $13,206

2013 SRP ANNUAL REPORT 33 The following table outlines the projected benefit obligation and accumulated benefit obligation in excess of Plan assets (in thousands):

2013 2012 Projected benefit obligation $ 2,014,039 $1,736,633 Accumulated benefit obligation $ 1,731,165 $1,507,028 Fair value of Plan assets $ 1,658,265 $ 1,466,878 SRP internally funds its other postretirement benefits obligation. At April 30, 2013 and 2012, $584.9 million and $525.7 million of segregated funds, respectively, were designated for this purpose.

The weighted overage assumptions used to calculate actuarial present values of benefit obligations at April 30 were as follows:

Pension Benefits Postretirement Benefits 2013 2012 2013 2012 Discount rate 4.27% 4.92% 4.27% 4.92%

Rate of compensation increase 4.00% 4.00% N/A N/A Weighted average assumptions used to calculate net periodic benefit costs were as follows:

Pension Benefits Postretirement Benefits 2013 2012 2013 2012 Discount rate 4.92% 5.69% 4.92% 5.69%

Expected return on Plan assets 8.25% 8.25% N/A N/A Rate of compensation increase 4.00% 4.00% N/A N/A For employees who retire at age 65 or younger, for measurement purposes, a 70% annual increase before attainment of age 65 and a Z0%annual increase on and after attainment of age 65 in per capita costs of health care benefits were assumed during 2013; these rates were assumed to decrease uniformly until equaling 5% in all future years.

34 2013 SaP ANNUAL REPORT The components of net periodic benefit costs for the years ended April 30, are as follows (inthousands):

Pension Benefits Postretirement Benefits 2013 2012 2013 2012 Service cost $ 50,332 $ 42,662 $13,020 $11,440 Interest cost 83,831 82,881 30,216 31,346 Expected return on Plan assets 1123,670) 1112,972)

Amortization of transition obligation (1) (1)

Amortization of net actuarial loss 40,378 24,708 8,092 6,349 Amortization of prior service cost 2,141 2,315 (266) (203)

Net periodic benefit cost $ 53,012 $ 39,594 $51,061 $48,931 Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in the assumed health care cost trend rates would have the following effect (inthousands):

One Percentage One Percentage Point Increase Point Decrease Effect on total service cost and interest cost components $ 8,395 $ (6,463)

Effect on postretirement benefit obligation $138,312 $(95,781)

Plan Assets The Board has established an investment policy for Plan assets and has delegated oversight of such assets to a compensation committee (the Committee). The investment policy sets forth the objective of providing for future pension benefits by targeting returns consistent with a stated tolerance of risk. The investment policy is based on analysis of the characteristics of the Plan sponsors, actuarial factors, current Plan condition, liquidity needs, and legal requirements.

The primary investment strategies are diversification of assets, stated asset allocation targets and ranges, and external management of Plan assets. The Committee determines the overall target asset allocation ratio for the Plan and defines the target asset allocation ratio deemed most appropriate for the needs of the Plan and the risk tolerance of the District.

The market value of investments (reflecting returns, contributions, and benefit payments) within the Plan trust appreciated 14.75% during fiscal year 2013, compared to an increase of 2.95% during fiscal year 2012. Changes in the Plan's funded status affect the assets and liabilities recorded on the balance sheet in accordance with FASB authoritative guidance.

Due to the District's regulatory treatment, the recognition of funded status is offset by regulatory assets or liabilities and is recovered through prices. The Pension Protection Act (PPA) of 2006 establishes new minimum funding standards and restricts plans underfunded by more than 20% from adopting amendments that increase plan liabilities unless they are funded immediately. In December 2008, the Worker, Retiree, and Employer Recovery Act (WRERA) was enacted. Among other provisions, the WRERA provides temporary funding relief to defined benefit plans during the current economic downturn. The Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 (PACMBPRA) was signed into law during fiscal year 2011. During fiscal year 2013, the Moving Ahead for Progress in the 21 st Century Act (MAP-21) was passed, which included a provision related to pension funding. All three acts subsequent to the passage of the PPA, WRERA, PACMBPRA, and MAP-21 will favorably affect the level of minimum required contributions.

2013 SnP ANNUAL REPORT 35 The Plan's weighted-average asset allocations are as follows:

Target Allocations 2013 2012 Equity securities 65.0% 62.4% 61.9%

Debt securities 25.0% 29.2% 29.4%

Real estate 10.0% 8.4% 8.7%

Total 100.0% 100.0% 100.0%

The investment policy, as authorized by the Board, allows management to reallocate Plan assets at any time within a tolerance range up to plus or minus 5% from the target asset allocation which allows for flexibility in managing the assets based on prevailing market conditions and does not require automatic rebalancing ifthe actual allocation strays from the target allocation.

Securities Lending As of April 30, 2013 and 2012, the Plan participated in a securities lending program with the trustee of the investments.

The program authorizes the trustee of the particular investments to lend securities, which are assets of the plans, to approved borrowers. The trustee requires borrowers, pursuant to a security lending agreement, to deliver collateral to secure each loan. The loaned securities are required to be collateralized. Under the program, the borrowers deliver collateral having a market value not less than 102% of the market value of the loaned securities. The cash collateral received is invested in a collateral pool made up of fixed income securities. The Plan bears the risk of loss with respect to unfavorable changes in fair value of the invested collateral.

Fair Value of Plan Assets The following table sets forth the fair value of Plan assets, by asset category, at April 30, 2013 (dollars in thousands):

Level 1 Level 2 Level 3 Total Money market funds $221,879 $ 49,040 $ $ 70,919 Mutual funds 404,765 404,765 U.S. government securities 90,958 90,958 Corporate bonds 242,833 242,833 Corporate stocks 437,130 318 437,448 Commingled funds 166,052 88,857 254,909 Real estate 140,126 140,126 Exchange traded derivatives 62,426 - 62,426 OTC derivatives 81,368 81,368 Exchange traded derivative liabilities (45,806) (45,806)

OTC derivative liabilities (81,681) (81,681)

Total assets $ 880,394 $ 548,888 $ 228,983 $1,658,265 The fair value of the Plan assets excludes $349.1 million payable for collateral on loaned securities in connection with the participation of the Plan in securities lending programs.

36 2013 52'n ANNUAL REPORT The following table sets forth the fair value of Plan assets, by asset category, at April 30, 2012 (dollars in thousands):

Level 1 Level 2 Level 3 Total Money market funds $ 8,857 $ 45,727 $ $ 54,584 Mutual funds 278,057 278,057 U.S. government securities 98,194 98,194 Corporate bonds 206,297 206,297 Corporate stocks 382,102 398 382,500 Commingled funds 232,121 85,111 317,232 Real estate 128,234 128,234 Exchange traded derivatives 46,596 46,596 OTC derivatives 46,003 46,003 Exchange traded derivative liabilities (43,960) (43,960)

OTC derivative liabilities (46,859) (46,859)

Total assets $671,652 $581,881 $213,345 $ 1,466,878 The fair value of the Plan assets excludes $332.7 million payable for collateral on loaned securities in connection with the participation of the Plan in securities lending programs.

For a description of the fair value hierarchy, refer to Note [6] FAIR VALUE MEASUREMENTS.

Valuation Methodologies Real estate: Real estate commingled funds are funds with a direct investment in a pool of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, real estate investments have been categorized as Level 3 investments. The valuations of the real estate funds are sensitive to market factors outside the control of the Plan, including interest rate levels and economic activity. The valuations, although done quarterly by independent qualified appraisers, may vary due to these factors.

Exchange traded derivatives: The fair values of exchange traded options and futures are priced based on inputs using quoted prices in active markets using observable inputs. Observable inputs reflect the assumptions market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the reporting entity. Therefore, these investments have been categorized as Level 1.

OTC derivatives: The fair values of OTC options, forwards, swaptions, and swaps are priced based on inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly through corroboration with observable market data. Therefore, these investments have been categorized as Level 2 in the fair value hierarchy.

For an explanation of the valuation methodologies used to determine fair value of the assets of the Plan that are not listed above, refer to Note [6] FAIR VALUE MEASUREMENTS.

Changes in Level 3 Fair Value Measurements The table below includes the reconciliation of changes to the balance sheet amounts for the years ended April 30 for financial instruments classified within Level 3 of the valuation hierarchy; this determination is based upon unobservable inputs to the overall fair value measurement:

2013 SIP ANNUAL REPORT 37 Plan Assets (in thousands) 2013 2012 Beginning balance at May 1 $213,345 $163,034 Actual return on plan assets relating to assets still held at end of period 15,638 15,051 Purchases - 35,260 Balance at April 30 $ 228,983 $213,345 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.

Employer Contributions SRP expects to contribute $60.0 million to the Plan over the next valuation period.

Benefits Payments SRP expects to pay benefits in the amounts as follows (inthousands):

Pension Benefits Postretirement Benefits Before Subsidy* Net 2014 $ 70,031 $ 24,778 $ 23,969 2015 74,456 26,805 25,910 2016 79,415 29,031 28,040 2017 84,483 31,164 30,077 2018 90,283 33,170 31,966 2019 through 2023 535,959 193,018 185,310

• Estimated future benefit payments, including prescription drug benefits, prior to federal drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

Defined Contribution Plan SRP's Employees' 401(k) Plan (the 401(k) Plan) covers substantially all employees. The 401Nk) 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 $0.90 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 $16.0 million and $14.8 million during fiscal years 2013 and 2012, respectively.

Employee Performance Incentive Compensation Program During fiscal year 2013, the Employee Performance Incentive Compensation [EPIC) program was approved by the Board. EPIC covers substantially all regular employees, and the fiscal year 2013 incentive compensation is based on the achievement of pre-established targets for fiscal year 2013. The fiscal year 2012 incentive compensation was based on the achievement of pre-established targets for the fiscal years 2011 and 2012 combined. The total compensation accrued for EPIC in fiscal years 2013 and 2012 was $25.5 million and $275 million, respectively.

38 2013 SQP ANNUAL REPORT (10) INTERESTS IN JOINTLY OWNED ELECTRIC UTILITY PLANTS AND TRANSMISSION FACILITIES:

The District has entered into various agreements with other electric utilities for the joint ownership of electric generating and transmission facilities. Each participating owner in these facilities must provide for the cost of its ownership share. The District's share of expenses of the jointly owned plants and transmission facilities is included in operating expenses in the accompanying Combined Statements of Net Revenues.

The following table reflects the District's ownership interests in jointly owned electric utility plants as of April 30, 2013 (inthousands):

Construction Ownership Plant in Accumulated Work Generating Station Share Service Depreciation In Progress Four Corners (NM) (Units 4 & 5) 10.00% $ 123,829 $ (103,880) $ 5,810 Navajo (AZ) (Units 1, 2 & 3) 21.70% 342,416 (324,295) 18,836 Hayden (CO) (Unit 2) 50.00% 141,856 (118,844) 2,334 Craig (CO) (Units 1 & 2) 29.00% 287,458 (248,420) 5,413 Mesquite Common 50.00% 78,075 (376) 464 PVNGS (AZ) (Units 1, 2 & 3) 17.49% 1,209,605 (1,033,221) 57,068

$2,183,239 $(1,829,036) $ 89,925 The following table reflects the District's investment in jointly owned transmission facilities as of April 30, 2013 (in thousands):

Construction Plant in Accumulated Work Transmission Facility Service Depreciation In Progress Mead Phoenix $ 53,329 $ (14,879) $ 3 Southwest Valley 77,477 (11,743)

Southeast Valley 184,642 (10,956) 77 Morgan-Pinnacle Peak 64,256 (1,368) 6,610 El Dorado 11,637 (4,211)

Southern Transmission 72,215 (30,714)

Mesquite 24,435 (54) 223 ANPP 70,843 (23,581) 13

$ 558,834 $ (97,506) $ 6,926

2013 sKP ANNUAL REPO.T 39 (11) VARIABLE INTEREST ENTITIES:

SRP follows guidance that defines a variable interest entity (VIE) as a legal entity whose equity owners do not have sufficient equity at risk or lack certain characteristics of a controlling financial interest in the entity. This guidance identifies the primary beneficiary as the variable interest holder that has the power to direct the activities that most significantly affect the VIE's economic performance (power criterion) and has the obligation to absorb losses or the right to receive benefits from the VIE (losses/benefits criterion). The primary beneficiary is required to consolidate the VIE unless specific exceptions or exclusions are met. SRP considers both qualitative and quantitative factors to form a conclusion whether it, or another interest holder, meets the power criterion and the losses/benefits criterion. SRP performs ongoing reassessments of its VIEs to determine if the primary beneficiary changes each reporting period.

Unconsolidated VIEs While SRP is not required to consolidate any VIE as of April 30, 2013 or 2012, it held variable interests in certain VIEs as described below.

In May 2008, the District entered into a 20-year power purchase agreement to purchase energy from a 575 MW simple-cycle natural-gas peaking facility. The District has concluded that this power purchase agreement is a capital lease.

The District has also determined that it is not the primary beneficiary of this VIE since it does not control operations and maintenance, which it believes are the primary activities that most significantly affect the economic activities of the entity.

See further discussion in Note [7] LONG-TERM DEBT AND CAPITAL LEASE OBLIGATION.

The District has entered into various long-term power purchase agreements with developing renewable energy generation facilities that extend for periods of 20 to 30 years. One facility, with capacity of approximately 19 MW, began commercial operation in fiscal year 2013 and two facilities, with capacities of 50 MW and 20 MW, began commercial operation in fiscal year 2012. The District is receiving the power and renewable energy credits from these facilities and other facilities started in prior years. The amounts that the District paid to these projects were $78.1 million and $34.3 million for fiscal years 2013 and 2012, respectively. Additional facilities are expected to begin commercial operation between fiscal year 2014 and fiscal year 2016. The expected capacity of all the facilities combined, once in operation, is approximately 291 MW. With the exception of two projects for which the District is obligated to pay operating and maintenance expenses, the District is obligated to pay only for actual energy delivered and will have no obligation with respect to any facilities that do not start commercial operations. Some of these agreements include a price adjustment clause that will affect the future cost. There are no minimum payment obligations under these agreements. The District has concluded that it is not the primary beneficiary of these VIEs since it does not control operations and maintenance, which it believes are the primary activities that most significantly affect the economic activities of the entity.

The District formed a partnership during fiscal year 2010 to market long-term water storage credits. The District made net capital contributions of $1.3 million and $2.0 million to the partnership and carried $4.3 million and $3.4 million of investment in the partnership in fiscal years 2013 and 2012, respectively. The District has a future maximum exposure up to a $25.0 million contribution limit. The primary risks associated with this VIE relate to the marketing of the water storage credits. The District has concluded that it is not the primary beneficiary of this VIE since it does not have power to direct the activities related to the marketing of the long-term water storage credits, which represent the most significant economic activities of the VIE.

40 2013 SU1 ANNUAL REPORT (12) COMMITMENTS:

Purchased Power and Fuel Supply The District had various firm, noncancelable purchase commitments at April 30, 2013, which are not recognized in the accompanying Combined Balance Sheets. The following table presents actual payments and estimated future payments pertaining to firm purchase commitments with remaining terms greater than one year [in millions):

Total Payments Purchase Commitments 2013 2012 2014 2015 2016 2017 2018 Thereafter Purchase power contracts$ 61.0 $109.0 $ 34.8 $ 38.3 $ 38.9 $ 39.6 $ 40.3 $ 821.1 Fuel supply contracts 379.6 370.2 337.6 333.1 289.3 262.5 178.4 671.8 Total $ 440.6 $ 479.2 $372.4 $ 371.4 $ 328.2 $ 302.1 $ 218.7 $ 1,492.9 Gas Purchase Agreement In October 2007, the District entered into a 30-year gas purchase agreement with Salt Verde Financial Corporation ISVFC), 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 10,425,000 MMBtus (millions of British thermal units) of natural gas in fiscal years 2014 and 2015, 10,270,000 MMBtus in fiscal year 2016, 10,420,000 MMBtus in fiscal years 2017 and 2018, and 208,400,000 MMBtus over the balance of the term. These purchases are expected to supply approximately 20% of its projected natural-gas requirements needed to serve retail customers over the remainder of the 30-year period.

The District receives a discount off market prices and is obligated to pay only for gas delivered. Payments, net of discount, to SVFC under the agreement were $177 million and $31.6 million in fiscal years 2013 and 2012, respectively. The agreement also provides for payment from SVFC to the District of certain excess cash resulting from a portion of SVFC's investment income, which effectively reduces the price the District pays for the gas. The excess cash amounts received by the District from SVFC totaled $3.1 million and $2.8 million for fiscal years 2013 and 2012, respectively.

Operating Leases The District entered into various operating leases to facilitate the operations of Springerville Generating Station ISpringerville) Unit 4, a 400 MW coal-fired plant owned by the District and operated by Tucson Electric Company (TEP).

Total payments under the agreements to TEP and other parties were $13.8 million and $13.0 million in fiscal years 2013 and 2012, respectively. Minimum payments under these agreements are estimated to be $13.5 million in fiscal years 2014 and 2015, $9.8 million in fiscal years 2016, 2017, and 2018 and $250.9 million thereafter. The leases expire in various years from 2015 through 2106.

(13) CONTINGENCIES:

Nuclear Insurance Under existing law, public liability claims arising from a single nuclear incident are limited to $12.595 billion. PVNGS participants insure for this potential liability through commercial insurance carriers to the maximum amount available

($375.0 million) with the balance covered by an industry-wide retrospective assessment program as required by the Price-Anderson Act. If losses at any nuclear power plant exceed available commercial insurance, the District could be assessed retrospective premium adjustments. The maximum assessment per reactor per nuclear incident under the retrospective

2013 SiIP ANNUAL REPORT 41 program is $117.5 million, including a 5% surcharge applicable in certain circumstances, but not more than $175 million per reactor may be charged in any one year for each incident. Based on the District's ownership share of PVNGS, the maximum potential assessment would be $61.7 million, including the 5% surcharge, but would be limited to $9.2 million per incident in any one year.

PVNGS participants also maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. The District has also secured insurance against portions of any increased cost of generation or purchased power and any business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The coverage for property damage, decontamination, and replacement power is provided by Nuclear Electric Insurance Limited (NEIL). The District is subject to retrospective assessments under all NEIL policies if NEIL's losses in any policy year exceed accumulated funds. The maximum amount of retrospective assessments the District could incur under the NEIL policies totals approximately $10.9 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

Spent Nuclear Fuel Under the Nuclear Waste Policy Act of 1982, the District pays $0.001 per kilowatt-hour on its share of net energy generation at PVNGS to the U.S. Department of Energy (DOE). However, to date, for various reasons, the DOE has not constructed a site for the storage of spent nuclear fuel. Accordingly, Arizona Public Service Company lAPS), the operating agent for PVNGS, has constructed an on-site dry cask storage facility to receive and store PVNGS spent fuel.

PVNGS has sufficient capacity at its on-site spent fuel storage installation to be able to store all of the nuclear fuel that will be spent during the first operating license period which ends in December 2027 In addition, PVNGS has sufficient capacity to store a portion of the fuel that will be spent during the period of extended operation, which will end in December 2047 Potentially, and depending on how the NRC rules on the future unloading of spent fuel pools, PVNGS could use high capacity storage casks to store the balance of any fuel spent during the extended license period. The on-site facility stored its first cask in March 2003. As of April 30, 2013, one hundred one casks were being stored at the on-site facility.

The District's share of on-site interim storage at PVNGS is estimated to be $73.3 million for costs to store spent nuclear fuel from inception through the life of the plant. These costs are recovered through the District's base rates as a component of the system benefit charge. At April 30, 2013 and 2012, the District's accrued spent fuel storage cost was $23.8 million and $25.8 million, respectively, and is included in deferred credits and other non-current liabilities on the accompanying Combined Balance Sheets.

Coal Supply Black Mesa Environmental Impact Statement: In 2008, the Office of Surface Mining, Reclamation and Enforcement

("OSM") issued an Environmental Impact Statement ("EIS") to allow Peabody to include the Black Mesa Mine (which formerly served the Mohave Generating Station) in the permit for the Kayenta Mine (which serves NGS). Under the administrative appeals process, numerous appeals of the permit decision were filed, and a decision was issued that the process OSM had followed to issue the permit was inadequate. In response to the decision, Peabody filed an application for a permit renewal for the Kayenta Mine. On January 6, 2012, the OSM approved a five-year renewal of the permit through July 6, 2015. In February 2012, three separate appeals of the renewal were filed by various environmental and tribal groups, following which the District successfully intervened in the matter. Although an Administrative Law Judge ("ALl")

issued a decision disposing of several of the claims in the appeals, certain claims were left for hearing. The proceedings have been stayed pending discussions among the parties regarding the possible resolution of some of the remaining claims. The District cannot predict the outcome of this matter at this time.

42 2013 EP ANNUAL REPORT Navajo Mine Permit BHP Billiton Limited (BHP) operates the Navajo Coal Mine, which supplies Four Corners Generating Station (Four Corners), in which the District owns 10% of units 4 and 5. Several environmental groups have filed lawsuits challenging the mining permit and expanded operations. If these lawsuits were successful, they would result not only in an increased cost of mining operations, which would be passed to the owners of the generating station, but could also result in the suspension or termination of mining activities. APS, as operating agent of Four Corners, is working with BHP and other defendants to allow the expansion and continuation of the mine. The District cannot predict the outcome of these lawsuits at this time.

Trapper Mine Permit On February 27, 2013, WildEarth Guardians (WEG) filed suit in the U.S. District Court for the District of Colorado against the Office of Surface Mining (OSM), Al Klein, the Western Regional Director of the OSM and Secretary of the Interior Ken Salazar (Secretary) (the Complaint). In the Complaint, WEG alleges that the OSM violated the National Environmental Policy Act JNEPAl and the Administrative Procedure Act (APA) by "unlawfully approving mining plans for the Colowvyo and Trapper Mines in Colorado" and the plans of five other mines located in Montana, New Mexico and Wyoming. The District owns a 32.1% interest in Trapper Mining Inc. (Trapper), which owns the Trapper Mine.

Trapper Mine serves Craig Generating Station, in which the District owns 29% of Units 1 and 2. WEG alleges, among other things, that the Secretary's approval of Trapper's 2009 modification to its existing mining plan (lthe 2009 Trapper Plan) violated the terms of NEPA and the APA on various grounds. WEG asks the Court to reverse the Secretary's approval of the 2009 Trapper Plan and enjoin Trapper from continuing its mining operations until OSM demonstrates compliance with NEPA and the APA when considering approval of the 2009 Trapper Plan. Trapper has intervened in the suit. The District cannot predict the outcome of this lawsuit at this time.

Environmental SRP is subject to numerous legislative, administrative and regulatory requirements at the federal, state and local levels, as well as lawsuits relative to air quality, water quality, hazardous waste disposal and other environmental matters.

Such requirements have resulted, and will continue to result, in increased costs associated with the operation of existing properties. At April 30, 2013 and 2012, SRP accrued $35.6 million and $36.4 million, respectively, for environmental issues, on a non-discounted basis, which is included in deferred credits and other non-current liabilities on the accompanying Combined Balance Sheets. The following topics highlight some of the major environmental compliance issues affecting SRP.

Water quality: Due to the nature of its business, from time to time the District is involved in various state and federal superfund matters. In September 2003, the EPA notified the District that it might be liable under 1he federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) as an owner and operator of a facility within the Motorola 52nd Street Superfund Site Operable Unit 3. The District completed the remedial investigation at the facility, but other potentially responsible parties are still undertaking remedial investigations and feasibility studies and the District could still be liable for past costs incurred and for future work to be conducted within the Superfund Site with regard to groundwater. At the adjacent West Van Buren Water Quality Assurance Revolving Fund Site, a state superfund site, the Roosevelt Irrigation District (RID) has sued the District and numerous other parties claiming that as a result of groundwater contamination, RID has been damaged in excess of $125.0 million. The District denies the allegations and intends to vigorously contest the claim. Although the plaintiff has dismissed the District from the litigation, Maricopa County has filed a Third Party Complaint against the District and other parties, which will bring the District back into the litigation. While the District is unable at this time to predict the outcome of these matters, it believes it has recorded adequate reserves as part of its environmental reserves to cover expected liabilities related to these issues.

Air quality: Efforts to reduce emissions from fossil fuel power plants will substantially increase the 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 reductions in emissions of mercury and other pollutants at its coal-fired power plants, including plants located on the Navajo Reservation. In particular, under the terms of a consent agreement with the EPA, the District agreed

2013 SRP ANNUAL REPORT 43 in 2008 to install additional pollution control equipment at CGS at a projected cost of approximately $539.0 million, with work expected to be completed in approximately June 2014. As of April 30, 2013, approximately $31.8 million remains to be completed.

The full significance of air-quality standards and emissions-reduction initiatives to the District in terms of costs and operational problems is difficult to predict, but recent regulatory actions mean that costly equipment will be added to units now in operation. In addition, the cost of fossil fuel purchased by the District may increase and 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 relating to renewable energy and restricting greenhouse gas (GHG) emissions. The District cannot predict the impact of such initiatives on the District at this time.

The District has negotiated a Consent Order with the Arizona Department of Environmental Quality (ADEQ), pursuant to which the District will delay compliance with current Arizona limitations on mercury emissions until 2016, and instead implemented a control strategy designed to achieve a 70% reduction of mercury emissions at CGS on a facility-wide annual average basis beginning January 1, 2012 at an estimated annual cost of $2.4 million.

In February 2012, the EPA published its Mercury and Air Toxics Standards (MATS) rule, which contains emissions standards for hazardous air pollutants from existing and new coal- and oil-fired power plants under the Clean Air Act (CAA),

including emissions of mercury, trace minerals, acid gases and organic compounds. These standards are effective in April 2015, unless one or more facilities are granted an extension under the CAA. Additional controls may be required at several of the coal-fired plants in which the District has an interest. The District is analyzing the final rule and potential effects on future operations at its coal-fired plants and cannot yet estimate the associated costs. The District anticipates this rule will require new controls for mercury at CGS and NGS, but has not yet made a final determination on control strategy at either facility.

Provisions of the EPA's Regional Haze Rule require emissions controls known as Best Available Retrofit Technology (BART) for coal-fired power plants and other industrial facilities that emit air pollutants that reduce visibility in Class I areas, such as national parks. The District has financial interests in several coal-fired power plants that are subject to the BART requirements.

The EPA proposed a BART determination for NGS inJanuary 2013. The District owns 21.7% of NGS. The District believes that BART for NGS requires the installation on all three units of low-NOx burners and separated over-fired air (LNB/SOFA).

The [NB/SOFA equipment has been installed on all three units at a total cost of approximately $45.0 million, of which the District's share was $9.8 million. Nevertheless, the EPA has proposed a BART emissions limit for NGS of 0.0551b/

MMbtu that would likely require the installation of post-combustion controls such as selective catalytic reduction (SCR). It is also possible that additional controls for sulfuric acid mist emissions and fine particulate matter will be required. Collectively these controls would cost approximately $1.1 billion, of which the District's share would be approximately $240.0 million.

Based on the proposal, achievement of the proposed BART limit would be required by 2018. The EPA proposed an alternative that would give the NGS owners credit for previous installation of low-NOx burners, and allow SCR to be installed on one unit per year between 2021 and 2023. The EPA also invited the submittal of other alternative proposals that achieve benefits equal to or greater than the EPA's proposal. The District is evaluating the options provided by the EPA and will file comments later in 2013. It is not known when the EPA will publish a final rule.

With respect to CGS, the District submitted a BART analysis to the ADEQ in 2008. The ADEQ completed its review of CGS and other BART-eligible sources and in 2011 sent a proposed State Implementation Plan (SIP) to the EPA that, among other things, accepted current controls at CGS as BART, subject to completion of pollution control equipment additions that are scheduled to be completed in 2014 pursuant to a consent decree. By letter dated November 17 2011, the EPA indicated that it planned to develop a partial Regional Haze Federal Implementation Plan ("FIP") for the State of Arizona, including potentially revisiting the BART determination for CGS to determine whether any additional pollution controls

44 2013 SrZP ANNUAL REPORT are warranted, such as the addition of SCR on the remaining unit. On December 5, 2012, the EPA finalized the FIP that imposes new emissions limits for PM, S02, and NOx under the BART provisions of the rule. The limit for NOx will require installation of a second SCR system at CGS. The projected capital cost to the District of additional SCR at CGS is approximately $110 million. The District must meet the new limits by January 4, 2018. The District has filed for judicial review of the final FIP with the U.S. Court of Appeals for the 91h Circuit and has also filed an Administrative Petition for Reconsideration with the EPA. In April 2013, the EPA sent a letter to the District indicating it would grant the District's Petition for Reconsideration on a limited subset of the concerns listed in the petition. The EPA has yet to publish a Federal Register notice granting the petition. It is too soon to predict the outcome of this matter.

On August 6, 2012, the EPA issued its final BART determination for Four Corners that requires the installation of SCRs on all five units, or the closure of units 1, 2 and 3 and SCRs on units 4 and 5. SCR for units 4 and 5 could cost $530.0 million, of which the District's share would be $53.0 million. The new SCRs would be required to be operational by July 31, 2018.

The BART determinations for District-owned generating stations in Colorado were finalized on December 31, 2012. The final determinations will require installation of new emissions control equipment on Craig Unit 1, Craig Unit 2 and Hayden Unit 2. The District owns 29% of Craig Units 1 and 2 and 50% of Hayden Unit 2. Tri-State, the operating agent for Craig, has provided the EPA with an estimate of approximately $213.1 million to install the emissions control equipment at Craig Units 1 and 2, of which the District's share for the two units would be $62.0 million. According to Xcel Energy, the operating agent for Hayden, installation of SCR on Hayden Unit 2 would cost approximately $72.0 million, of which the District's share would be $36.0 million. The new emission control equipment is expected to be in operation within five years. In February and March 2013, two petitions for judicial review of the BART determination for Craig were filed with the U.S. Court of Appeals for the Tenth Circuit by environmental organizations. It is too soon to predict the outcome of these matters.

In May 2009, the National Parks Conservation Association (NPCA) and other environmental and tribal groups, petitioned the U.S. Department of Interior - National Park Service (DOI) to certify to the EPA that visibility impairment in Grand Canyon National Park was "reasonably attributable" to oxides of nitrogen and particulate matter emissions from NGS (the NGS Petition). On February 16, 2010, NPCA and a similar coalition of environmental and tribal groups filed a similar petition with both the DOI and the U.S. Department of Agriculture - U.S. Forest Service (DOA) with respect to Four Corners, asking the DOI and the DOA to certify to the EPA that impairment of visibility in sixteen areas within 300 kilometers of Four Corners, including Grand Canyon National Park, among others, was reasonably attributable to pollutant emissions from Four Corners. However, the DOI and the DOA deferred action on the petitions pending completion of the BART determinations for the plants.

On October 4, 2011, following earlier notices of intent to sue, Earthjustice, representing Dine CARE, To' Nizhoni Ani, Sierra Club and National Parks Conservation Association, filed a citizen suit in the District Court of New Mexico against the co-owners of Four Corners, including the District, alleging violations of the Prevention of Significant Deterioration IPSD) provisions of the CAA. The plaintiffs alleged that the defendants made two sets of major modifications to units 4 and 5, in which the District owns 10%, which allowed the plant to significantly increase its emissions of pollutants without first obtaining a PSD permit. On January 13, 2012, the District was served with a Summons and First Amended Complaint asserting two additional claims related to Four Corners. In addition to the alleged PSD violations, the First Amended Complaint alleges violations of the New Source Performance Standards (NSPS) arising from the same two sets of modifications. Among other things, the plaintiffs ask the court to enjoin operations at Four Corners until the defendants apply for and obtain a PSD permit and comply with the NSPS, order the Four Corners owners to install best available control technology, and order civil penalties, including a mitigation project. The owners of Four Corners filed two motions to dismiss all of the claims in the First Amended Complaint and briefing has been completed but the decision on those motions is stayed to allow the parties time to pursue settlement. The District cannot predict the outcome of this litigation.

On October 22, 2012, WildEarth Guardians filed a petition for review in the Ninth Circuit asking the court to review the

2013 SUP,*ANNUAL REPORT 45 BART Federal Implementation Plan for Four Corners. In its petition, WildEarth Guardians alleged that the final Four Corners BART rule results in more air pollution being emitted into the air than allowed by law and that the EPA failed to follow the requirements of the Endangered Species Act (ESA). APS, the operating agent for Four Corners, was granted intervention in the lawsuit in early December. On December 12, 2012, the EPA moved to dismiss the lawsuit or, in the alternative, to transfer the lawsuit to the 1Oth Circuit. On December 21, 2012, APS filed a response brief in support of the EPA's motion.

In February 2013, in response to the motions by EPA and APS, the case was transferred to the Tenth Circuit and briefing currently is underway. The District is unable to predict the outcome of this matter.

On February 25, 2013, WildEarth Guardians filed a Petition for Review in the Tenth Circuit Court of Appeals challenging EPA's approval of the Colorado regional haze SIP. On March 1, 2013, the National Parks Conservation Association also filed a Petition for Review. Although briefing has not commenced, the District understands that the petitions will challenge the BART decision for the Craig Generating Station. The Colorado Department of Public Health and Environment, Tri-State Generation and Transmission Association, PacifiCorp, and Public Service Company of Colorado d/b/a X-Cel Energy have been granted intervention in one or both cases. The District is unable to predict the outcome of these matters.

In December 2009, the EPA found that emissions of GHG endanger public health and welfare. In.April 2010, the EPA issued a "timing" rule that allows the EPA to regulate emissions of GHG by stationary sources such as power plants.

Subsequently, the EPA issued its "tailoring rule," which specifies thresholds that trigger permitting requirements for sources of GHG emissions. The rule applied to power plants on January 2, 2011. InMarch 2012, the EPA proposed a separate rule that would establish a single performance standard for CO2 emissions from new power plants. The proposed standard would apply to all newly constructed fossil-fuel-fired facilities. The President has directed the EPA to revise and re-propose this rule by September 2013. The President has also directed the EPA to propose emissions guidelines for reduction of GHG emissions from existing plants byJune 2014 and to finalize these guidelines by June 2015. The District cannot predict the impact of these rules and guidelines on its operations or finances at this time.

The California Legislature has enacted various GHG laws. As a result, the Los Angeles Department of Water and Power, one of the participants in NGS, and Southern California Edison Company, a participant in Four Corners units 4 and 5, are or will be selling their interests in those plants. In addition, legislation has recently been passed at the Nevada Legislature that may require Nevada Power Company, another participant in NGS, to withdraw from the plant by the end of 2019.

The District is still analyzing these actions and cannot predict the impact on its operations or finances at this time.

Hazardous waste: The EPA has issued a proposed rule seeking comments on regulatory options governing the handling and disposal of coal combustion residuals (CCRs(, such as fly ash, bottom ash and flue gas desulfurization (FGD) sludge. The District disposes of CCRs in dry landfill storage areas at CGS and NGS, with the exception of wet surface impoundment disposal of FGD sludge at CGS. Both CGS and NGS sell a portion of their fly ash for beneficial reuse as a constituent in concrete production. The District also owns interests in joint participation plants, such as Four Corners, Craig, Hayden and Springerville, which dispose of CCRs in dry storage areas and in wet surface impoundments. The regulated community, including utilities, strongly opposes regulation of CCRs as hazardous waste and Congress is considering legislation that would prohibit the EPA from regulating CCRs as hazardous waste. The EPA is expected to issue a final rule in 2014. At this time, it is too early to definitively estimate projected costs, but the costs could be substantial depending on the approach taken in the final rules.

EndangeredSpecies: Several species listed as threatened or endangered under of the Endangered Species Act (ESA) have been discovered in and around reservoirs on the Salt and Verde rivers, as well as C.C. Cragin Reservoir, which is operated by SRP. Potential ESA issues also exist along the Little Colorado River in the vicinity of CGS and Springerville.

The District obtained Incidental Take Permits (ITPs) from the United States Fish and Wildlife Service (USFWS), which allow full operation of Roosevelt Dam on the Salt River and of Horseshoe and Bartlett Dams on the Verde River. The ITPs, and associated Habitat Conservation Plans (HCPs), identify the obligations, such as mitigation and wildlife monitoring, the District must undertake to comply with the ESA. The District has established trust funds to pay mitigation and monitoring

2013 SRP ANNUAL REPORT 47 INDEPENDENT AUDITOR'S REPORT 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 We have audited the accompanying combined financial statements of Salt River Project Agricultural Improvement and Power District and its subsidiaries and the Salt River Valley Water Users' Association (collectively, "SRP"), which comprise the combined balance sheets as of April 30, 2013 and April 30, 2012, and the related combined statements of net revenues and cash flows for the years then ended.

Management's Responsibility for the Combined FinancialStatements Management is responsible for the preparation and fair presentation of the combined financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of combined financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility Our responsibility is to express an opinion on the combined financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the combined financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the combined financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the combined financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the combined financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the combined financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion In our opinion, the combined financial statements referred to above 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 at April 30, 2013 and April 30, 2012, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

PricewaterhouseCoopers LLP Las Vegas, Nevada July 19, 2013

46 2013 SP ANNUAL REPORT expenses related to the implementation of both the Roosevelt HCP and Horseshoe-Bartlett HCP and believes it has recorded adequate reserves as a part of its environmental reserves to cover its related obligations. The District continues to assess the potential ESA liabilities along the Little Colorado River and at C.C. Cragin, and is working closely with the USFWS and other state and federal agencies to address potential species concerns as necessary, but cannot predict the ultimate outcome at this time.

Water Rights The District and the Association are parties to a state water-rights adjudication proceeding initiated in 1976 that encompasses the entire Gila River System (the Gila River Adjudication). This proceeding is pending in the Superior Court for the State of Arizona, Maricopa County, and will eventually result in the determination of all conflicting rights to water from the Gila River and its tributaries, including the Salt and Verde rivers. The District and the Association are unable to predict the ultimate outcome of this proceeding.

In 1978, a water-rights adjudication was initiated in the Apache County Superior Court for the State of Arizona with regard to the Little Colorado River System and will eventually result in the determination of all conflicting rights to water from the Little Colorado River and its tributaries, including Clear Creek, the location of C.C. Cragin Dam and Reservoir. The District has filed its claim to water rights in this proceeding, which includes a claim for groundwater being used in the operation of CGS. The District is unable to predict the ultimate outcome of this proceeding, but believes an adequate water supply for CGS will remain available and that the rights to C.C. Cragin will be confirmed.

The City of Prescott, together with the towns of Prescott Valley and Chino Valley, have plans to withdraw groundwater from the Big Chino Groundwater Sub-Basin and transport the water to their respective service areas for municipal and industrial uses. The District opposed these plans because of the potential that such pumping would deplete the base flow of the Verde River, which is delivered to and used by Association shareholders. The District is negotiating agreements with the parties that will satisfy its concerns.

Other Litigation In the normal course of business, SRP is exposed to various litigations or is a defendant in various litigation matters. In management's opinion, the.ultimate resolution of these matters will not have a material adverse effect on SRP's financial position or results of operations.

Self-Insurance SRP maintains various self-insurance retentions for certain casualty and property exposures. In addition, SRP has insurance coverage for amounts in excess of its self-insurance retention levels. SRP provides reserves based on management's best estimate of claims, including incurred but not reported claims. In management's opinion, the reserves established for these claims are adequate and any changes will not have a material adverse effect on SRP's financial position or results of operations. SRP records the reserves in deferred credits and other non-current liabilities in the accompanying Combined Balance Sheets.

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S-___ *. . - 1 Report of Independent Auditors and Combined Financial Statements for Southern California Public Power Authority June 30, 2014 and 2013 MOSS-ADAMSL Certified Public Accountants I Business Consultants Acumen. Agility. Answers.

TABLE OF CONTENTS PAGE REPORT OF INDEPENDENT AUDITORS 1-2 MANAGEMENT'S DISCUSSION AND ANALYSIS 3-9 FINANCIAL STATEMENTS Combined financial statements 10-48 Notes to combined financial statements49-110 SUPPLEMENTAL INFORMATION Supplemental schedule of receipts and disbursements in funds required by the bond indenture for the year ended June 30, 2014 Palo Verde Project 111 San Juan Project 112 Magnolia Power Project 113 Canyon Power Project 114 Apex Power Project 115 Hoover Uprating Project 116 Tieton Hydropower Project 117 Milford 1 Wind Project 118 Milford 2 Wind Project 119 Windy Point Project 120 Linden Wind Energy Project 121 Southern Transmission System Project 122 Mead-Phoenix Project 123 Mead-Adelanto Project 124 Natural Gas Pinedale Project 125 Natural Gas Barnett Project 126 Prepaid Natural Gas Project No. 1 127 Multiple Project Fund 128

WWW.MOSSADAMS.COM REPORT OF INDEPENDENT AUDITORS The Board of Directors and Participants of Southern California Public Power Authority Report on Financial Statements We have audited the accompanying combined and individual projects' financial statements of Southern California Public Power Authority, which comprise the combined and individual projects' statements of net position as of June 30, 2014 and 2013, and the related combined and individual project's statements of revenues, expenses and changes in net position, and cash flows for the years then ended, and the related notes to the financial statements.

Management'sResponsibilityforthe FinancialStatements Management is responsible for the preparation and fair presentation of these combined and individual projects' financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of combined and individual project financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility Our responsibility is to express an opinion on these combined and individual project financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the combined and individual projects' financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the combined and individual projects' financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the combined and individual projects' financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the combined and individual projects' financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the combined and individual projects' financial statements.

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REPORT OF INDEPENDENT AUDITORS (continued)

We believe that the audit evidence obtained is sufficient and appropriate to provide a basis for our audit opinions.

Opinion In our opinion, the combined and individual project financial statements referred to above present fairly, in all material respects, the financial position of Southern California Public Power Authority and each of the Authority's projects: Palo Verde Project, San Juan Project, Magnolia Power Project, Canyon Power Project, Apex Power Project, Hoover Uprating Project, Tieton Hydropower Project, Milford I Wind Project, Milford II Wind Project, Windy Point Project, Linden Wind Energy Project, Southern Transmission System Project, Mead-Phoenix Project, Mead-Adelanto Project, Pinedale Project, Barnett Project, Prepaid Natural Gas Project, Ormat Geothermal Energy Project, MWD Small Hydro Project, Pebble Springs Project, Ameresco Chiquita Landfill Gas Project, Don A. Campbell Wild Rose Geothermal Project, Copper Mountain Solar Project, Multiple Project Fund, Project Development Fund, Projects' Stabilization Fund and SCPPA Building Fund as of June 30, 2014 and 2013, and the combined and individual results of the projects' operations and cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Other Matter Required Supplementary Information Accounting principles generally accepted in the United States of America require that the management's discussion and analysis be presented to supplement the basic financial statements. Such information, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures in the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management's responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

Other Information Our audit was conducted for the purpose of forming an opinion on the basic financial statements as a whole.

The supplemental schedules of receipts and disbursements in funds for the year ended June 30, 2014, as presented on pages 110 - 127, are presented for purposes of additional analysis and are not a required part of the basic financial statements. Such information has not been subjected to the auditing procedures applied in the audit of the basic financial statements, and accordingly, we do not express an opinion or provide any assurance on it.

Portland, Oregon October 30, 2014 2

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS The following discussion and analysis of the financial performance of Southern California Public Power Authority (the Authority or SCPPA), provides an overview of the Authority's financial activities for the fiscal years ended June 30, 2014 and 2013. Please read this discussion and analysis in conjunction with the Authority's Combined Financial Statements, which begin on page 10. Description and other details pertaining to the Authority are included in the Notes to Combined Financial Statements.

The Authority is a joint powers authority whose primary purpose has been to provide joint financing and oversight for large joint projects for its member agencies that consist of eleven municipal electric utilities and one irrigation district in California. On a combined basis, these entities provide electricity to more than two million retail electric customers. A Board of Directors (the Board) governs the Authority, which consists of one representative from each member agency.

Using This Financial Report This annual financial report consists of a series of financial statements and reflects the self-supporting activities of the Authority that are funded primarily through the sale of energy, natural gas, and transmission services to member agencies under project specific take-or-pay contracts that require each member agency to pay its proportionate share of operating and maintenance expenses and debt service with respect to such projects. 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 Authority also established take-and-pay contracts for the participants of the prepaid natural gas project where the payments received from the sale of gas will be sufficient to pay debt service. In addition, the Authority has entered into various power purchase agreements. These agreements are substantially take-and-pay contracts but there may be other costs not associated with the delivery of energy that the participants may be obligated to pay.

3

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS Combined Summary of Financial Condition and Changes in Net Position (in thousands)

June 30, 2014 2013 (restated) 2012 (restated)

Assets Net utility plant $ 1,574,194 $ 1,362,772 $ 1,431,352 Investments 679,569 730,573 678,358 Cash and cash equivalents 301,753 230,929 348,515 Prepaid and other 1,099,682 1,152,331 1,230,973 Total assets 3,655,198 3,476,605 3,689,198 Deferred outflows of resources 95,061 122,746 126,951 Total assets and deferred outflows of resources $ 3,750,259 $ 3,599,351 $ 3,816,149 Liabilities Noncurrent liabilities $ 3,456,473 $ 3,307,841 $ 3,578,046 Current liabilities 392,473 398,509 415,090 Total liabilities 3,848,946 3,706,350 3,993,136 Deferred inflows of resources Net position Net investment in capital assets (608,196) (621,687) (641,171)

Restricted 583,618 565,717 555,522 Unrestricted (74,109) (51,029) (91,338)

Total net position (98,687) (106,999) (176,987)

Total liabilities, deferred inflows of resources, and net position $ 3,750,259 $ 3,599,351 $ 3,816,149 Revenues, expenses and changes in net position for the year ended June 30 Operating revenues $ 702,327 $ 639,925 $ 682,990 Operating expenses (564,690) (503,837) (511,062)

Operating income 137,637 136,088 171,928 Investment and other income 30,066 14,727 23,745 Derivative gain (loss) 395 60,189 (42,743)

Debt expense (156,729) (157,645) (164,017)

Change in net position 11,369 53,359 (11,087)

Net position, beginning of year (106,999) (176,987) (127,079)

Cumulative effect of restatement (50,792)

Net position, beginning of year as restated (106,999) (176,987) (177,871)

Net contributions/(withdrawals) by participants (3,057) 16,629 11,971 Net position, end of year ,$ 98,687) $ R106,999) $ f176,987) 4

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS Combined Financial Statements (continued)

Net Position-During fiscal year 2014 the Authority's net position increased by $8 million mainly due to the increase in assets and deferred outflows of resources of $151 million offset by the increase in liabilities of $143 million.

The increase in the Authority's assets is due to the following:

Utility Plant- increased by $211 million.

This increase is primarily due to the $294 million acquisition of the Apex Power Project (APP),

and $19 million of ongoing capital improvements in the Palo Verde Project (PV), Canyon Power (CPP), Magnolia (MAG) and San Juan (SJ) Projects. The increase was offset by $102 million of scheduled depreciation in all projects.

• Investments - decreased by $51 million.

This decrease is largely due to the $36 million GIC withdrawal for the final debt service requirements of the 1989 Multiple Project Bonds; $13.5 million release of debt service reserves for the debt service requirements of the 2002A SJ Bonds; $4.5 million withdrawal from the Project Fund for the debt service requirements of the 2006A Magnolia Project Bonds; and $24 million net transfers of funds from long term investments to cash and cash equivalents. The decreases were offset by $23 million of remaining bond proceeds from the issuance of the APP Revenue Bonds, 2014 Series A&B (APP 2014 A&B Bonds); and $4 million reserves for major maintenance in the Magnolia Project.

" Cash and cash equivalents - increased by $71 million.

This increase is mainly due to the $24 million net transfers of funds from long term investments to cash and cash equivalents; $34 million accumulated overbillings and advances in various Projects; and $13 million of remaining bond proceeds from the issuance of the APP 2014 A&B Bonds.

" Prepaid and other assets - decreased by $53 million.

This decrease is primarily due to $64 million amortization of the prepaid assets in the Prepaid Gas, Milford 1, Milford II, and Windy Point/Windy Flats Projects; offset by an increase in inventory of $3 million relating to the newly acquired APP; a $2 million increase in advances collected from the APP, MAG and the SJ Projects for various expenses and an increase in accounts receivable of $3 million for an advance payment for a prior year IPA audit adjustment in the STS Project; and a $3 million settlement from the Department of Energy (DOE) for spent fuel fees in the PV Project.

5

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS Combined Financial Statements (continued)

Deferred outflows of resources - decreased by $28 million.

The decrease is largely due to the $30 million amortization of unamortized loss on refunding which was reclassified to deferred outflows of resources in accordance with GASB 65; offset by the $2 million increase in the reported value of derivative instruments in the MPP and Prepaid Gas Project in accordance with GASB 53.

Liabilities The increase in the Authority's liabilities of $143 million is primarily due to the following:

$319 million issuance of APP 2014 A&B Bonds at a premium of $15 million; $23 million increase in accruals and accumulated overbillings and advances in various Projects; and $2 million increase in the reported change in fair value of the derivative instruments in the MPP, STS, and Prepaid Gas Projects. The increase was offset by the $216 million principal maturities and related amortization for all debt-funded projects.

During fiscal year 2013, the Authority's assets and deferred outflow of resources, as restated, decreased by $217 million because of ongoing transactions such as scheduled depreciation and amortization in all projects; capital improvements in the PV, CPP and SJ Projects; and capital drilling costs in the Natural Gas Reserve Projects. This decrease was offset by a decrease in liabilities of $287 million mainly due to principal maturities and related amortization for all debt funded projects, resulting in an increase in the Authority's net position of $70 million.

Operatingincome -

The net increase in operating income of $1 million is due to the $26 million increase in participants' billings for debt service requirements in the Mead-Adelanto (MA) and Mead-Phoenix (MP) Projects, and increased expenses for O&M costs and nuclear fuel in the MPP and PV Projects, respectively; and the receipt of $3 million in upfront savings for the restructuring of the Prepaid Project Bonds. This increase was offset by a $28 million decrease in participant billing in the San Juan Project because of the completion of the scheduled major maintenance outages in fall 2012.

During FY 2013, the net decrease of $43 million in participants billings was mainly due to lower debt service costs in the STS, MPP, MA, MP, and PV Projects; and the $7 million net decrease in operating expenses was mainly due to the scheduled major maintenance outage in the San Juan Project which resulted in a net decrease in operating income of $36 million.

6

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS Combined Financial Statements (continued)

Investment and OtherIncome -

Investment and other income increased $15 million mainly due to a $5 million fire insurance settlement in the SJ Project; $3 million spent fuel settlement in the PV Project; $3 million of upfront savings received from the restructuring of the 2007 Gas Project Bonds; and the net increase of $4 million resulting from the increase in market values of the investment securities held in all projects together with the loss of earnings in the MP, MA, and Multiple Projects because of the withdrawal of all funds from the 1989 Multiple GIC in relation to the final maturity of the Multiple Project Bonds.

DerivativeGain (Loss) -

In June 2008, GASB issued Statement No 53, Accounting and Financial Reporting for Derivative Instruments, effective for financial statements for periods beginning after June 15, 2009. GASB 53 requires that the fair value of derivative instruments be reported in the financial statements as investment income or loss if the derivative fails to effectively hedge the risk of rising or falling cash flows or fair values. $0.395 million and $60 million were charged to expense and income related to the Authority's derivative instruments that were deemed investment instruments as of June 30, 2014 and 2013, respectively. The decrease in derivative gain of $60 million is mainly due to termination of the STS 2001, MA 2008 and the MP 2008 Swaps. (See Note 5).

Debt Expense -

Debt expense decreased by $1M largely due to the final maturity of the 1989 Multiple Project Revenue Bond, offset by the issuance of the APP 2014 A&B Bonds.

During fiscal year 2013, interest expense decreased because of the termination of the STS 2006 Constant maturity swap, the refunding of the STS 2002 A& B Bonds and a portion of the MPP 2003A Bonds, and the recognition of the remaining balance of the upfront payment received in connection with the execution of the MA and MP 2004 Swaps which were terminated in the fiscal year. These transactions were offset by the effect of the GASB 65 restatement, which required costs of issuance to be expensed upon issuance and resulted in a $6 million net decrease in debt expense.

7

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS Combined Financial Statements (continued)

Financial outlook - The Authority's credit strength is based on a number of factors including:

" The collective credit strengths of each project participant;

• The absence of concentration risk as evidenced by the lack of substantial reliance by one participant on the resources financed;

• The low cost power the Projects provide the participants; and

" Strong legal provisions.

The Authority has take-or-pay power sales, natural gas sales, and transmission service contracts that unconditionally require the Participants to pay for the cost of operating and maintaining the Projects, including debt service, whether or not the Projects are operating or operable. Although the contracts have not been court-tested, a municipal utility's authority to enter into such contracts is rooted in the State's constitutional provisions for municipal electric utilities. The Participants of the Prepaid Natural Gas Project No. 1, however, are obligated only to purchase and pay for gas delivered by SCPPA at market-based prices in accordance with the prepaid gas sale agreements in take-and-pay contracts. The Authority has also entered into various power purchase agreements that are substantially take-and-pay contracts but there may be other costs not associated with the delivery of energy that the participants may be obligated to pay.

Through the collaborative efforts of its members, the Authority has developed a comprehensive and dynamic strategic plan that provides a common vision for its members and a platform for joint action.

SCPPA continues its involvement in legislative and regulatory affairs at both the state and federal levels to protect represented customers, by assuring resource adequacy, excellent reliability, and environmental stewardship. Backed by one of the strongest financial ratings in the utility industry, SCPPA maintains its traditional role of providing financing for its members' natural gas, generation, and transmission projects. In addition to the conventional areas of power, investments are also being made to provide customers with more renewable generation and energy efficiency.

AB 1890 required all California electric utilities to commit a portion of their revenue to other Public Benefit Programs, including energy efficiency, renewable energy, research, development and demonstration (RD&D), and low-income customer assistance. Since 1998, a combined $1.7 billion dollars have been spent by our Members on their respective Public Benefits Programs to support local communities.

8

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS Combined Financial Statements (continued)

Renewable projects - Member agencies' electric utilities are governed by their respective city councils or other elected legislative bodies. Many of whom previously established voluntary targets including goals for the percentage of renewable energy they wish to obtain within their portfolios. Some have set targets as high as 40% by the year 2020. Many of our members are approaching, or have already exceeded their interim targets of 20% renewable energy and are now updating their objectives to meet 33% by 2020 as required by SBX1 2.

SCPPA continues to seek cost effective resources to support our members' Renewable Portfolio Standard (RPS) objectives for 2016 and forward. SCPPA has an active working group focused on renewable energy development. This group, with representation from all twelve of the member agencies, has reviewed over five hundred (500) individual project proposals since starting in 2007.

Many of these projects have advanced into specific contract negotiations, and over 1,000 MW of capacity are now being operated in support of our members' renewable objectives.

Summary The management of the Authority is responsible for preparing the information in this management discussion and analysis, combined and individual projects' financial statements, and notes to combined financial statements. The financial statements were prepared according to accounting principles generally accepted in the United States of America, and they fairly portray the Authority's financial position and operating results. The notes to the financial statements are an integral part of the basic financial statements and provide additional financial information.

9

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINED STATEMENTS OF NET POSITION (AMOUNTS IN THOUSANDS) lune 30.

2013 2014 As Restated ASSETS Noncurrent assets Net utility plant $ 1,574,194 $ 1.362,772 Investments - restricted 648,532 682,044 Investments - unrestricted 31,037 48,529 Advance to IPA - restricted 11,550 11,550 Advances for capacity and energy, net - restricted 3,688 5,259 Fair value of derivative instruments 752 625 Prepaid and other assets 968.744 1,032,953 Total noncurrent assets 3,238.497 3,143.732 Current assets Cash and cash equivalents - restricted 205,018 151,476 Cash and cash equivalents - unrestricted 96,735 79,453 Interest receivable 3,042 3,822 Accounts receivable 17,399 9,692 Materials and supplies 24,904 21,272 Prepaid and other assets 69,603 67,158 Total current assets 416,701 332.873 DEFERRED OUTFLOWS OF RESOURCES 79,668 Unamortized loss on refunding 109,205 Accumulated decrease in fair value of hedging derivatives 15J393 13,541 Total deferred outflows of resources 95.061 122,746 Total assets and deferred outflows of resources $ , 3,750,259 31599,351 LIABILITIES Noncurrent liabilities Long-term debt $ 3,353,692 $ 3,200,415 Fair value of derivative instruments 55,984 54,399 Notes payable and other liabilities 15,890 22,214 Advances from participants 30,907 30,813 Total noncurrent liabilities 3,456,473 3,307,841 Current liabilities Debt due within one year 158,320 189,730 Notes payable and other liabilities due within one year 15,275 11,572 Advances from participants due within one year 50,892 46,894 Accrued interest 65,396 64,173 Accounts payable and accruals 96,337 79,658 Accrued property tax 6,253 6.482 Total current liabilities 392,473 398,509 Total liabilities 3,848,946 3,706,350 NET POSITION Net investment in capital assets (608,196) (621,687)

Restricted 583.618 565,717 Unrestricted (74,1091 (51,029)

Total net position (98,687) f106,999)

Total liabilities and net position $ 3,750,259 $ 34599351 10 See accompanying notes.

10 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINED STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION (AMOUNTS IN THOUSANDS)

Years Ended June 30, 2013 2014 As Restated Operating revenues Sales of electric energy $ 504,862 $ 467,798 Sales of transmission services 151,086 119,322 Sales of natural gas 46,379 52,805 Total operating revenues 702,327 639,925 Operating expenses Operations and maintenance 445,016 385,999 Depreciation, depletion and amortization 97,964 94,334 Amortization of nuclear fuel 16,031 16,749 Decommissioning 5,679 6,755 Total operating expenses 564,690 503,837 Operating income 137,637 136,088 Non operating revenues (expenses)

Investment and other income 30,066 14,727 Derivative gain 395 60,189 Debt expense (156,729) (157,645)

Net non operating revenues (expenses) (126,268) (82,729)

Change in net position 11,369 53,359 Net position - beginning of year, before restatement (106,999) (129,308)

Cumulative effect of restatement (47,679)

Net position - beginning of year as restated (106,999) (176,987)

Net contributions (distributions) by participants (3,057) 16,629 Net position - end of year $ (98,687) $ (106,999)

See accompanying notes. 11 See accompanying notes. 11

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINED STATEMENTS OF CASH FLOWS (AMOUNTS IN THOUSANDS)

Years Ended June 30, 2014 2013 Cash flows from operating activities Receipts from participants $ 621,802 $ 569,883 Receipts from sale of oil and gas 9,152 9,809 Payments to operating managers (296,029) (295,548)

Other disbursements and receipts 21,897 20,946 Net cash flows from operating activities 356,822 305,090 Cash flows from noncapital financing activities Advances by participants, net 25,708 1,460 Cash flows from capital financing activities Additions to plant and prepaid projects, net (335,618) (51,528)

Debt interest payments (145,419) (167,428)

Proceeds from sale of bonds 333,872 243,030 Payment for defeasance of revenue bonds (226,032)

Transfer of funds from (to) escrow (56,970)

Transfer of funds from (to) Mine Reclamation Trust Fund (489) (1,930)

Transfer of funds from (to) other projects (24,822)

Principal payments on debt (189,730) (115,620)

Payment for bond issue costs 2,508,1 f1,292)

Net cash used for capital and related financing activities (364,7141 (377.7701 Cash flows from investing activities Interest received on investments 8,132 11,732 Purchases of investments (436,386) (580,344)

Proceeds from sale/maturity of investments 481,262 522,246 Net cash provided by (used for) investing activities 53,008 (46,3661 Net increase (decrease) in cash and cash equivalents 70,824 (117,586)

Cash and cash equivalents, beginning of year 230,929 3481515 Cash and cash equivalents, end of year $ 301,753 230,929 Reconciliation of operating income to net cash provided by operating activities Operating income $ 137,637 $ 136,351 Adjustments to reconcile operating income to net cash provided Depreciation, depletion and amortization 149,779 145,950 Decommissioning 5,679 6,755 Advances for capacity and energy 3,031 3,202 Amortization of nuclear fuel 16,031 16,749 Changes in assets and liabilities Accounts receivable (4,830) 6,118 Accounts payable and accruals 29,294 (25,187)

Other 20,201 151S2 Net cash provided by operating activities 356,822 $ 3051090 Cash and cash equivalents as stated in the Combined Statements of Net Position $ 205,018 $ 151,476 Cash and cash equivalents - restricted Cash and cash equivalents-unrestricted 96,735 79,453

$ 230.929,,

$ 301,753 12 See accompanying notes.

12 See accompanying notes.

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF NET POSITION JUNE 30,2014 (AMOUNTS IN THOUSANDS)

GENERATION Palo Verde San luan Magnolia Power Canyon Power Apex Power ASSETS Noncurrent assets Net utility plant $ 72.982 $ 7S,461 $ 219.668 $ 258.135 $ 290.782 Ifvestments - restricted 194,156 21,213 55,558 23,297 23,477 Investments - unrestricted 30,477 -

Advance to IPA - restricted Advances for capacity and energy, net- restricted Fair value of derivative instruments Prepaid and other assets - 727 Total noncurrent assets 297,615 97,401 275.226 281,432 314,259 Current assets Cash and cash equivalents - restricted 9,869 8,596 27,618 7.576 16.306 Cash and cash equivalents - unrestricted 7,423 13,732 6,127 1,697 17,430 Interest receivable 538 25 116 1,864 16 Accounts receivable 5.332 177 1,621 59 -

Due from other project- restricted Materials and supplies 9.826 4,563 7,021 1,042 2,452 Prepaid and other assets 677 1,428 822 812 Total current assets 33,665 28,521 43,325 12.238 37,016 DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunding 1,000 12,899 -

Accumulated decrease in fair value of hedging derivatives 6.856 Total deferred outflows of resources - 1,000 19,75S

$ 3128

• 12622 ,, 338.306 $ ,293.670,$ ,3527 Total assets and deferred outflows of resources LIABILITIES Noncurrent liabilities Long-term debt S 36,130 $ 60,161 S 331,564 $ 309,045 $ 333,684 Fair value of derivative instruments 19,419 Notes payable and other liabilities 13,413 -

- 2,500 Advances from participants Total noncurrent liabilities 49.543 60,161 30983 309,045 336,184 Current liabilities Debt due within one year 11,330 13,200 10,565 - -

Notes payable and other liabilities due within one year 6,653 .8,622 -

Advances from participants due within one year - 9,082 22,429 2,225 -

Accrued interest 1 1,797 3,639 8,366 3,327 Accounts payable and accruals 12,615 10,448 6,141 196 17,073 Accrued property tax 1,303 371 - -

Due to other projects Total current liabilities 31,902 34,898 51,396 10,787 , 20,400 Total liabilities 81,445 , 95059 402.379 319,832 356,S84 NET POSITION Net investment in capital assets 25,522 245 (109,533) (46,548) (11,985)

Restricted 183,786 22,536 S7,196 17,785 3,054 Unrestricted 40,S27 9,082 f7361 2,601 3622 Total net position 249,835 31,863 (64,0731 f26,1621 (5.3091 Total liabilities and net position $ 331 280 $ 126.922 $ 338 306 $ 293.670 $ 351,275 13 See accompanying notes.

13 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF NET POSITION JUNE 30,2013 (As Restated)

(AMOUNTS IN THOUSANDS)

GENERATION Palo Verde San Juan Magnolia Power Canyon Power ASSETS Noncurrent assets Net utility plant $ 84,910 S 84,961 $ 230,395 $ 260,687 Investments - restricted 178,911 31,189 52,625 30,870 Investments - unrestricted 36,878 - -

Advance to IPA - restricted Advances for capacity and energy, net - restricted Fair value of derivative instruments Prepaid and other assets l1153 - -

Total noncurrent assets 300,699 117,303 283,020 291,557 Current assets Cash and cash equivalents - restricted 19,371 5,878 28,701 8,757 Cash and cash equivalents - unrestricted 4,964 11,455 6,346 626 Interest receivable 543 45 117 49 Accounts receivable 1,748 220 599 1,069 Due from other project - restricted Materials and supplies 9,645 4,502 6,070 1,055 Prepaid and other assets 648 505 192 Total current assets 36,919 22,60S 42,025 11,556 DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunding - 1,370 14,112 Accumulated decrease in fair value of hedging derivatives -5,405 Total deferred outflows of resources - 1,370 19,S17 Total assets and deferred outflows of resources 337.618 $ 141 278  ; 344,562 S 303,113 LIABILITIES Noncurrent liabilities Long-term debt $ 47,460 $ 74,083 $ 343,455 $ 310,102 Fair value of derivative Instruments - - 15,972 -

Notes payable and other liabilities 19,737 Advances from participants Total noncurrent liabilities 67,197 74,083 359,427 310,102 Current liabilities Debt due within one year 10,980 27,250 15,605 -

Notes payable and other liabilities due within one year 6,337 - 4,607 -

Advances from participants due within one year - 4,071 21,479 2,225 Accrued Interest 4 2,546 3,853 8,366 Accounts payable and accruals 10,993 5,896 2,105 378 Accrued property tax 1,350 349 -

Due to other projects Total current liabilities 29,664 ,40,112 47,649 10,969 Total liabilities 96,861 114.195 407,076 321,071 NET POSITION Net investment in capital assets 26,471 (17,921) (110,351) (38,035)

Restricted 172,336 34,564 51,908 17,706 Unrestricted 41,950 10,440 (4,0711 2,371 Total net position 240,757 27,083 f62,5141 [17,958)

Total liabilities and net position $ 337,618 $ 141,278 See accom1mriving notes. 14 See accompanying notes. 14

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF NET POSITION JUNE 30, 2014 (AMOUNTS IN THOUSANDS)

Tieton Windy Point Linden Wind Hoover Upratinn Hvdr wnr Milford I Wind Milford I1 Wind Project Energy ASSETS Noncurrent assets Net utility plant $ 41,205 $ $ $ $ 124,470 Investments - restricted 2,982 5,383 31,219 6,973 22,812 4,674 Investments - unrestricted 560 Advance to IPA- restricted Advances for capacity and energy, net- restricted 3,688 Fair value ofderivative instruments Prepaid and other assets 1634936 140,588 , 41694-Total noncurrent assets 7,230 461588 195,154 147,561 439,756 129,144 Current assets Cash and cash equivalents - restricted 181 2,124 6.475 5,372 17,307 4,772 Cash and cash equivalents - unrestricted 787 684 8,723 5,932 7,575 2,534 Interest receivable 2 14 56 14 16 1 Accounts receivable 400 Due from other project- restricted Materials and supplies Prepaid and other assets 1,572 - 1,4 , 8,697 32,241 -

Total current assets 2,S42 2,822 26,65S 20,015 57,139 71,707 DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunding Accumulated decrease in fair value of hedging derivatives Total deferred outflows of resources

$ 9772 ,$ ,49410 221809 $ 167576 $ 496895 $ 136851 Total assets and deferred outflows of resources LIABILITIES Noncurrent liabilities Long-term debt $ 6,127 $ 50,836 $ 214,773 $ 157,200 S 488,305 $ 132,382 Fair value of derivative Instruments Notes payable and other liabilities Advances from participants Total noncurrent liabilities 61127 50,836 214,773 157,200 ,488,305 132,382 Current liabilities Debt due within one year 1,835 815 8,450 5,270 18,535 3,530 Notes payable and other liabilities due within one year Advances from participants due within one year 202 250 250 1,000 2,004 Accrued interest 104 1,273 5,211 3,797 11,253 3,313 Accounts payable and accruals 65 416 8,432 5,657 6,370 1,093 Accrued property tax - 737 247 Due to other projects Total current liabilities 2,004 2,706 221343 14,974 37,89S 10,187 Total liabilities 8,131 53,542 237,116 172,174 526,200 142,569 NET POSITION Net investment In capital assets - (10,446) (11,443)

Restricted 357 6,249 6,534 Unrestricted 1284 65 107 (4,5981 (29,305) (8091 Total net position 1,641 (4.132) 115,3071 (4.5981 (29,305) (5,7181 Total liabilities and net position $ 91772 $ 49 410 S 221 809 $ 167,576 $ 496r895 $ 1361851 15 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF NET POSITION JUNE 30, 2013 (As Restated)

(AMOUNTS IN THOUSANDS)

GREENPOWER Hoover' Tieton Windy Point Linden Wind Oprating Hydropower Milford I Wind Milford 11Wind Project Energy ASSETS Noncurrent assets Net utility plant $ $ 42,589 $ $ .$ S . 130,283 Investments - restricted 2,344 5,293 32,071 7,865 29,347 6,392 Investments - unrestricted 1,160 1,498 5,497 2,497 Advance to IPA - restricted Advances for capacity and energy, net - restricted 5,259 Fair value of derivative instruments

- 175,337 149,285 448,657 Prepaid and other assets Total noncurrent assets 8,763 47,882 208,906 162,647 478,004 139,172 Current assets Cash and cash equivalents - restricted 742 2,111 5,316 4,369 10,381 3,363 Cash and cash equivalents - unrestricted 139 618 6,723 2,377 6,988 1,907 Interest receivable - 16 58 14 50 2 Accounts receivable 39 64 Due from other project - restricted Materials and supplies Prepaid and other assets ,495 1 01 8696 32,242 -

Total current assets 2,415 2,810 23,498 15,456 49,661 5,272 DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunding Accumulated decrease in fair value of hedging derivatives Total deferred outflows of resources Total assets and deferred outflows of resources 1 11178 , 50692 $ 232,404 $ 178,103 $ 527661 $ 144,444 LIABILITIES Noncurrent liabilities Long-term debt $ 7,983 S 51,716 $ 224,612 S 164,762 $ 513,295 $ 136,972 Fair value of derivative instruments Notes payable and other liabilities Advances from participants Total noncurrent liabilities 7,983 51,716 224,612 164,762 513,29S 136,972 Current liabilities Debt due within one year 1,755 790 8,135 5,065 17,850 3,425 Notes payable and other liabilities due within oneyear Advances from participants due within one year - 202 250 250 1,000 2.004 Accrued Interest 123 1,284 5,370 3,898 11,597 3,364 Accounts payable and accruals 45 417 7,930 7,596 5.746 2.956 Accrued property tax - - 773 247 Due to other projects Total current liabilities 1,923 2,693 21,685 16,809 36,966 11,996 Total liabilities 9,906 54,409 246,297 1811571 550,261 148,968 NET POSITION Net investment In capital assets (9,916) - - (10,114)

Restricted 6,134 6,393 Unrestricted 1,272 65 113,8931 (3,468) 122,596) (803)

Total net position 1,272 371717] (13,8931 (3,4681 (22,596) f4,524)

Total liabilities and net position $ 11,178 $ 50692 S 232.404 $ 178103 $ 527,665 $ 144,444 See accompanying notes. 16 See accompanying notes. 16

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF NET POSITION JUNE 30, 2014 (AMOUNTS IN THOUSANDS)

TRANSMISSION Southern Transmission System Mead- Phoenix Mead- Adelanto ASSETS Noncurrent assets Net utility plant $ 261,767 S 31,287 $ 91,226 Investments - restricted 66,092 2,300 17,900 Investments - unrestricted Advance to IPA - restricted 11,S50 Advances for capacity and energy, net - restricted Fair value of derivative instruments 752 Prepaid and other assets Total noncurrent assets 339,409 33,587 109.878 Current assets Cash and cash equivalents - restricted 32,585 4,100 10,050 Cash and cash equivalents - unrestricted 146 322 358 Interest receivable 54 1 1 Accounts receivable 3,834 114 63 Due from other project - restricted Materials and supplies Prepaid and other assets Total current assets 36,619 4,537 10,472 DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunding 50,438 3,751 11,580 Accumulated decrease in fair value of hedging derivatives Total deferred outflows of resources 50,438 3,751 11,580 Total assets and deferred outflows of resources 426.466 $ 41.875 $ 131.930 LIABILITIES Noncurrent liabilities Long-term debt $ 681,723 S 35,928 $ 120,185 Fair value of derivative instruments 28,028 Notes payable and other liabilities 2,477 Advances from participants Total noncurrent liabilities 709,751 35,928 122,662 Current liabilities Debt due within one year 50,885 5.215 17,385 Notes payable and other liabilities due within one year Advances from participants due within one year Accrued interest 14,391 814 2,954 Accounts payable and accruals 6,035 102 363 Accrued property tax Due to other projects Total current liabilities 71,311 6,131 20.702 Total liabilities 781,062 42,059 143,364 NET POSITION Net investment in capital assets (412,196) (6,105) (37,241)

Restricted 87,683 5,556 24,970 Unrestricted (30.0831 365 837 Total net position (354,5961 (1841 (11.4341 Total liabilities and net position 426,466 $ 4r875 $ 131,930 17 See accompanying notes.

17 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF NET POSITION JUNE 30, 2013 (As Restated)

(AMOUNTS IN THOUSANDS)

TRANSMISSION Southern Transmission System Mead- Phoenix Mead- Adelanto ASSETS Noncurrent assets Net utility plant $ 284,521 $ 32,746 $ 95,748 Investments - restricted 66,384 5,869 22,686 Investments - unrestricted Advance to IPA - restricted 11,550 Advances for capacity and energy, net - restricted Fair value of derivative instruments 625 Prepaid and other assets Total noncurrent assets 362,455 38,615 119.059 Current assets Cash and cash equivalents - restricted 32,744 1,469 4,425 Cash and cash equivalents - unrestricted 3,643 190 41 Interest receivable 75 203 834 Accounts receivable 188 95 Due from other project - restricted 6,734 19,637 Materials and supplies Prepaid and other assets Total current assets 3r,462 8,784 25,032 DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunding 69,188 5,915 18,620 Accumulated decrease in fair value of hedging derivatives Total deferred outflows of resources 69,188 5,915 18,620 Total assets and deferred outflows of resources $ 468.105 53,314 $ 162.711 LIABILITIES Noncurrent liabilities Long-term debt $ 737,010 $ 41,695 $ 140,042 Fair value of derivative instruments 30,290 -

Notes payable and other liabilities - 2,477 Advances from participants Total noncurrent liabilities 767,300 41,695 142.519 Current liabilities Debt due within one year 49,130 6,505 17,820 Notes payable and other liabilities due within one year 628 Advances from participants due within one year Accrued interest 13,472 1,002 3,473 Accounts payable and accruals 7,000 206 1,031 Accrued property tax Due to other projects Total current liabilities 69.602 7,713 22,952 Total liabilities 836,902 49,408 165,471 NET POSITION Net investment in capital assets (424,297) (9,539) (46,598)

Restricted 89,013 13,114 43,376 Unrestricted (33,5131 331 462 Total net position (368,7971 3,906 (2,7601 Total liabilities and net position 468,10S S 53.314 $ 162,711 See accompanying notes. is See accompanying notes. 18

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF NET POSITION JUNE 30, 2014 (AMOUNTS IN THOUSANDS)

NATURAL GAS Pinedale Barnett Prepaid Natural Gas ASSETS Noncurrent assets Net utility plant $ 48,747 $ 54,240 $

Investments - restricted 27,950 11,579 Investments -unrestricted Advance to IPA - restricted Advances for capacity and energy, net - restricted Fair value of derivative instruments Prepaid and other assets 126 - 246.424 Total noncurrent assets 48.873 82.190 258,003 Current assets Cash and cash equivalents - restricted 10,055 13,988 6,839 Cash and cash equivalents - unrestricted 9,235 2,121 23 Interest receivable 43 47 Accounts receivable 1,711 1,562 1,441 Due from other project - restricted Materials and supplies Prepaid and other assets 652 11.292 Total current assets 21,653 17.714 19.642 DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunding Accumulated decrease in fair value of hedging derivatives , 8,537 Total deferred outflows of resources ,8537 Total assets and deferred outflows of resources $ 70,526 $ 99,904 $ 286.182 LIABILITIES Noncurrent liabilities Long-term debt 24,763 $ 58,162 $ 312,724 Fair value of derivative instruments 8,537 Notes payable and other liabilities Advances from participants 19,261 9,146 -

Total noncurrent liabilities 44,024 67,308 321,261 Current liabilities Debt due within one year 2,219 5,211 3,875 Notes payable and other liabilities due within one year Advances from participants due within one year 10,045 1,301 -

Accrued interest 745 1,752 2,659 Accounts payable and accruals 4,853 2,426 2,796 Accrued property tax 3,595 -

Due to other projects Total current liabilities 21,457 10,690 9,330 Total liabilities 65,481 77,998 330.591 NET POSITION Net investment in capital assets 341 6,970 Restricted 2,206 13,679 Unrestricted 2,498 1,257 (44.4091 Total net position 5,045 21.906 (44.4091 Total liabilities and net position $ 70.526 $ 99,904 $ 286,182 19 See accompanying notes.

19 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF NET POSITION JUNE 30, 2013 (As Restated)

(AMOUNTS IN THOUSANDS)

NATURAL GAS Pinedale Barnett Prepaid Natural Gas ASSETS Noncurrent assets Net utility plant 53,724 $ 57,944 $

Investments - restricted 7,600 34,395 11.510 Investments - unrestricted 999 Advance to IPA - restricted Advances for Capacity and energy, net - restricted Fair value of derivative instruments Prepaid and other assets 126 - 258,374 Total noncurrent assets 62.449 92.339 269,884 Current assets Cash and cash equivalents - restricted 7,014 1,111 5,711 Cash and cash equivalents - unrestricted 8,469 7,352 239 Interest receivable 55 45 Accounts receivable 2,297 1,715 1,470 Due from other project - restricted Materials and supplies Prepaid and other assets 653 - 11,316 Total current assets 18,433 10,233 18,781 DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunding Accumulated decrease In fair value of hedging derivatives 8,136 Total deferred outflows of resources 8,136 Total assets and deferred outflows of resources $ 80,882 $ 102.572 $ 296,801 LIABILITIES Noncurrent liabilities Long-term debt 26,982 $ 63.373 $ 316,873 Fair value of derivative instruments 8,137 Notes payable and other liabilities Advances from participants 21,038 9,775 -

Total noncurrent liabilities 48,020 73,148 325,010 Current liabilities Debt due within one year 2,253 5,302 4,065 Notes payable and other liabilities due within one year Advances from participants due within one year 12,022 1,279 -

Accrued interest 794 1,867 2,693 Accounts payable and accruals 8,387 1,603 1,686 Accrued property tax 3,763 - -

Due to other projects Total current liabilities 27.219 10,051 8,444 Total liabilities 75239 83,199 333,454 NET POSITION Net investment in capital assets 3,451 10,898 -

Restricted 2,576 1,014 Unrestricted (3841 7,461 136,6531 Total net position 5r643 19.373 (36,6531 Total liabilities and net position 80.882 $ 102 572 $ 296,801 See accompanying notes. 20 Se -acmpnyn noe.2

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF NET POSITION JUNE 30, 2014 (AMOUNTS IN THOUSANDS)

Ormat Arneresco Don A. Campbell Geothermal Chiqulta Landfill Wild Rose Copper Mountain Energy MWI Small Hydra Pebble Springs Gas Geothermal Solar 3 ASSETS Noncurrent assets Net utility plant Investments - restricted Investments - unrestricted Advance to IPA - restricted S- - - - - - -- - - - -

Advance%for capacity and energy, net - restricted Fair value of dervative instruments Prepaid and other assets Total noncurrent assets Current assets Cash and cash equivalents - restricted Cash and cash equivalents - unrestricted 2,819 1,221 4,123 2,041 67 1,615 Interest receivable Accounts receivable 170 915 Due from other project - restricted Materials and supplies Prepaid and other assets 3 6 Total current assets 2,822 1,397 4,123 2,041 982 1,615 DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunding Accumulated decrease in fair value of hedging derivatives Total deferred outflowo of resources Total assets and deferred outflows of resources S 2,822 $ 1,397 $ 4,123 S 2,041 S 982 S 1,615 LIABILITIES Noncurrent liabilities Long-term debt $ SSS - $ .

Fair value of derivative instruments Notes payable and other liabilities Advances from participants Total noncurrent liabilities Current liabilities Debt doe within one year Notes payable and other liabilities due within one year Advances from participants due within one year 857 So0 400 Accrued interest Accounts payable and accruals 1,965 897 4,123 1,641 982 1,61S Accrued property tan Due to other projects Total current liabilities 2822 1,397 4,123 2,041 982 1,615 Total liabilities 2,22 1,397 4r123 2,041 982 1,615 NET POSITION Net investment in capital assets Restricted Unrestricted Total net position

, , 28,22 , 12,Ir97 5 4123 5 2041 8 5 1,611 Total liabilities and net position 21 See accompanying notes.

21 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF NET POSITION JUNE 30, 2013 (As Restated)

(AMOUNTS IN THOUSANDS)

POWER PURCHASE AGREEMENTS Ormat Ameresco Geothermal MWD Small Chiqulta Landfill Energy Hydro Pebble Sprines Gas ASSETS Noncurrent assets Net utility plant $ - $- -

Investments - restricted Investments - unrestricted Advance to IPA - restricted Advances for capacity and energy, net - restricted Fair value of derivative instruments Prepaid and other assets Total noncurrent assets Current assets Cash and cash equivalents - restricted Cash and cash equivalents - unrestricted 5,386 1,993 7,713 2,284 Interest receivable 1 Accounts receivable 188 Due from other project - restricted Materials and supplies Prepaid and other assets 9 15 6 Total current assets 5,395 2,008 7,714 2,478 DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunding Accumulated decrease in fair value of hedging derivatives Total deferred outflows of resources

$ -- 5-395 $ 2008 $ 7-714 $ 2,478 Total assets and deferred outflows of resources LIABILITIES Noncurrent liabilities Long-term debt $ - $ - $

Fair value of derivative instruments Notes payable and other liabilities Advances from participants Total noncurrent liabilities Current liabilities Debt due within one year Notes payable and other liabilities due within one year Advances from participants due within one year 1,045 S00 400 Accrued interest Accounts payable and accruals 4,350 1,S08 7,714 2,078 Accrued property tax Due to other projects Total current liabilities 5,395 2,008 7,714 2,478 Total liabilities 5r395 7,714 2,478 NET POSITION Net investment in capital assets Restricted Unrestricted Total net position

$,5395 , $7,74 Total liabilities and net position

• 2,478_

See accompanying notes. 22 See accompanying notes. 22

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF NET POSITION JUNE 30, 2014 (AMOUNTS IN THOUSANDS)

MISCELLANEOUS Project Projects' SCPPA Multiple Development Stabilliation Building Total Project Fund Fund Fund Fund Total Eliminations Combined ASSETS Noncurrent assets Net utility plant $ $ $ 4,224 $ 1,574,194 S $ 1.574,194 Investments - restricted 130,967 - 648,532 648.532 Investments - unrestricted 31,037 31.037 Advance to IPA- restricted 11,550 11,550 Advances for capacity and energy, net - restricted 3,688 3,688 Fair value of derivative instruments 752 752 Prepaid and other assets 968,744 - 968,744 Total noncurrent assets - 130,967 4,224 3,238,497 - 3,2381497 Current assets Cash and cash equivalents - restricted 65 20,826 314 205,018 205,018 Cash and cash equivalents - unrestricted 96,735 96,73S Interest receivable 234 3,042 3,042 Accounts receivable - 17,399 17,399 Due from other project - restricted Materials and supplies 24,904 24,904 Prepaid and other assets 69,603 - 69,603 Total current assets 65 21,060 314 416,701 416,701 DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunding - 79,668 79,668 Accumulated decrease in fair value of hedging derivatives 15,393 - 15,393 Total deferred outflows of resources 95,061 95,061 Total assets and deferred outflows of resources S - 1 0 3$38 S 3,750259 S -

LIABILITIES Noncurrent liabilities Long-term debt $ 3,353,692 $ $ 3,353,692 Fair value of derivative Instruments 55,984 55.984 Notes payable and other liabilities 15,890 15,890 Advances from participants 30,907 30,907 Total noncurrent liabilities 3.456,473 - ---- 3,456,473 Current liabilities Debt due within one year 158,320 158.320 Notes payable and other liabilities due within one year 15,27S 15.275 Advances from participants due within one year 65 282 50,892 50,892 Accrued interest - - 65,396 65,396 Accounts payable and accruals 33 96,337 96.337 Accrued property tax 6,253 6,253 Due to other projects Total current liabilities 65 31S 392-473 3923473 Total liabilities - 65 315 3,848,946 . 3848,946 NET POSITION Net investment in capital assets 4,223 (608,196) (608.196)

Restricted 152,027 - 583.618 583.618 Unrestricted (74,1091 (74,109)

Total net position -152027 4,223 198,6871 (98,687)

Total liabilities and net position S - 65 $ 152,027 S 4,538 _ 3750259 $ $ 3$70259 23 See accompanying notes.

23Se -copayn nts

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF NET POSITION JUNE 30,2013 (As Restated)

(AMOUNTS IN THOUSANDS)

MISCELLANEOUS Project Projects' SCPPA Multiple Development Stabilization Building Total Project Fond Fund Fund Fund Total Eliminations Combined ASSETS Noncurrent assets Net utility plant S - $ - S 4,264 $ 1,362,772 S S 1,362,772 Investments - restricted 39.197 117,496 - 682,044 682,044 Investments - unrestricted 48,529 48,529 Advance to IPA- restricted 11,550 11,550 Advances for capacity and energy, net - restricted 5,259 5,259 Fair value of derivative Instruments 625 625 Prepaid and other assets - 1,032,953 - 1,032,953 Total noncurrent assets 39,197 . 117,496 4,264 3,143,732 - - 3,143,732 Current assets Cash and cash equivalents - restricted 154 9,813 46 151,476 151,476 Cash and cash equivalents - unrestricted - - - 79,453 79,453 Interest receivable 1,441 274 3,822 3,822 Accounts receivable 9,692 9,692 Due from other project - restricted 26,371 (26,371)

Materials and supplies 21,272 21,272 Prepaid and other assets - - 67,158 - 67,158 Total current assets 1,441 154 10,087 46 359,244 (26,3711 332,873 DEFERRED OUTFLOWS OF RESOURCES 109,205 109,205 Unamortized loss on refunding Accumulated decrease In fair value ofhedging derivatives 13,541 13,541 Total deferred outflows of resources - - - - 122,746 122,746 Total assets and deferred outflows of resources $ 40638 S 154 $ 127583 $ 4310 S 3625722 $$

LIABIUTIES Noncurrent liabilities Long-term debt $ $ $ $ 3,200,415 $S S3,200,415 Fair value ofderivative instruments 54,399 54,399 Notes payable and other liabilities - 22,214 22,214 Advances from participants -30,813 - 30813 Total noncurrent liabilities - 3,307,841 3,307,841 Current liabilities Debt due within one year 13,800 189,730 189,730 Notes payable and other liabilities due within one year - 11.572 11.572 Advances from participants due within one year - 154 13 46,894 46,894 Accrued interest 467 - - 64,173 64,173 Accounts payable and accruals 33 79,658 79,658 Accrued property tax 6,482 6,482 Due to other projects 267 - 26,371 126,3711 -

Total current liabilities 401638 154 - 46 424,880 (26,371) 398,1509 Total liabilities 40,638 154 - 46 3,732,721 (26,3713 3,706,350 NET POSITION Net investment In capital assets 4,264 (621.687) (621,687)

Restricted 127,S83 565,717 565,717 Unrestricted - {(51,0291 (s1,029)

Total net position 127,583 4,264 f106,999) , - 106,999)

Total liabilities and net position $ S 540638 154 127,583 _$ 4,310 $ 3,62.S722 $ (26,371) S 3.S99,351 See accompanying notes. 24

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

GENERATION Magnolia Palo Verde San Juan Power Canyon Power Apex Power Operating revenues Sales of electric energy $ 82,369 $ 77,298 $ 101,292 $ 19,456 $ 25,517 Sales of transmission services Sales of natural gas Total operating revenues 82,369 77,298 101,292 19,456 25,517 Operating expenses Operations and maintenance 41,851 63,443 78,853 6,683 22,390 Depreciation, depletion and amortization 20,695 7,926 11,438 9,582 3,015 Amortization of nuclear fuel 16,031 - -

Decommissioning 2,429 3,250 Total operating expenses 81,006 74,619 90,291 16,265 25,405 Operating income (loss) 1,363 2,679 11I001 3,191 112 Non operating revenues (expenses)

Investment and other income 8,000 6,092 1,155 4,279 13 Derivative gain (loss) (1,995) - -

Debt expense f285) (3,9911 (11,720) (15,674) (5,434)

Net non operating revenues (expenses) 7,715 2,101 (12,560) (11,395) (5,421)

Change in net position 9,078 4,780 (1,559) (8,204) (5,309)

Net position - beginning of year 240,757 27,083 (62,514) (17,958)

Net contributions (distributions) by participants Net position - end of year $ 249,835 l 31863 S (64,073) $ (26.162) $ (5,309) 2S See accompanying notes.

25 ee ccopay-n noes

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION FOR THE YEAR ENDED JUNE 30,2013 (As Restated)

(AMOUNTS IN THOUSANDS)

GENERATION Palo Verde San Juan Magnolia Power Canyon Power Operating revenues Sales of electric energy $ 79,386 $ 105,300 $ 67,354 $ 20,809 Sales of transmission services Sales of natural gas Total operating revenues 79,386 105,300 67,354 20,809 Operating expenses Operations and maintenance 40,506 68,920 48,482 8,147 Depreciation, depletion and amortization 20,570 6,955 10,949 9,331 Amortization of nuclear fuel 16,749 Decommissioning 2,429 4,326--

Total operating expenses 80,254 80,201 59,431 17,478 Operating income (loss) (868) 25,099 7,923 3,331 Non operating revenues (expenses)

Investment and other income (3,062) 1,153 (242) 3,378 Derivative gain (loss) - 14,715 Debt expense (4,903) (12,189) (15,674)

Net non operating revenues (expenses) (5,244) (3,750) 2,284 (12,296)

Change in net position (6,112) 21,349 10,207 (8,965)

Net position - beginning of year 247,077 6,226 (44,554) (6,803)

Cumulative effect of restatement (208) (492) (28,167) (2,190)

Net position - beginning of year as restated 246,869 5,734 (72,721) (8,993)

Net position - end of year $ 240,757 $ 27,083 $ (62,514) $ (17, See accompanying notes. 26 See accompanying notes. 26

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

GREEN POWER Windy Linden Hoover Tieton Milford I Milford II Point Wind Uprating Hydropower Wind Wind Project Energy Operating revenues Sales of electric energy $ 2,535 $ 4,525 $ 29,962 $ 18,423 $ 78,446 $17,313 Sales of transmission services Sales of natural gas Total operating revenues 2,535 4,525 29,962 18,423 78,446 17,313 Operating expenses Operations and maintenance 3,350 1,308 22,751 14,264 69,257 7,993 Depreciation, depletion and amortization 1,465 5,814 Amortization of nuclear fuel Decommissioning Total operating expenses 3,350 2,773 22,751 14,264 69,257 13,807 Operating income (loss) (815) 1,752 7,211 4,159 9,189 3,506 Non operating revenues (expenses)

Investment and other income 62 314 471 68 232 865 Derivative gain (loss)

Debt expense 1,122 ( (9,096) (5,3571 (16,130) (5,565)

Net non operating revenues (expenses) 1,184 (2,167) (8,625) (5,289) (15,898) (4,700)

Change in net position 369 (415) (1,414) (1,130) (6,709) (1,194)

Net position - beginning of year 1,272 (3,717) (13,893) (3,4681 (22,596) (4,524)

Net contributions (distributions) by participants ---

Net position - end of year $ 1,641 $ (4,132) 45,718) 3 $(15,307) $ (4,598) $ (29,305) $

=__l 27 See accompanving notes.

27 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION FOR THE YEAR ENDED JUNE 30,2013 (As Restated)

(AMOUNTS IN THOUSANDS)

GREEN POWER Windy Linden Hoover Tieton Milford I Milford I! Point Wind Uprating Hydropower Wind Wind Proiect Energy Operating revenues Sales of electric energy $ 2,575 $ 4,663 $ 33,546 $ 18,403 $ 80,724 $ 17,761 Sales of transmission services Sales of natural gas Total operating revenues 2,575 4,663 33,546 18,403 80,724 17761 Operating expenses Operations and maintenance 3,525 1,496 26,396 14,245 72,269 8,470 Depreciation, depletion and amortization 1,465 5,814 Amortization of nuclear fuel Decommissioning Total operating expenses 3,525 2,961 26,396 14,245 72,269 14,284 Operating income (loss) (950) 1,702 7,150 4,158 8,455 3,477 Non operating revenues (expenses)

Investment and other income (32) (27) (325) 2 736 784 Derivative gain (loss)

Debt expense 1,281 (2,504) (9,238) (5,377) (16,264) (5,594)

Net non operating revenues (expenses) 1,249 f2,531) (9,563) (5,375) (15,528) (4,810)

Change in net position 299 (829) (2,413) (1,217) (7,073) (1,333)

Net position - beginning of year 1,031 (2,265) (9,899) (1,040) (12,674) (2,180)

Cumulative effect of restatement (58) (623) (1,581) (1,211) (2,849) (1,011)

Net position - beginning of year as restated 973 (2,888) (11,480) (2,251) (15,523) (3,191)

Net position - end of year $ 1,272 $ 3,717) $ (13,893) $ (3,468) $ (22,596) $ 4,524)

See accompanying notes. 28 Seeaccmpayig ntes 2

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

TRANSMISSION Southern Transmission System Mead- Phoenix Mead- Adelanto Operating revenues Sales of electric energy $ $ ,2 $

Sales of transmission services 117,170 8,257 25,659 Sales of natural gas Total operating revenues 117,170 8,257 25,659 Operating expenses Operations and maintenance 35,269 1,264 2,098 Depreciation, depletion and amortization 22,754 1,524 4,522 Amortization of nuclear fuel Decommissioning Total operating expenses 58,023 2,788 6,620 Operating income (loss) 59,147 5,469 19,039 Non operating revenues (expenses)

Investment and other income 903 3 26 Derivative gain (loss) 2,263 - 127 Debt expense (48,112) (3,178) (9,429)

Net non operating revenues (expenses) (44,946) (3,175) (9,2761 Change in net position 14,201 2,294 9,763 Net position -beginning of year (368,797) 3,906 (2,760)

Net contributions (distributions) by participants (6,384) (18,437)

Net position - end of year $ (354,52a) $ J18n4 $ (11,434) 29 See accompanying notes.

29 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION FOR THE YEAR ENDED JUNE 30, 2013 (As Restated)

(AMOUNTS IN THOUSANDS)

TRANSMISSION Southern Transmission System Mead- Phoenix Mead- Adelanto Operating revenues Sales of electric energy $ 17 $ 31 $

Sales of transmission services 107,797 3,150 8,375 Sales of natural gas Total operating revenues 107,797 3,150 8,375 Operating expenses Operations and maintenance 25,333 1,134 2,107 Depreciation, depletion and amortization 22,750 1,523 4,522 Amortization of nuclear fuel Decommissioning Total operating expenses 48,083 2,657 6,629 Operating income (loss) 59,714 493 1,746 Non operating revenues (expenses)

Investment and other income 5,717 535 2,106 Derivative gain (loss) 24,088 5,498 15,888 Debt expense (46,458) (3,482) (10,924)

Net non operating revenues (expenses) (16,653) 2,551 7,070 Change in net position 43,061 3,044 8,816 Net position -beginning of year (407,074) 1,255 (10,775)

Cumulative effect of restatement (4,784) (39L) (801)

Net position - beginning of year as restated (411,858) 862 (11,576)

Net position - end of year $ (368,797) $ 3,906 $ (_2,760)

See accompanying notes. 30 Se nts.3 acmpnin

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION FOR THE YEAR ENDED JUNE 30, 2014 (AMOUNTS IN THOUSANDS)

NATURAL GAS Prepaid Natural Pinedale Barnett Gas Operating revenues Sales of electric energy $ $ $

Sales of transmission services Sales of natural gas 9,951 20,116 16,312 Total operating revenues 9,951 20,116 16,312 Operating expenses Operations and maintenance 4,018 10,601 11,754 Depreciation, depletion and amortization 5,046 4,070 Amortization of nuclear fuel Decommissioning Total operating expenses 9,064 14,671 11,754 Operating income (loss) 887 5,445 4,558 Non operating revenues (expenses)

Investment and other income 5 591 4,092 Derivative gain (loss)

Debt expense (1,4901 (3,503)_ (16,406)

Net non operating revenues (expenses) (1,485) (2,912) (12,3141 Change in net position (598) 2,533 (7,756)

Net position - beginning of year 5,643 19,373 C36,653)

Net contributions (distributions) by participants Net position - end of year $ 5,045 $ 21,906 $ (44,409) 31 See accompanying notes.

31 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION FOR THE YEAR ENDED JUNE 30,2013 (As Restated)

(AMOUNTS IN THOUSANDS)

NATURAL GAS Prepaid Natural Pinedale Barnett Gas Operating revenues Sales of electric energy $ - $ - $

Sales of transmission services Sales of natural gas 10,986 21,610 20,209 Total operating revenues 10,986 21,610 20,209 Operating expenses Operations and maintenance 4,462 10,481 12,475 Depreciation, depletion and amortization 5,877 4,465 Amortization of nuclear fuel Decommissioning Total operating expenses 10,339 14,946 12,475 Operating income (loss) 647 6,664 7,734 Non operating revenues (expenses)

Investment and other income 8 (295) 751 Derivative gain (loss)

Debt expense (1,587) (3,734) (16,608)

Net non operating revenues (expenses) (1,579) (4,029) (15,857)

Change in net position (932) 2,635 (8,123)

Net position - beginning of year 7,163 17,338 (26,407)

Cumulative effect of restatement (588) (600) (2,123)

Net position - beginning of year as restated 6,575 16,738 (28,530)

Net position - end of year $ 5,643 $ 19,373 $ (36,653)

See accompanying notes. 32 See accompanying notes. 32

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

POWER PURCHASE AGREEMENTS Ameresco Don A. Campbell Ormat MWD Small Pebble Chiquita Wild Rose Copper Mountain Geothermal Hydro Springs Landfill Gas Geothermal Solar 3 Operating revenues Sales of electric energy $ 7,768 $ 3,009 $ 23,222 $ 2,954 $ 9,350 $ 1.423 Sales of transmission services Sales of natural gas Total operating revenues 7,768 3,009 23,222 2,954 9,350 1,423 Operating expenses Operations and maintenance 7,774 3,011 23,227 2,954 9,3S0 1,423 Depreciation, depletion and amortization Amortization of nuclear fuel Decommissioning Total operating expenses 7,774 3,011 23,227 2,954 9,350 1,423 Operating income (loss] (61 (2) (5)

Non operating revenues (expenses)

Investment and other income 6 2 5 Derivative gain (loss)

Debt expense Net non operating revenues (expenses] 6 2 5 Change in net position Net position - beginning of year Net contributions (distributions) by participants Net position - end of year $ - $ - $ -$ -

33 See accompanying notes.

33 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION FOR THE YEAR ENDED JUNE 30, 2013 (As Restated)

(AMOUNTS IN THOUSANDS)

POWER PURCHASE AGREEMENTS Ameresco Ormat MWD Small Pebble Chiquita Geothermal Hydro Springs Landfill Gas Operating revenues Sales of electric energy $ 7,299 $ 2,235 $ 24,502 $ 3,241 Sales of transmission services Sales of natural gas Total operating revenues 7,299 2,235 24,502 3,241 Operating expenses Operations and maintenance 7,304 2,237 24,506 3,241 Depreciation, depletion and amortization Amortization of nuclear fuel Decommissioning Total operating expenses 7,304 2,237 24,506 3,241 Operating income (loss) (5) (2) (4)

Non operating revenues (expenses)

Investment and other income 5 2 3 Derivative gain (loss)

Debt expense Net non operating revenues (expenses) 5 2 3 Change in net position - - (1)-

Net position - beginning of year Cumulative effect of restatement Net position - beginning of year as restated Net position - end of year $ - $ - $ - $

See accompanying notes. 34 See accompanying notes. 34

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

MISCELLANEOUS Multiple Project Projects' SCPPA Project Development Stabilization Building Total Fund Fund Fund Fund Combined Operating revenues Sales of electric energy $ $ $ $ - $ 504,862 Sales of transmission services -- 151,086 Sales of natural gas 46,379 Total operating revenues -- 702,327 Operating expenses Operations and maintenance 130 445,016 Depreciation, depletion and amortization 113 97,964 Amortization of nuclear fuel -- 16,031 Decommissioning -- 5,679 Total operating expenses 243 564,690 Operating income (loss) (243) 137,637 Non operating revenues (expenses)

Investment and other income 2,752 130 30,066 Derivative gain (loss) S- - 395 Debt expense S- - (156,729)

Net non operating revenues (expenses) 2752 130 (126,268)

Change in net position 2,752 (113) 11,369 Net position - beginning of year 127,583 4,264 (106,999)

Net contributions (distributions) by participants 21,692 72 (3,057)

Net position - end of year $ $ $ 152,027 $ 4,223 $ (98,687) 35 See accompanying notes.

35Seacmanignts

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION FOR THE YEAR ENDED JUNE 30, 2013 (As Restated)

(AMOUNTS IN THOUSANDS)

MISCELLANEOUS Project Projects' SCPPA Multiple Development Stabilization Building Total Project Fund Fund Fund Fund Combined Operating revenues Sales of electric energy $ $ $ $ $ 467,798 Sales of transmission services 119,322 Sales of natural gas 52,805 Total operating revenues 639,925 Operating expenses Operations and maintenance 263 385,999 Depreciation, depletion and amortization 113 94,334 Amortization of nuclear fuel -- 16,749

- 6,755 Decommissioning Total operating expenses 376 503,837 Operating income (loss) - (376) 136,088 Non operating revenues (expenses)

Investment and other income 4,724 (1,457) 263 14,727 Derivative gain (loss) S- - 60,189 Debt expense (2,208) - - (157,645)

Net non operating revenues (expenses) 2,516 - (1,457) 263 (82,729)

Change in net position 2,516 (1,457) (113) 53,359 Net position - beginning of year (2,516) 112,419 4,369 (129,308)

Cumulative effect of restatement -- - -(47,679]

Net position - beginning of year as restated (2,516) 112,419 4,369 (176,987)

Net contributions by participants 16,621 8 16,629 Net position - end of year $ - $ - $ 127,583 $ 4,264 $ (106,999)

See accompanying notes. 36 See accompanying notes. 36

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

GENERATION Palo Verde San loan Magnolia Power Canyon Power Avex Power Cash flows from operating activities Receipts from participants $ 75,291 $ 86,764 $ 54,969 $ 16,033 $ 27,836 Receipts from sale of oil and gas Payments to operating managers (39,630) (58,591) (25,900) (2,416) (6,252)

Other disbursements and receipts 7,633 - - - 173 Net cash flows from operating activities 43,294 28,173 29,069 13,617 21,757 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net Cash flows from capital financing activities Additions to plant and prepaid projects, net (28,446) (1,681) (920) (7,032) (296,120)

Debt Interest and swap payments (275) (5,093) (12,100) (14,893) -

Proceeds from sale of bonds - - - - 333,872 Payment for defeasance of revenue bonds Transfer of funds from (to) escrow Transfer of funds from (to] Mine Reclamation Trust Fund (489)-

Transfer of funds from (to] other projects Principal payments on debt (10,980] (27,250) (15,605) 229 Payment for bond issue costs -- - - 2.2931 Net cash used for capital and related financing activities (39,7011 (34.,5131 1"28,6251 121.925 35,459 Cash flows from investing activities Interest received on investments 255 799 660 290 5 Purchases of investments (22,921) (32,898) (41,566) (15,967) (23,485)

Proceeds from sale/maturity of investments 12,030 43,434 39,160 23 875-Net cash provided by (used for) investing activities (10,636) 11,335 (1,7461 8,198 (23,400 Net increase (decrease) in cash and cash equivalents (7,043) 4,995 (1,302) (110) 33,736 Cash and cash equivalents, beginning of year 24,335 17,333 35,047 9,383 Cash and cash equivalents, end ofyear $ 17.292 23 9273 $ 333736 Reconciliation of operating income (loss) to net cash provided by operating activities Operating income (loss) $ 1,363 $ 2,679 $ 11,001 $ 3,191 $ 112 Adjustments to reconcile operating income (loss) to net cash provided by operating activities Depreciation, depletion and amortization 20,695 7,926 11,438 9,582 3,214 Decommissioning 2,429 3,250 Advances for capacity and energy Amortization of nuclear fuel 16,031 Changes in assets and liabilities Accounts receivable (139) 50 (1,025) 1,010 -

Accounts payable and accruals 3,125 9,586 4,059 (193) 18,712 Other (2101 4,682 3,596 27 12811 Net cash provided by operating activities 43,94 2

,, ,*8,173 , s, 29,069 , 13 617 , 21.757 Cash and cash equivalents as stated in the Combined Statements of Net Position Cash and cash equivalents - restricted $ 9,869 $ 8,596 $ 27,618 $ 7,576 $ 16,306 Cash and cash equivalents - unrestricted 7,423 13,732 6,127 1,697 17,430

$ 17292 .- 22,328 $ 33.745 $ 9,273 $ 33.736 37 See accompanying notes.

37 Se accmpaning otes

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30,2013 (AMOUNTS IN THOUSANDS)

GENERATION Palo Verde San luan Magnolia Power Canyon Power Cash flows from operating activities Receipts from participants 64,723 $ 96,475 $ 47,246 $ 14,427 Receipts from sale of oil and gas Payments to operating managers (44,755) (70,033) (26,042) (2,693)

Other disbursements and receipts 7,634 Net cash flows from operating activities 27,602 26,442 21,204 11,734 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net Cash flows from capital financing activities Additions to plant and prepaid projects, net (21,835) (16,931) (1,687) (1,216)

Debt interest and swap payments (728) (5,808) (12,583) (12,936)

Proceeds from sale of bonds Payment for defeasance of revenue bonds Transfer of funds from (to) escrow Transfer of funds from (to) Mine Reclamation Trust Fund (1,930)

Transfer of funds from (to) other projects Principal payments on debt (10,660) (13,010) (9,780)

Payment for bond issue costs Net cash used for capital and related financing activities (33,2231 (37,6791 (24,0511 [14,1521 Cash flows from investing activities Interest received on investments 270 1,214 795 285 Purchases of investments (31,895) (20,215) (75,006) (39,122)

Proceeds from sale/maturity of investments 32,S80 28,780 69,246 33,599 Net cash provided by (used for) investing activities 955 9,779 (4,965) fS,2381 Net increase (decrease] in cash and cash equivalents (4,666) (1,458) (7,812) (7,656)

Cash and cash equivalents, beginning of year 294001 18,791 423859 17,039 Cash and cash equivalents, end of year $ 24t35

$ 7 333 $ 3 _L_7__9,383 Reconciliation of operating Income (loss) to net cash provided by operating activities Operating income (loss) $ (868) $ 25,099 $ 7,923 $ 3,331 Adjustments to reconcile operating income (loss) to net cash provided by operating activities Depreciation, depletion and amortization 20.570 6,955 10,949 9,331 Decommissioning 2,429 4,326 - -

Advances for capacity and energy Amortization of nuclear fuel 16,749 - -

Changes in assets and liabilities Accounts receivable 427 (107) 60 (934)

Accounts payable and accruals (10,490) (8,807) (5,619) 33 Other fl,2151 (1,024) 7,891 (27)

Net cash provided by operating activities _1 27,602 26442734 Cash and cash equivalents as stated in the Combined Statements of Net Position Cash and cash equivalents - restricted $ 19,371 $ 5,878 $ 28,701 $ 8,757 Cash and cash equivalents - unrestricted 4,964 11,455 6,346 626

$ 24,335 l $ 17,333 $ 35.047 $ 9,383 See accoMpanying notes. 38 See aCCompanying notes. 38

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

GREEN POWER Hoover Tieton Milford I Milford II Windy Point Linden Wind Uprating Hydropower Wind Wind Proiect Energy Cash flows from operating activities Receipts from participants $ 2.583 S 4,459 $ 30,544 $ 16.508 S 79,488 $ 17,292 Receipts from sale of oil and gas Payments to operating managers (308) (1,177) (12,133) (5,647) (38,077) (9,836)

Other disbursements and receipts - 155 643 Net cash flows from operating activities 2,275 3,437, 19,054 10A861 41,411 7,456 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net Cash flows from capital financing activities Additions to plant and prepaid projects, net (81)

Debt interest and swap payments (455) (2,556) (10,581) (7,696) (22,850) (6,277)

Proceeds from sale of bonds Payment for defeasance of revenue bonds Transfer of funds from (to) escrow Transfer of funds from (to) Mine Reclamation Trust Fund Transfer of funds from (to) other projects Principal payments on debt (1,755) (790) (8,135) (5,065) (17,850) (3.425)

Payment for bond issue costs Net cash used for capital and related financing activities (2,2101 (3,4271 (18,716) (12,7611 (40.700] [9,7021 Cash flows from investing activities Interest received on investments 22 69 320 54 208 29 Purchases of investments (1,860) (500) (19,842) (9,696) (30,279) (6,232)

Proceeds from sale/maturity of investments 1,860 500 22,343 16100 36,873 10,485 Net cash provided by (used for) investing activities 22 69 2.821 6,458 6,802 4,282 Net increase (decrease) In cash and cash equivalents 87 79 3,159 4,558 7,513 2,036 Cash and cash equivalents, beginning ofyear 881 2,729 12,039 6,746 17,369 5,270

$ 968 $ 2808 $ 15198 $ 11.304 S 24.882 $ 7.306 Cashand cash equivalents, end of year Reconciliation of operating income (loss) to net cash provided by operating activities Operating income (loss) $ (81s) $ 1,752 $ 7.211 $ 4,159 $ 9,189 $ 3,506 Adjustments to reconcile operating income (loss) to net cash provided by operating activities Depreciation, depletion and amortization 1,465 11,338 8,643 31,635 5,814 Decommissioning Advances for capacity and energy 3,031 Amortization of nuclear fuel Changes in assets and liabilities Accounts receivable 38 Accounts payable and accruals 21 502 (1,941) 587 (1,864)

Other 220 3 - -

Net cash provided by operating activities Cash and cash equivalents as stated in the Combined Statements of Net Position Cash and cash equivalents - restricted $ 181 $ 2,124 $ 6,475 $ 5,372 $ 17,307 $ 4.772 Cashand cash equivalents - unrestricted 787 684 8,723 5,932 7575 2,534

$ 968 $ 2,808 $ 15.198 $ 11304 $ 24.882 $ 7.306

= A----%1 39 See accompanying notes.

39 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30,2013 (AMOUNTS IN THOUSANDS)

GREEN POWER Hoover Tieton Milford I Milford II Windy Point Linden Wind Uprating Hydropower Wind Wind Prolect Energy Cash flows from operating activities Receipts from participants $ 2,532 $ 4,617 $ 34,361 S 21,150 S 84,524 $ 18,331 Receipts from sale of oil and gas Payments to operating managers (334) (1,418) (15,203) (9,412) (39,985) (8,567)

Other disbursements and receipts 9 33111 1 1 4 Net cash flows from operating activities 2.198 3.3,10 1918 1 3 4t3 6 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net Cash flows from capital financing activities Additions to plant and prepaid projects, net Debt interest and swap payments (537) (2,575) (10,876) (7,839) (23,489) (5,935)

Proceeds from sale of bonds Payment for defeasance of revenue bonds Transfer of funds from (to) escrow Transfer of funds from (to) Mine Reclamation Trust Fund Transfer of funds from (to) other projects Principal payments on debt (1,670) (775) (7,860) (4,235) (17,240) (3,360)

Payment for bond issue costs Net cash used for capital and related financing activities (2,2071 (3,3501 (18,7361 (12,0741 (40,7291 (9.295)

Cash flows from investing activities Interest received on investments 27 70 371 53 174 39 Purchases of investments (2,995) (5,495) (45,399) (15,231) (33,823) (10,800)

Proceeds from sale/maturity of investments 3,560 5,007 36,419 S,140 18,762 4,165 Net cash provided by (used for) investing activities 592 (418) (8,6091 (10.0381 (14,8871 (6,5961 Net increase (decrease) in cash and cash equivalents 583 (458) (8,187) (10,374) (11,077) (6,127)

Cash and cash equivalents, beginning of year -298 3,187 20,226 17,120 28,446 11,397 Cash and cash equivalents, end of year $ 881 S 2.729 $ 12039 $ 674 739 $ 57 Reconciliation of operating income (loss) to net cash provided by operating activities Operating income (loss) $ (950) 1,702 $ 7,150 $ 4,158 $ 8,455 $ 3,477 Adjustments to reconcile operating income (loss) to net cash provided by operating activities Depreciation, depletion and amortization - 1,465 11,338 8,643 31,635 5,814 Decommissioning Advances for capacity and energy 3,202 Amortization of nuclear fuel Changes in assets and liabilities Accounts receivable (38) - - 781 1.328 -

Accounts payable and accruals (16) (62) 670 (1,844) 2.340 473 Other - 205 - 781 -

Net cash provided by operating activities $ 2,198 $ 3.310 $ 19.158 $ 11,738 $ 44539 $ 9.764 Cash and cash equivalents as stated in the Combined Statements of Net Position Cash and cash equivalents - restricted $ 742 $ 2,111 $ 5,316 $ 4,369 $ 10,381 $ 3,363 Cash and cash equivalents - unrestricted 139 618 6,723 2,377 6,988 1,907

$ 881 $ 2729 $ 12 039 $ 6746 $ 17369 $ 5270 See accompanying notes. 40 See accompanying notes. 40

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

TRANSMISSION Transmission System Mead- Phoenix Mead- Adelanto Cash flows from operating activities Receipts from participants $ 112,691 $ 8,524 $ 25,736 Receipts from sale of oil and gas Payments to operating managers (35,406) (1,511) (2,392)

Other disbursements and receipts Net cash flows from operating activities 77,285 7,013 23,344 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net Cash flows from capital financing activities Additions to plant and prepaid projects, net (91) (53)

Debt interest and swap payments (32,721) (1,816) (6,427)

Proceeds from sale of bonds Payment for defeasance of revenue bonds Transfer of funds from (to) escrow Transfer of funds from (to) Mine Reclamation Trust Fund Transfer of funds from (to) other projects 350 1,200 Principal payments on debt (49,130) (6,505) (17,820)

Payment for bond issue costs (2151 -

Net cash used for capital and related financing activities (82,1571 (8,0241 (23,047)

Cash flows from investing activities Interest received on investments 756 206 841 Purchases of investments (82,225) (2,300) (27,783)

Proceeds from sale/maturity of Investments 82,685 5,868 32,587 Net cash provided by (used for) investing activities 1.216 3,774 5,645 Net increase (decrease) in cash and cash equivalents (3,656) 2,763 5,942 Cash and cash equivalents, beginning of year 36,387 1,659 4,466 Cash and cash equivalents, end of year 32,731 $ 4.422 $ 10,408 Reconciliation of operating Income (loss) to net cash provided by operating activities Operating Income (loss) 59,147 $ 5,469 $ 19,039 Adjustments to reconcile operating income (loss) to net cash provided by operating activities Depreciation, depletion and amortization 22,754 1,524 4,522 Decommissioning Advances for capacity and energy Amortization of nuclear fuel Changes in assets and liabilities Accounts receivable (3,835) 39 31 Accounts payable and accruals (781) 13 38 Other f321 f286)

Net cash provided by operating activities $ 77,285 $ 7,013 $ 23,344 Cash and cash equivalents as stated in the Combined Statements of Net Position $ 32,585 S 4,100 $ 10,050 Cash and cash equivalents - restricted Cash and cash equivalents - unrestricted 146 322 358

$ 32,731 $ 4,422 $ 10.408 41 See accompanying notes.

41 Se acomp-yn noes

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30,2013 (AMOUNTS IN THOUSANDS)

TRANSMISSION Transmission System Mead- Phoenix Mead- Adelanto Cash flows from operating activities Receipts from participants $ 104,559 $ 3,000 $ 8,140 Receipts from sale of oil and gas Payments to operating managers (20,589) (1,358) (2,114)

Other disbursements and receipts Net cash flows from operating activities 83,970 1,642 6,026 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net Cash flows from capital financing activities Additions to plant and prepaid projects, net (2,026) (10)

Debt interest and swap payments (30,647) (6,966) (23,368)

Proceeds from sale of bonds 96,414 33,965 112,651 Payment for defeasance of revenue bonds (96,511) (29,947) (99,574)

Transfer of funds from (to) escrow (56,970)

Transfer of funds from (to) Mine Reclamation Trust Fund Transfer of funds from (to) other projects 510 285 Principal payments on debt - (5,530) (15,230)

Payment for bond issue costs (3011 f3211 (669)

Net cash used for capital and related financing activities (90,0411 f8.299) (25,9051 Cash flows from investing activities Interest received on investments 854 427 1,722 Purchases of investments (78,552) (985) (3,830)

Proceeds from sale/maturity of investments 67,770 4,399 14,636 Net cash provided by (used for] investing activities (9,9281 3,841 12,528 Net increase (decrease) in cash and cash equivalents (15,999) (2,816) (7,351)

Cash and cash equivalents, beginning of year 52,386 4,475 11,817 Cash and cash equivalents, end of year 36.387 $ ,1659 $ 4,466 Reconciliation of operating income (loss) to net cash provided by operating activities Operating income (loss) $ 59,714 $ 493 $ 1,746 Adjustments to reconcile operating income (loss) to net cash provided by operating activities Depreciation, depletion and amortization 22,750 1,523 4,522 Decommissioning Advances for capacity and energy Amortization of nuclear fuel Changes in assets and liabilities Accounts receivable 4,924 (138) (96)

Accounts payable and accruals (3,418) (227) (146)

Other (9)

Net cash provided by operating activities $ 83,970 $ 1,642 $ 6,026 Cash and cash equivalents as stated in the Combined Statements of Net Position $ 32,744 $ 1,469 $ 4,425 Cash and cash equivalents - restricted Cash and cash equivalents - unrestricted 3,643 190 41

$ 36,387 $ 1,659 $ 4,466 See accompanying notes. 42 Seeacoman-n noesi4

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

NATURAL GAS Prepaid Natural Pinedale Barnett Gas Cash flows from operating activities Receipts from participants $ 5,015 $ 10,196 $ 8,614 Receipts from sale of oil and gas 3,247 5,905 Payments to operating managers (3,912) (6,448) (1,632)

Other disbursements and receipts (71 13,430 Net cash flows from operating activities 4,343 9,653 20,412 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net 3,236 399 Cash flows from capital financing activities Additions to plant and prepaid projects, net (586) (536)

Debt interest and swap payments (1,538) (3,619) (16,056)

Proceeds from sale of bonds Payment for defeasance of revenue bonds Transfer of funds from (to) escrow Transfer of funds from (to) Mine Reclamation Trust Fund Transfer of funds from (to) other projects Principal payments on debt (2.253) (5.302) (4,065)

Payment for bond issue costs Net cash used for capital and related financing activities (4,3771 (9,457) f20,1211 Cash flows from investing activities Interest received on investments 5 251 691 Purchases of investments (1,200) (17,000) (27,435)

Proceeds from sale/maturity of investments 1.800 23,800 27,365 Net cash provided by (used for) investing activities 605 7,051 621 Net increase (decrease) In cash and cash equivalents 3,807 7,646 912 Cash and cash equivalents, beginning of year 15,483 8,463 5S950 Cash and cash equivalents, end of year $ 19.290 $ 16.109 $ 6,862 Reconciliation of operating income (loss) to net cash provided by operating activities Operating income (loss) $ 887 $ 5,445 $ 4,558 Adjustmnents to reconcile operating income (loss) to net cash provided by operating activities Depreciation, depletion and amortization 5,046 4,070 Decommissioning Advances for capacity and energy Amortization of nuclear fuel Changes in assets and liabilities Accounts receivable 52 (182) 28 Accounts payable and accruals 528 404 1,109 Other (2,1701 (841 14,717 Net cash provided by operating activities 4,343 $ 9.653 $ 20,412 Cash and cash equivalents as stated in the Combined Statements of Net Position $ 10,055 $ 13,988 $ 6,839 Cash and cash equivalents - restricted Cash and cash equivalents - unrestricted 9,235 2,121 23

$ 19.290 $ 16.109 $ 6.862 43 See accompanying notes.

43 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30,2013 (AMOUNTS IN THOUSANDS)

NATURAL GAS Prepald Natural Pinedale Barnett Gas Cash flows from operating activities Receipts from participants $ 4,868 $ 10,364 S 5,091 Receipts from sale of oil and gas 3,491 6,318 Payments to operating managers (4,053) (6,007) (824)

Other disbursements and receipts - 1 13,200 Net cash flows from operating activities 4,306 10,676 17.467 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net f15.6731 382 Cash flows from capital financing activities Additions to plant and prepaid projects, net (1,731) (5,907)

Debt interest and swap payments (1,639) (3,857) (16,278)

Proceeds from sale of bonds Payment for defeasance of revenue bonds Transfer of funds from (to) escrow Transfer of funds from (to) Mine Reclamation Trust Fund Transfer of funds from (to) other projects Principal payments on debt (2,549) (6,016) (4,805)

Payment for bond issue costs Net cash used for capital and related financing activities (5,9191 (15780) (21,0831 Cash flows from investing activities Interest received on investments 10 244 759 Purchases of investments (1,298) (59,609) (20,195)

Proceeds from sale/maturity of investments 699 46,749 22,522 Net cash provided by (used for) investing activities (589) (12,616) 3,086 Net increase (decrease) in cash and cash equivalents (17,875) (17,338) (530)

Cash and cash equivalents, beginning of year 33,358 25,801 6,480 Cash and cash equivalents, end of year $ 15,483 $ 8.463 $ 5950 Reconciliation of operating income (loss) to net cash provided by operating activities Operating income (loss) $ 647 $ 6,664 $ 7,734 Adjustments to reconcile operating income (loss) to net cash provided by operating activities Depreciation, depletion and amortization 5,877 4,465 Decommissioning Advances for capacity and energy Amortization of nuclear fuel Changes in assets and liabilities Accounts receivable (199) (289) 399 Accounts payable and accruals 479 661 (2,748)

Other C2.4981 [8251 12,082 Net cash provided by operating activities $ 4,306 $ 10,676 _ 17467 Cash and cash equivalents as stated in the Combined Statements of Net Position $ 7,014 $ 1,111 $ 5,711 Cash and cash equivalents - restricted Cash and cash equivalents - unrestricted 8,469 7.352 239

$ 15.483 $ 8,463 $ 5.950 See accompanying notes. 44 Se acmpn-nnts.4

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

POWER PURCHASE AGREEMENTS

• Hso.uuu La,,,pue* LuppW, Onoat Geothermal MWD Small Pebble Chiquita Landfill Wild Rose Mountain Solar Enerey Hydro Springs Gas Geothermal 3 Cash flows from operating activities Receipts from participants 4,823 $ 2.094 S 19,843 $ 2,446 $ 8,435 $ 1,618 Receipts from sale of oil and gas Payments to operating managers (7,395) (2,868) (23.438) (2.6891 (8,3681 (3)

Other disbursements and receipts Net cash flows from operating activities R.5721 4 7741 (1,5951 f2431 67 1,615 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net Cash flows from capital financing activities Additions to plant and prepaid projects, net Debt Interest and swap payments Proceeds from sale of bonds Payment for defeasance of revenue bonds Transfer of funds from (to) escrow Transfer of funds from (to) Mine Reclamation Trust Fund Transfer of fonds from (to) other projects Principal payments on debt Payment for bond Issue costs Net cash used for capital and related financing activities Cash flows from Investing activities Interest received on investments Purchases of investments Proceeds from sale/maturity of Investments Net cash provided by (used for) investing activities 5 2 5---

Net Increase (decrease) In cash and cash equivalents (2,567) (772) (3,590) (243) 67 1,615 Cash and cash equivalents, beginning of year 1,993 7,713 1386 2,284 6 1 Cash and cash equivalents, end of year $ 2,8L9 $ 1.22*1 $ 23 $ 2,041 S 67 $ 1.61,5, Reconciliation of operating income (loss) to net cash provided by operating activities Operating income (loss) (6) $ (2) S (S) $ - S - $

Adjustments to reconcile operating income (loss) to net cash provided by operating activities Depreciation, depletion and amortization Decommissioning Advances for capacity and energy Amortization of nuclear fuel Changes in assets and liabilities Accounts receivable - (170) - 188 (915) -

Accounts payable and accruals (2,572) (610) (3,590) (436) 982 1.615 Other 6 8 - S -

Net cash provided by operating activities S (2.5721 . I7741 .- 359S] 1 24]1 67 $ 1. is Cash and cash equivalents as stated in the Combined Statements of Net Position Cash and cash equivalents - restricted $ - $ - $ - S S$- S Cash and cash equivalents - unrestricted 2,819 1,221 4,123 2,041 67 1r615

,$ 2,819 *S 1L221 S 4123 - 2,041 1 67 s 45 See accompanying notes.

45 SeIcopnignts

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30, 2013 (AMOUNTS IN THOUSANDS)

POWER PURCHASE AGREEMENTS Ormat Geothermal MWD Small Pebble Ameresco Chiquita Energy Hydro Springs Landfill Gas Cash flows from operating activities Receipts from participants $ 10,334 $ 3,528 $ 27,254 $ 4,359 Receipts from sale ofoil and gas Payments to operating managers (9,006) (2,483) (24,863) (5,809)

Other disbursements and receipts Net cash flows from operating activities 1,328 1,045 2,391 (1,4501 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net Cash flows from capital financing activities Additions to plant and prepaid projects, net Debt interest and swap payments Proceeds from sale of bonds Payment for defeasance of revenue bonds Transfer of funds from (to) escrow Transfer of funds from (to) Mine Reclamation Trust Fund Transfer of funds from (to) other prolects Principal payments on debt Payment for bond issue costs Net cash used for capital and related financing activities Cash flows from investing activities Interest received on investments 2 3 Purchases of investments Proceeds from sale/maturity of investments Net cash provided by (used for) investing activities 6 2 3 Net increase (decrease) in cash and cash equivalents 1,334 1,047 2,394 (1,450)

Cash and cash equivalents, beginning of year 4,052 946 S.319 3.734 Cash and cash equivalents, end of year S 5.386 $ 1.993 $ 7.713 $ 2.284 Reconciliation of operating income (loss) to net cash provided by operating activities Operating income (loss) (5) $ (2) $ (4) $

Adjustments to reconcile operating income (loss) to net cash provided by operating activities Depreciation, depletion and amortization Decommissioning Advances for capacity and energy Amortization of nuclear fuel Changes in assets and liabilities Accounts receivable Accounts payable and accruals 1,340 1,057 2,395 (1,258)

Other (7) (101 - 1921 Net cash provided by operating activities $ 1,328 $ 1045 $ 2,391 $ -11450 Cash and cash equivalents as stated In the Combined Statements of Net Position $ - $ - $ - $

Cash and cash equivalents - restricted Cash alid cash equivalents - unrestricted 5,386 1.993 7,713 2,284

$ 5,386 $ 1,993 $ 7.713 $ 2,284 See accompanying notes. 46 See accompanying notes. 46

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

MISCELLANEOUS Project Projects' SCPPA Multiple Development Stabilization Building Total Project Fund Fund Fund Fund Combined Cash flows from operating actvities Receipts from participants $ $ $ $ $ 621,802 Receipts from sale of oil and gas 9,152 Payments to operating managers (296,029)

Other disbursements and receipts - - - (130) 21,897 Net cash flows from operating activities f(130) 356,822 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net (891 21,692 470 2S,708 Cash flows from capital financing activities Additions to plant and prepaid projects, net - (72) (335,618)

Debt interest and swap payments (466) - (145,419)

Proceeds from sale of bonds 333,872 Payment for defeasance of revenue bonds Transfer of funds from (to) escrow Transfer of funds from (to) Mine Reclamation Trust Fund (489)

Transfer of funds from (to) other projects (26,372) (24,822)

Principal payments on debt (13,800) (189,730)

Payment for bond issue costs *-(2,508)

Net cash used for capital and related financing activities (40,6381 (721 (364,7141 Cash flows from investing activities Interest received on investments 1,441 1,218 8,132 Purchases of investments (73,197) (436,386)

Proceeds from sale/maturity of investments39-197 61,300 481,262 Net cash provided by (used for) investing activities 40,638 (10,679) 53,008 Net increase (decrease) in cash and cash equivalents - (89) 11,013 268 70,824 Cash and cash equivalents, beginning of year 154 9,813 46 230,929 Cash and cash equivalents, end of year $ $ 65 $ 20,826 $ 314 $ 301.753 Reconciliation of operating income loss) to net cash provided by operating activities Operating income (loss) $ - $ - $ - $ (243) $ 137,637 Adjustments to reconcile operating income (loss) to net cash provided by operating activities Depreciation, depletion and amortization 113 149,779 Decommissioning -- 5,679 Advances for capacity and energy 3,031 Amortization of nuclear fuel 16,031 Changes in assets and liabilities Accounts receivable (4,830)

Accounts payable and accruals 29,294 Other 20,201 Net cash provided by operating activities $ - $ , $ (130) ,,$ 356.822 Cash and cash equivalents as stated in the Combined Statements of Net Position Cash and cash equivalents - restricted $ $ 65 $ 20,826 $ 314 $ 205,018 Cash and cash equivalents - unrestricted S- - 96,735

$ $ 65 $ 20,826 $ 314 $ 301 753 47 See accompanying notes.

47 See accompanying notes.

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINING STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30,2013 (AMOUNTS IN THOUSANDS)

MISCELLANEOUS Multiple Project Projects' SCPPA Project Development Stabilization Building Total Fund Fund Fund Fund Combined Cash flows from operating activities Receipts from participants $ $ $ $ $ 569,883 Receipts from sale of oil and gas 9,809 Payments to operating managers (295,548)

Other disbursements and receipts - 20,946 Net cash flows from operating activities S30- 5.090 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net 130 16,621 1,460 Cash flows from capital financing activities Additions to plant and prepaid projects, net - (185) (51,528)

Debt interest and swap payments (1,367) - (167,428)

Proceeds from sale of bonds 243,030 Payment for defeasance of revenue bonds (226,032)

Transfer of funds from (to) escrow (56,970)

Transfer of funds from (to) Mine Reclamation Trust Fund - (1,930)

Transfer of funds from (to) other projects (795)

Principal payments on debt (12,900) -(11S,620)

Payment for bond issue costs -

S f1.2921 Net cash used for capital and related financing activities f15.062- (1851 (377,7701 Cash flows from investing activities Interest received on investments 3,283 1,124 - 11,732 Purchases of investments (16,974) (118,920) (580,344)

Proceeds from sale/maturity of investments 28,753 99,460 522,246 Net cash provided by (used for) investing activities 15,062 (18,336) - (46,366)

Net increase (decrease) in cash and cash equivalents - 130 (1,715) (185) (117,586)

Cash and cash equivalents, beginning of year 24 11,528 231 348,515

$ -$ 154 $ 9.813 $ 46 $ 230.929 Cash and cash equivalents, end of year Reconciliation of operating income (loss) to net cash provided by operating activities Operating income (loss) $ - $ - $ - $ (376) $ 136,088 Adjustments to reconcile operating income (loss) to net cash provided by operating activities Depreciation, depletion and amortization 113 145,950 Decommissioning -- 6,755 Advances for capacity and energy 3,202 Amortization of nuclear fuel 16,749 Changes in assets and liabilities Accounts receivable 6,118 Accounts payable and accruals (25,187)

Other - 263 15,415

. $ - $ - $ 305,090 Net cash provided by operating activities Cash and cash equivalents as stated in the Combined Statements of Net Position $ $ 154 $ 9,813 $ 46 $ 151,476 Cash and cash equivalents - restricted Cash and cash equivalents - unrestricted - - 79,453

$ $ 154 $ 9.813 $ 46 $ 230,929 48 See acco nanvine notes. 4

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose The Southern California Public Power Authority (the Authority or SCPPA), a public entity organized under the laws of the State of California, was formed by a Joint Powers Agreement dated as of November 1, 1980 pursuant to the Joint Exercise of Powers Act of the State of California. The Authority's participants consist of eleven municipal electric utilities and one irrigation district in the State of California. The Authority was formed for the purpose of planning, financing, developing, acquiring, constructing, operating and maintaining projects for the generation, transmission, and procurement of electric energy and natural gas for sale to its participants. The Joint Powers Agreement has a term expiring in 2030 or such later date as all bonds and notes of the Authority and the interest thereon have been paid in full or adequate provision for payments have been made.

The Authority has interests in the following projects:

GENERATION PROJECTS Palo Verde Project - On August 14, 1981, the Authority purchased a 5.91% interest in the Palo Verde Nuclear Generating Station (PVNGS), a 3,810 MW nuclear-fueled generating station near Phoenix, Arizona, a 5.44% ownership interest in the Arizona Nuclear Power Project High Voltage Switchyard (ANPP HVS), and a 6.55% share of the right to use certain portions of the Arizona Nuclear Power Project Valley Transmission System (collectively, the Palo Verde Project). Units 1, 2 and 3 of the Palo Verde Project began commercial operations in January 1986, September 1986, and January 1988, respectively.

Since inception of the ANPP HVS capital additions, new terminations, and other events have successively changed the respective ownership interests in the ANPP HVS. In FYE 2011, the PVNGS fourth transformer became the 14th termination in the ANPP HVS, and caused the Authority's proportional ownership percentage to change from 5.56% to 5.44%. This change became effective on April 1, 2011.

Units 1, 2, and 3 each operated under a 40-year Full-Power Operating License from the Nuclear Regulatory Commission (NRC), expiring in 2025, 2026, and 2027, respectively. In April 2011, after a detailed, two-year process, the NRC approved the application to extend the operating licenses for all three units for an additional 20 years, allowing Unit 1 to operate through 2045, Unit 2 through 2046, and Unit 3 through 2047.

San Juan Project - Effective July 1, 1993, the Authority purchased a 41.80% interest in Unit 3 and related common facilities of the San Juan Generating Station (SJGS) from Century Power Corporation.

Unit 3, a 497-MW unit, is one unit of a four-unit coal-fired power generating station in New Mexico.

49

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

Magnolia Power Project - The Magnolia Power Project (MAG) consists of a combined cycle natural gas-fired generating plant with a nominally rated net base capacity of 242 MW and was built on a site in Burbank, California. The plant is the first that is wholly owned by the Authority and entitlements to 100% of the capacity and energy of the Project have been sold to six of its members.

The City of Burbank, a Project participant, managed its construction and also serves as the operating agent for the Project Commercial operations began on September 22, 2005.

Gas Supply and Services Agreement - SCPPA entered into an agreement with Occidental Energy Marketing, Inc. (OEMI) beginning January 2005. This agreement is renewed each year unless notification is given by either party prior to December 31, of each year. OEMI provides 100% of the natural gas plant requirements on a daily basis, and also includes an option for the participants to bring in their own gas supply. In addition, OEMI provides gas balancing services.

• Natural Gas Transportation - SCPPA has an agreement with Southern California Gas Company (SoGas) for intrastate transmission services. The agreement took effect in January 2005 and the contract term was renewed in February 2013 and will continue for three additional years thereafter unless canceled by the Authority prior to February 1 of each year. SoGas provides transportation, storage, and balancing services of natural gas from the Southern California Border to the Magnolia Plant.

" Parts and Special Services Agreement - SCPPA entered into an 18-year agreement with General Electric International (GE) in September 2005. Initially, the agreement covered only the gas turbine, but the agreement was amended in August 2007, to include coverage for the gas generator, the steam turbine, and the steam generator. GE provides planned and unplanned maintenance, including replacement parts, based on factored fired hours.

Canyon Power Project - The Canyon Power Project (the Project) consists of a simple cycle natural gas-fired power generating plant, comprised of four combustion turbines with a combined nominally rated net base capacity of 200 MW, and auxiliary facilities, located in an industrial area of the city of Anaheim, California (Anaheim). The Project is owned by the Authority and constructed, operated, and maintained by Anaheim. The Project achieved full commercial operation in September 2011.

50

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

Apex Power Project - On March 26, 2014, the Authority acquired the Apex Power Project (the Project) pursuant to an Asset Purchase Agreement, dated as of October 17, 2013. The Project consists of a natural gas-fired, combined cycle generating facility (the "Facility"), nominally-rated at 531 MW, located in Clark County, Nevada, generator interconnection facilities, related assets and property, and interconnection and transmission contractual rights. The Facility is interconnected through a 3.13 mile 500 kV radial generation tie line owned by Nevada Power Company that connects the Facility to the Nevada Power Company's transmission system at its Harry Allen 500 kV Substation. The Los Angeles Department of Water & Power (LADWP) serves as project manager of the Project.

" Operation and Maintenance Agreement - The Facility is operated by EthosEnergy Power Operations (West), LLC (EthosEnergy), formerly Wood Group Power Operations (West), Inc.,

pursuant to an Operations and Maintenance Agreement dated February 12, 2007. Under the O&M Agreement, EthosEnergy provides all operations, routine maintenance, budget control, purchasing, billing, and reporting for the operation of the Facility, other than the maintenance provided by General Electric International ("GEl"), under a long-term service agreement.

EthosEnergy currently employs 22 people at the Facility for operation and maintenance purposes. The O&M Agreement initially between the Seller and EthosEnergy was assumed and amended by the Authority. The term of the O&M Agreement, which expires on February 12, 2016, has been extended to February 12, 2017.

• Large Generator Interconnection Agreement (LGIA) - The LGIA between Nevada Power Company and the Seller, dated July 1, 2001, provides for the interconnection of the Facility, and firm transmission service for the Facility output through two Service Agreements for Long-Term Point-to-Point Transmission Service, dated April 22, 2008 (together the "TSA"), with a point of delivery at the Mead 240 kV Substation. The term of these two agreements extends to July 30, 2023. The Authority expects to extend the term or renew these agreements prior to their expiration date or to provide for alternative transmission service from the Facility to the Mead 230 kV Substation. The Seller's obligations, under the Asset Purchase Agreement, is secured by a letter of credit in the amount of $10,000,000 which expires 18 months after the acquisition date of the Facility by the Authority and by a guaranty provided by a limited liability company for a period of 5 years following the acquisition.

" Long-Term Service Agreement - Major maintenance, including parts supply, parts repair and labor for the Facility's combustion turbine generators and the steam turbine are provided pursuant to a Long-Term Service Agreement ("LTSA") between the Seller and GEl, dated June 16, 2004. It is not currently possible to determine when the LTSA will expire, but the Authority anticipates that it will not expire prior to six years after the Facility acquisition date.

51

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

Operational Balancing Authority Agreement and Letter Agreement - The natural gas to fuel the Facility will be provided by LADWP and delivered by facilities owned by the Kern River Gas Transmission Company through an Operational Balancing Authority Agreement and Letter Agreement.

• Water Agreement - Water for the facility will be provided by Las Vegas Valley Water District pursuant to an agreement, dated June 5, 2001 and assigned to the Authority upon acquisition of the Facility. Unless extended, the Water Agreement expires on June 5, 2038.

" Transmission Service Agreements (TSAs) - Under the TSAs, Nevada Power Company currently provides transmission services to deliver the output of the Facility to the Mead 230 kV Substation. The rates, terms and conditions for such services are regulated by the Federal Energy Regulatory Commission pursuant to Nevada Power Company's open access transmission tariff. Changes to the rates are not accurately predictable and subject to numerous factors unrelated to the Apex Project.

LADWP, as the Project Manager, will administer, supervise, monitor and enforce the O&M Agreement and the LTSA in accordance with the Agency Agreement.

GREEN POWER Hoover Uprating Project - As of March 1, 1986, the Authority and six participants entered into an agreement pursuant to which each participant assigned its entitlement to Hoover Uprating capacity and associated firm energy to the Authority in return for the Authority's agreement to provide for the advancement of funds for the uprating to the United States Bureau of Reclamation (USBR) on behalf of such participants. The agreement expires on September 30, 2017.

On December 20, 2011, the Hoover Power Allocation Act, which extends the availability of Hoover Power to the existing contractors for an additional fifty years and creates a pool for new entrants, was signed into law. The participants will enter into new agreements with the federal government for the capacity and energy, effective from October 1, 2017 through September 30, 2067. Whether the Authority will play a role in the project after 2017 cannot be determined at this time.

Tieton Hydropower Project - On November 30, 2009, the Authority acquired the Tieton Hydropower Plant pursuant to an Asset Purchase Agreement, dated as of October 19, 2009. The Tieton Hydropower Project (the Project) consists of a 13.6 MW nameplate capacity "run-of-the-reservoir" hydroelectric generation facility, comprised of: a powerhouse located in Yakima County, Washington; a 21-mile 115 kV transmission line; other related assets, property, and contractual rights.

52

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

" Contractor Service Agreement - SCPPA entered into an agreement with Emanuel Services (Contractor) on January 1, 2013 to direct the operations of the Tieton Hydropower facility and to provide certain technical services with respect to the operation and maintenance of the facility. The term of the contract is for one year and was extended to June 30, 2014. On July 1, 2014 a new contract goes into effect with Energy Northwest for a term of one year and it may be extended for a period of one month to one year upon mutual agreement of the parties.

• Facilities Maintenance Agreement - SCPPA entered into an agreement with PacifiCorp to provide supervision, labor, materials, and equipment necessary to perform routine non-emergency maintenance of the facilities and routine vegetation management. The agreement started on April 28, 2010 and will continue for as long as the Interconnection agreement is in effect, unless terminated by mutual agreement.

" Small Generator Interconnection Agreement - SCPPA entered into an agreement with PacifiCorp to perform certain interconnection requests submitted under the Small Generator Interconnection Procedures. This agreement governs the terms and conditions under which SCPPA's Small Generating Facility will interconnect with PacifiCorp's Transmission System. The agreement became effective on November 30, 2009 and will remain in effect for a period of 10 years after which it will automatically renew for successive one-year periods, unless terminated by a 20-day written notice in accordance with this agreement Milford I Wind Project - On February 9, 2010, the Authority financed the prepayment of a specified supply of electricity from a wind farm located in Milford, Utah (the Facility). The Facility is a 203.5 MW nameplate capacity wind farm comprised of 97 wind turbines located near Milford, Utah, together with a 90-mile transmission line, and other related facilities. Under the related power purchase agreements by and between SCPPA and Milford Wind Corridor Phase I, LLC (the Seller), SCPPA will receive 6.7 million MW hours over a 20-year delivery term. SCPPA has also agreed to make monthly payments to the Seller for any energy delivered in each year that exceeds the guaranteed annual quantity of 338,215 MW hours. Commercial operation began on November 16, 2009.

Milford 11 Wind Energy Project - On August 25, 2011, the Authority financed the prepayment of a specified supply of energy from the Milford Wind Corridor Phase 11Project (the Milford II Project), for a delivery term of 20 years (unless terminated earlier) pursuant to a Power Purchase Agreement dated March 1, 2010. The Authority also entered into power sales agreements with LADWP and the city of Glendale (Glendale) to sell 100% of its entitlement to capacity and energy in the Facility on a "take-or-pay basis." Under a separate contract, the city of Glendale sold its entitlement share of energy to LADWP until Glendale exercises its option to repurchase its share. The Facility is a 102 MW nameplate capacity wind powered electric generating facility comprised of 68 1.5 MW wind turbines and related facilities located near Milford, Utah. The Milford II Project achieved commercial operation on May 2, 2011.

53

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

Linden Wind Energy Project - On September 15, 2010, the Authority acquired the Linden Wind Energy Project (the Project) pursuant to the terms of the Asset Purchase Agreement, dated as of June 23, 2009.

The Project is an approximately 50 MW nameplate capacity wind farm comprised of 25 wind turbines and related facilities, located in Klickitat County, Washington, developed and constructed by Northwest Wind Partners, LLC. The Authority has also entered into power sales agreements with LADWP and Glendale to sell 100% of its entitlement to capacity and energy in the Project on a "take-or-pay" basis. Through a separate layoff agreement, the City of Glendale has sold 100% of its entitlement to capacity and energy to LADWP, but remains responsible for all payments associated with its participation in the power sales agreement if LADWP fails to buy the energy pursuant to the layoff agreement

• Operation and Maintenance Service Agreement - SCPPA entered into a three-year agreement with Senvion Wind Energy Solutions ("Senvion") (formally, REpower Systems AG) in February 2012.

This agreement automatically renews for an additional two years unless either party provides written notice to the other party to cancel the contract. Senvion performs fixed fee services such as scheduled maintenances, periodic operational checks and tests, and regular preventive maintenance required on the wind turbine generators (WEC) in accordance with the maintenance manual.

Senvion also performs remote monitoring services, repair services, and services related to the availability of the WEC.

• Energy Exchange Agreement - SCPPA entered into a two-year agreement with Powerex Corp. on November 27, 2012 for delivery of energy to Powerex for shaping and moving services. The delivery term may be renewed for up to five additional one-year terms commencing on January 1 of each successive calendar year, if the parties have confirmed in writing their agreement to extend this contract not less than ninety days prior to the commencement of each renewal term.

• Balance of Plant Agreement - Cannon Power Services Company, LLC assumed responsibility for operations of the Linden Wind Energy Project from EDF Renewable Energy (formerly EnXco Service Corporation) through an agreement with SCPPA that was executed on July 9, 2013 and was effective September 3, 2013. This agreement to operate, maintain, and repair the Wind Plant will continue for a period of three years and will automatically be extended for successive one year periods unless either party provides written notice to terminate the contract Windy Point/Windy Flats Project - On September 9, 2010, the Authority financed the purchase of a supply of energy from the Windy Point/Windy Flats Project (the Project) for an initial delivery term of 20 years, pursuant to the terms of a power purchase agreement, dated June 24, 2009. The Authority also entered into power sales agreements with LADWP and the city of Glendale to sell 100% of its entitlement to capacity and energy in the Project on a "take-or-pay" basis. Through a separate layoff agreement, the City of Glendale sold 100% of its entitlement to capacity and energy to LADWP, but remains responsible for all payments associated with its participation in the power sales agreement if LADWP fails to buy the energy pursuant to the layoff agreement.

54

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

The Project is a facility with a 262.2 MW nameplate capacity wind farm comprised of 114 wind turbines located in the Columbia Hills area of Klickitat County, Washington near the city of Goldendale. The Project is owned by Windy Flats Partners, LLC, a limited liability company organized and existing under the laws of the State of Delaware. The initial delivery term began on the commercial operation date of the first of two phases of the facility. The first phase commenced operations on January 25, 2010 and the second phase on March 1, 2010.

TRANSMISSION PROJECTS Southern Transmission System Project - On May 1, 1983, the Authority entered into an agreement with the Intermountain Power Agency (IPA), to defray all the costs of acquisition and construction of the Southern Transmission System Project (STS), which provides for the transmission of energy between the Southern California and the Rocky Mountain regional markets, including long-term renewable resources such as Milford I Wind and Milford II Wind, from the Intermountain Generating Station located in Utah to Southern California. STS commenced commercial operations in July 1986.

Construction to upgrade two AC/DC converter stations and increase their combined rating from 1,920 MW to 2,400 MW was completed in May 2011. The LADWP, a member of the Authority, serves as project manager and operating agent of the Intermountain Power Project (IPP).

Mead-Phoenix and Mead-Adelanto Projects - As of August 4, 1992, the Authority entered into an agreement to acquire an interest in the Mead-Phoenix Project (Mead-Phoenix), a transmission line extending between the Westwing substation in Arizona and the Marketplace substation in Nevada. The agreement provides the Authority with an 18.31% interest in the Westwing-Mead project component, a 17.76% interest in the Mead Substation project component, and a 22.41% interest in the Mead-Marketplace project component.

As of August 4, 1992, the Authority also entered into an agreement to acquire a 67.92% interest in the Mead-Adelanto Project (Mead-Adelanto), a transmission line extending between the Adelanto substation in Southern California and the Marketplace substation in Nevada. Funding for these projects was provided by a transfer of funds from the Multiple Project Fund and commercial operations commenced in April 1996. LADWP serves as project manager and operating agent of Mead-Adelanto.

55

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

NATURAL GAS PROJECTS Natural Gas Pinedale Project - On July 1, 2005, the Authority, together with LADWP and Turlock Irrigation District (TID), acquired 42.5% of an undivided working interest in three natural gas leases located in the Pinedale Anticline region of the State of Wyoming. The Authority's individual share in these interests equals 14.9%. The purchase includes 38 operating oil and gas wells and associated lateral pipelines, equipment, permits, rights of way, and easements used in production. The natural gas field production is expected to increase for several more years as additional capital is invested on drilling new wells and then decline over a life expectancy greater than 30 years.

• Joint Operating Agreement (JOA) - In July 2005, SCPPA's purchase of the natural gas reserve interests at Pinedale, Wyoming (Pinedale) included an underlying long-term JOA with the operator, Ultra Resources, Inc. SCPPA pays the operator for SCPPA's share of both operating and drilling/capital expenses on a monthly basis.

• Gathering and processing agreements - SCPPA's purchase of Pinedale included underlying agreements with Jonah Gas Gathering Company, Questar Gas Management Company, and Western Gas Resources, Inc. for gathering and processing of the natural gas.

Natural Gas Barnett Project - Natural gas resources in the Barnett shale geological formation in Texas were acquired from Collins and Young Holding, L.LP (C&Y) for a total of $84 million. The acquisition settled on October 26, 2006 and was completed on December 7, 2006 when the participants, together with TID, exercised their option to purchase additional resources from C&Y.

joint Operating Agreement (JOA) - In October 2006, SCPPA's purchase of the natural gas reserve interests in Barnett, TX (Barnett) included an underlying long-term JOA with the operator, Devon Energy Production Company, L.P. SCPPA pays the operator for SCPPA's share of both operating and drilling/capital expenses on a monthly basis.

Prepaid Natural Gas Project No. 1 - On October 11, 2007, the Authority made a one-time prepayment of $481 million to acquire the right to receive approximately 135 billion cubic feet of natural gas from J.Aron & Company (J.Aron) to be delivered over a 30-year term, beginning July 1, 2008. On October 3, 2007, prior to the acquisition of the prepaid gas supply, the Authority entered into five separate Prepaid Natural Gas Sales Agreements (the Gas Sales Agreements) with J.Aron and simultaneously, five Prepaid Natural Gas Supply Agreements (the Gas Supply Contracts) in which the Authority sold its interest in the natural gas, on a "take-and-pay" basis, to the cities of Anaheim, Burbank, Colton, Glendale, and Pasadena (the Project No. 1 Participants). Through the Gas Supply Contracts, SCPPA has provided for the sale to the Project Participants, on a pay-as-you-go basis, of all of the natural gas to be delivered to SCPPA pursuant to the Gas Sales Agreements.

56

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

" On October 22, 2009, the Prepaid Natural Gas Sales Agreements and certain other agreements were restructured to reduce risk, provide an acceleration of a portion of the long-term savings, reduce the remaining volumes of gas to be delivered from 135 billion to 90 billion cubic feet, and shorten the term of the agreements from 30 years to 27 years. As a result of the restructuring, the Natural Gas contracts will now expire in 2035 and $165.5 million principal of the 2007 Natural Gas Project Bonds were terminated (see Note 6).

" Under the Gas Supply Contracts, the approximate average Daily Quantity of gas to be purchased by each Project Participant is as follows:

Average Daily Quantity (1)

Revised Original Participant Project Participant Volumes Volumes Percentage (%)

City of Anaheim 1,467 2,000 16.5%

City of Burbank 2,924 4,000 33.0%

City of Colton 1,007 1,375 11.0%

City of Glendale 2,015 2,750 23.0%

City of Pasadena 1,464 2,000 16.5%

Total 8,877 12,125 100.0%

(1) The Average Daily Quantity is in MMBtu and is calculated over the term of the applicable Gas Supply Contracts. The contracts were restructured and volumes revised in October 2009.

57

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

Participant ownership interests - The Authority's participants may elect to participate in the projects.

As of June 30, 2014, the members have the following participation percentages in the Authority's operating projects:

GENERATION TRANSMISSION Trans-Magnolia Canyon Apex mission Mead- Mead-Palo Verde San Juan Power Power Power System Phoenix Adelanto Participants Project Project Project Project Project Project Project Project City of Los Angeles 67.0% - 100.0% 59.5% 24.8% 35.7%

City of Anaheim - 38.0% 100% - 17.6% 24.2% 13.5%

City of Riverside 5.4% - - 10.2% 4.0% 13.5%

Imperial Irrigation District 6.5% 51.0% -

City of Vernon 4.9% - - -

City of Azusa 1.0% 14.7% 1.0% 2.2%

City of Banning 1.0% 9.8% 1.0% 1.3%

City of Colton 1.0% 14.7% 4.2% - 1.0% 2.6%

City of Burbank 4.4% - 31.0% 4.5% 15.4% 11.5%

City of Glendale 4.4% 9.8% 16.5% 2.3% 14.8% 11.1%

City of Cerritos 4.2% - -

City of Pasadena 4.4% - 6.1% 5.9% 13.8% 8.6%

100.0%

100.0% 100.0% 100.0% 100.0%

i 100.0%

_=

100.0% 100,0%

GREEN POWER NATURAL GAS rrepanu Hoover Tieton Linden Windy Natural Uprating Hydro- Milford I Milford II Wind Point Pinedale Barnett Gas Participants Project power Wind Wind Energy Project Project Project Project City of Los Angeles 92.5% 95.1% 90.0% 92.4% - - -

City of Anaheim 42.6% - - - - 35.7% 45.4% 16.5%

City of Riverside 31.9% - - -

Imperial Irrigation District City of Vernon City of Azusa 4.2%

City of Banning 2.1%

City of Colton 3.2% - 7.1% 9.1% 11.0%

City of Burbank 16.0% 50.0% 5.0% 14.3% 27.3% 33.0%

City of Glendale - 50.0% 4.9% 10.0% 7.6% 28.6% 23.0%

City of Cerritos City of Pasadena 2.5% 14.3% 18.2% 16.5%

100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

The Authority has entered into power sales, natural gas sales, and transmission service agreements 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.

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

The contracts expire as follows:

Palo Verde Project 2030 San Juan Project 2030 Magnolia Power Project 2036 Canyon Power Project 2040 Apex Power Project 2038 Hoover Uprating Project 2018 Tieton Hydropower Project 2040 Milford I Wind Project 2030 Milford II Wind Project 2031 Linden Wind Energy Project 2035 Windy Point Project 2030 Southern Transmission System Project 2027 Mead-Phoenix Project 2030 Mead-Adelanto Project 2030 Natural Gas Pinedale Project 2040 Natural Gas Barnett Project 2040 Prepaid Natural Gas Project 2038 Ormat Geothermal Energy Project 2031 Pebble Springs Wind Project 2025 MWD Small Hydro Project 2023 Ameresco Chiquita Landfill Gas Project 2030 Don A Campbell Wild Rose Project 2033 Copper Mountain Solar 3 Project 2040 The Authority's interests or entitlements in natural gas, generation, and transmission projects are jointly owned with other utilities, except for the Magnolia Power Project, Canyon Power Project, Apex Power Project, Tieton Hydropower Project, and the Linden Wind Energy Project, which are wholly owned by the Authority. Under these arrangements, a participating member has an undivided interest in a utility plant and is responsible for its proportionate share of the costs of construction and operation and is entitled to its proportionate share of the energy, available transmission capacity, or natural gas produced. Each joint plant participant, including the Authority, is responsible for financing its share of construction and operating costs. The financial statements reflect the Authority's interest in each jointly owned project as well as the projects that it owns. Additionally, the Authority's share of expenses for each project is included in the statements of revenues, expenses, and changes in net position as part of operations and maintenance expenses.

59

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

POWER PURCHASE AGREEMENTS Ormat Geothermal Energy Project - The Authority entered into long-term power purchase agreements in December 2005 with divisions of Ormat Technologies, Inc. for up to 20 MW of electric generation. The Project started delivery of approximately 5 MW in January 2006 from geothermal energy facilities located in Heber, California and the agreements were amended to allow for excess capacity in May 2008. The city of Anaheim acts as the scheduling coordinator on behalf of the project participants. The term of the contract is 25 years.

MWD Small Hydro Project - Consists of a power purchase agreement for the output from four small hydroelectric plants on the MWD system in Southern California, having a total nameplate capacity of 17.04 MW, and a historical output of 40,130 MWH per year. Transmission is accomplished through the California Independent System Operator, with the city of Anaheim acting as scheduler. The term of the contract is 15 years and 2 months, expiring December 31, 2023. Operations began on November 1, 2008.

Pebble Springs Wind Project - In December 2007, the Authority entered into a power purchase agreement for the facility output of a wind project with 98.7 MW, located in Gilliam County, Oregon.

SCPPA along with LADWP, Burbank, and Glendale are now scheduling the energy through transmission agreements which bring this renewable energy from the project substation to the project participants.

The term of the Project is 18 years with a right of first offer to potentially purchase the entire project after the 10th contract year. Operations formally began on January 31, 2009.

Ameresco Chiquita Energy Project - In March 2004, SCPPA entered into a power purchase agreement with Ameresco Chiquita Energy LLC, subsequently amended in September 2006, for 100% of the electric generation from a landfill gas to energy facility located at the landfill site in Valencia, California (Ameresco Landfill Gas to Energy Project). The SCPPA participants in the project include the cities of Burbank and Pasadena. This project will initially be for 10 MW with the right of first refusal on any increase in output. Operations began in November 2010. The term of the contract is 20 years from the commercial operation date.

Don A. Campbell/Wild Rose Geothermal Energy Project - On December 31, 2012 the Authority entered into a power purchase agreement with Ormat Nevada, Inc. to purchase renewable geothermal energy from the Don A.Campbell/Wild Rose Facility (the "Facility") beginning December 31, 2013, for a 20-year term at a fixed price of $99/MW. The Facility is a geothermal power generating facility with a 16.2 MW nameplate capacity and a 95 percent capacity factor located in Mineral County;Nevada. The commercial operating date was December 31, 2013 but early delivery of energy began in November 2013. The two participants are LADWP and the city of Burbank. LADWP acts as project manager and has balancing authority at the point of delivery of energy at the Mead 230kV Substation in Southern Nevada.

Electricity from the Project will be transmitted through Nevada Energy's transmission system that includes the new 500 kV One Nevada Transmission Line.

60

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

Copper Mountain Solar 3 Project - On August 31, 2012, SCPPA entered into a power purchase agreement with Copper Mountain Solar 3, LLC to purchase certain renewable energy and associated environmental attributes. Although the facility is still under construction, delivery of test energy began in May 2014. Production is expected to start with about 5 MW of test energy and to ramp up gradually to 250 MW capacity between May 2014 and March 2015.

The Authority has entered into power purchase agreements with project participants as follows. These agreements are substantially "take-and-pay" contracts where there may be other obligations not associated with the delivery of energy.

Participant Ownership Interests Power Purchase Agreements Geothermal Chiquita Don A. Campbell Energy Pebble Springs MWD Small Hydro Landfill Wild Rose Copper Mountain Participants Project Wind Project Project Gas Project Geothermal Proiect Solar 3 Project Capacity 17.00 MW 98.70 MW 17.04 MW 10.00 MW 16.00 MW 250.00 MW City of Los Angeles - 69.6% 84.6% 84.0%

City of Anaheim 60.0% - 56.4%

City of Azusa - -21.8%

City of Banning 10.0% /

City of Colton 21.8%

City of Burbank 10.1% 16.7% 15.4% 16.0%

City of Glendale 15.0% 20.3%

City of Pasadena 15.0% 83.3%

100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

Contract expires 2031 2025 2023 2030 2033 2040 MISCELLANEOUS FUNDS Multiple Project Fund - During fiscal year 1990, the Authority issued Multiple Project Revenue Bonds for net proceeds of approximately $600 million to provide funds to finance costs of construction and acquisition of ownership interests or capacity rights in one or more, then unspecified, projects for the generation or transmission of electric energy. Certain of these funds were used to finance the Authority's interests in Mead-Phoenix and Mead-Adelanto. Final maturity of the 1989 Multiple Project Bonds occurred on July 1, 2013 leaving a Surplus Amount of approximately $6.4 million and $18.4 million available to the SCPPA Mead-Phoenix (MP) and Mead-Adelanto (MA) project participants, respectively.

The Surplus Amount is the result of the savings obtained from the partial refunding within five years of the original issue of the 1989 Multiple Project Bonds by the MP and MA 1994 Series A Project Bonds.

The partial refunding triggered a recalculation of the arbitrage yield, resulting in a higher arbitrage yield which reduced the rebate liability of the Authority and resulted in additional savings over the remaining life of the 1989 Multiple Project Bonds.

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 1 - Organization and Purpose (continued)

At the time of the refunding, the Authority determined that these Surplus Amounts benefited and should be transferred to the MP and MA Project Participants after final maturity of the 1989 Multiple Project Bonds. The Multiple Project Fund was closed after the transfer was completed during the year ended June 30, 2014.

Project Development Fund - Holds funds related to projects in the development phase. The funds related to the acquisition and renovation of the SCPPA Office Building located in the city of Glendora were transferred to the SCPPA Office Building Fund in 2012.

Projects' Stabilization Fund - In fiscal year 1997, the Authority authorized the creation of a Projects' Stabilization Fund. Deposits may be made into the fund from budget under-runs, after authorization of individual participants, and by direct contributions from the participants. Participants have discretion over the use of their deposits within SCPPA project purposes. This fund is not a project-related fund; therefore, it is not governed by any project Indenture of Trust. The members participate in the Projects' Stabilization Fund by making deposits to the fund at their discretion.

SCPPA Building Fund - In June 2011, the Authority acquired an 11,500 sq. ft. building located in the City of Glendora to be used as SCPPA office facilities. Acquisition and construction costs were financed by contributions from SCPPA members and the building was put into service during fiscal year 2012. All costs associated with the management, administration, and ongoing operations of the SCPPA Office Building are deemed to be SCPPA overhead costs and will be budgeted and paid in accordance with the projects annual budgets pursuant to SCPPA's traditional budgetary process. On July 18, 2013, the SCPPA Board authorized the installation of Solar Voltaic Equipment and Carports at the SCPPA Glendora Office Building. The estimated cost was financed by the SCPPA Members in accordance with their ownership interests in the SCPPA Building. (See Note 3)

Note 2 - Summary of Significant Accounting Policies Basis of accounting and presentation - The combined and individual financial statements of the Authority are prepared under the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America issued by the Governmental Accounting Standards Board (GASB) applicable to governmental entities that use proprietary fund accounting. Revenues are recognized when earned and expenses are recognized when incurred. The format of the Statement of Net Position follows the inverted approach which is consistent with the Federal Energy Regulatory Commission (FERC).

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 2 - Summary of Significant Accounting Policies (continued)

In June 2012, the GASB issued Statement No. 63, FinancialReporting of Deferred Outflows of Resources, Deferred Inflows of Resources, and Net Position, effective for financial statement for periods beginning after December 15, 2011. The balance sheets, statements of revenues, expenses, and net assets, and statements of cash flows have been revised in the current year to reflect the implementation of this Statement In addition to assets and liabilities, the combined financial statements will include deferred outflows and deferred inflows or resources, and will report net position instead of net assets (deficit).

Other than the change in presentation, there was no impact to the financial statements as a result of this implementation.

Net position: The Authority's net position is classified as follows:

" Net investment in capital assets - This component of net position consists of capital assets, (b) net of accumulated depreciation, reduced by the outstanding balances of any bonds, other borrowings, and advances from participants that are attributable to the acquisition, construction, or improvement of those assets. If there are significant unspent related debt proceeds at year-end, the portion of the debt attributable to the unspent proceeds is not included in the calculation of net investment in capital assets. Rather, that portion of the debt is included in the same net position component as the unspent proceeds.

• Restricted - This component consists of net position on which constraints are placed as to their use.

Constraints include those imposed by creditors (such as through debt covenants), contributors, or laws or regulation of other governments or constraints imposed by law through constitutional provisions or through enabling legislation.

" Unrestricted - This component of net position consists of net position that does not meet the definition of "restricted" or "net investment in capital assets."

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

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 2 - Summary of Significant Accounting Policies (continued)

Utility plant - The Authority's share of construction and betterment costs, natural gas reserves, intangibles, and nuclear fuel associated with PVNGS, STS, Mead-Phoenix, Mead-Adelanto, SJGS, Magnolia Power Project, the Natural Gas Pinedale Project and the Natural Gas Barnett Project (together the Natural Gas Projects) Canyon Power, Tieton Hydropower, Linden Wind Energy, and the Apex Power Projects are included as utility plant and recorded at cost Utility plant also includes the SCPPA Building.

Costs include labor, materials, capitalized interest costs on funds used in construction, and allocated indirect charges such as engineering, supervision, transportation and construction equipment, retirement plan contributions, health care costs, and certain administrative and general expenses. The costs of routine maintenance, repairs, and minor replacements incurred to maintain the plant in operating condition are charged to the appropriate operations and maintenance expense accounts in the period incurred. The original cost of property retired, net of removal and salvage costs, is charged to accumulated depreciation.

Depreciation expense is computed using the straight-line method based on the estimated service lives, principally 55 years for PVNGS, STS, Mead-Phoenix and Mead-Adelanto; 30 years for Magnolia and Canyon Power Project; 37 years for SJGS; 50 years for the Tieton Hydropower Project; 25 years for Linden Wind Energy Project; 24 Years for the Apex Power Project; and 35 years for the SCPPA Building Fund.

Natural gas reserve depletion - Depletion expense for the Natural Gas Projects is computed using the unit of production method based on the future production of the proved developed producing wells, estimated at 28.2 years for the Natural Gas Pinedale Project and 50 years for the Natural Gas Barnett Project. The estimate is based on site specific studies prepared by independent consultants as of December 2012 for both projects. The depletion rate for the Natural Gas Pinedale Project was

$3.35/MMBtu and $3.28/MMBtu; and the estimated total net revenue volume was 15,251,000 MMBtu and 16,043,427 MMBtu, for fiscal years 2014 and 2013, respectively. The depletion rate for the Natural Gas Barnett Project was $3.47/MMBtu and $3.15/MMBtu; and the estimated total net revenue volume was 16,689,563 MMBtu and 17,583,585 MMBtu, for fiscal years ended June 30, 2014 and 2013, respectively.

Nuclear fuel - Nuclear fuel is amortized and charged to expense 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 entity with nuclear operations, including the participants in PVNGS, $1 per MW hour of nuclear generation. The Authority records this charge as a current year expense. See Note 11 for information about spent nuclear fuel disposal.

64

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 2 - Summary of Significant Accounting Policies (continued)

Nuclear decommissioning - Decommissioning of PVNGS is expected to commence subsequent to the year 2026. The total cost to decommission the Authority's interest in PVNGS is estimated to be $137.5 million in 2011 dollars ($262.3 million in 2022 dollars, assuming a 6% estimated annual inflation rate).

This estimate is based on an updated site specific study prepared by an independent consultant in 2010.

The Authority is providing for its share of the estimated future decommissioning costs over the remaining life of the nuclear power plant through annual charges to expense, which amounted to $2.4 million in both fiscal years 2014 and 2013. The decommissioning liability is included as a component of accumulated depreciation and was $242.7 million and $240.3 million at June 30, 2014 and 2013, respectively.

The Authority contributes to external trusts set up in accordance with the Arizona Nuclear Power Plant participation agreement and Nuclear Regulatory Commission requirements. As of June 30, 2014, decommissioning funds totaled approximately $168.0 million, including approximately $0.4 million of interest receivable.

Asset retirement obligation - Demolition of SJGS is projected to commence subsequent to the year 2030. Based upon the study performed by an independent engineering firm, the Authority's share of the estimated demolition costs is $47.4 million in 2008 dollars. The Authority is providing for its share of the estimated future demolition costs over the remaining life of the power plant through annual charges to expense of $1.5 million. The demolition liability is included as a component of accumulated depreciation and totaled $55.9 million and $54.4 million at June 30, 2014 and 2013, respectively.

As of June 30, 2014, the Authority has not billed participants for the cost of demolition nor has it established a demolition fund.

San Juan reclamation liability- The Authority has certain obligations relating to its ownership interests in the SJGS Unit 3, to participate in the development of plans and arrangements for the eventual reclamation of the San Juan Coal Mine after the expiration in December 2017 of the Underground Coal Sales Agreement dated August 31, 2001. The Authority is providing for its share of the estimated future reclamation costs through annual charges to expense, which initially amounted to

$1.9 million at December 31, 2012. The reclamation liability is included as a component of accumulated reclamation costs and was $4.5 million at June 30, 2014.

The Authority contributes to a Reclamation Trust Fund set up in accordance with the Mine Reclamation Trust Funds Agreement among the San Juan Participants, dated June 1, 2012. As of June 30, 2014, reclamation funds totaled $2.4 million.

65

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 2 - Summary of Significant Accounting Policies (continued)

Investments - Investments include United States government and governmental agency securities, guaranteed investment contracts, medium term notes, and money market accounts. These investments are reported at fair value and changes in unrealized gains and losses are recorded in the statement of revenues, expenses, and changes in net position with the exception of the guaranteed investment contracts which are recorded at amortized cost Gains and losses realized on the sale of investments are generally determined using the specific identification method.

The Bond Indentures for the Projects and the Multiple Project Fund require the use of trust funds to account for the Authority's receipts and disbursements. Cash and investments held in these funds are restricted to specific purposes as stipulated in the Bond Indentures.

Accounts receivable - Accounts receivable consists primarily of participant receivables. As such no allowance is deemed necessary.

Prepaid and other assets - SCPPA entered into a prepaid gas contract with a supplier for a 30-year gas supply at a fixed discount and simultaneously entered into a contract with each of the project participants for the delivery of natural gas. The prepaid contracts were subsequently restructured and the term of the agreements were shortened to 27 years. SCPPA has also entered into 20-year term prepaid contracts for all of the energy generated by the Milford I Wind, Milford II Wind, and the Windy Point/Windy Flats Facilities, with corresponding power sales contracts with each project participant.

(See Note 1)

Advances for capacity and energy - Advance payments to the United States Bureau of Reclamation for the uprating of the 17 generators at the Hoover Power Plant are included in advances for capacity and energy. These advances are being reduced by the principal portion of the credits on billings to the Authority for energy and capacity. The current portion of these advances is recorded under Prepaid and Other Assets in the Current Assets Section of the Combined Statements of Net Position.

Advance to IPA - Advance to IPA consists of cash transferred to IPA for reserve, contingency, and self-insurance funding.

Unamortized premiums, discounts, debt expenses, and losses on refunding - In March 2012, the GASB issued Statement No. 65, Items previously Reported as Assets and Liabilities(GASB 65) effective for financial statements for periods beginning after December 15, 2012. GASB 65 reclassifies losses on refunding debt as deferred outflows of resources instead of a contra-liability as it was reported previously. Losses or gains on refunding related to bonds redeemed by refunding bonds are still amortized over the shorter of the life of the refunding bonds, or the remaining term of bonds in accordance with GASB Statement No. 23, Accounting and Financial Reporting for Refundings of Debt Reported by ProprietaryActivities.

66

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 2 - Summary of Significant Accounting Policies (continued)

Unamortized premiums, discounts, and debt expenses were recorded as assets and amortized over the life of the related debt issue. GASB 65 now requires that all debt issuance costs, except for any portion related to prepaid insurance costs, be recognized as an expense in the period incurred. Prior year balances have been restated to conform with 2014 presentation. (See Note 12)

Cash and cash equivalents - Cash and cash equivalents include cash and investments with original maturities of 90 days or less.

Deferred outflow and inflow of resources - Effective July 1, 2013, the Authority adopted GASB 65 and reclassified loss or gain on refunding bonds, which were previously classified as a component of long-term debt, as Deferred outflows or Deferred inflows of resources, respectively. Prior year balances have been reclassified to conform to the 2014 presentation. (See Note 12)

In addition, the accumulated changes in the fair value of effective hedging derivative instruments are reported as deferred outflow of resources. Under hedge accounting, the changes in the fair value of an effective hedging derivative instrument, in asset or liability positions, are reported as a deferred inflow of resources or deferred outflow of resources, respectively, on the Statements of Net Position.

Materials and supplies - Materials and supplies consist primarily of items for construction and maintenance of plant assets and are stated at the lower of cost or market Arbitrage rebate and yield restrictions - The unused proceeds from the issuance of tax-exempt debt have been invested in taxable financial instruments. The excess of earnings on investments, if any, over the amount that would have been earned if the investments had a yield equal to the bond yield or yield restricted rate, is payable to the IRS within five years of the date of the bond offering and each consecutive five years thereafter until final maturity of the related bonds.

Final maturity of the 1989 Multiple Project Bonds occurred on July 1, 2013 leaving a Surplus Amount of approximately $6.4 million and $18.4 million available to the SCPPA Mead-Phoenix and Mead-Adelanto project participants, respectively. The Surplus Amount was the result of the cumulative savings from refunding of the 1989 Multiple Project Bonds by the 1994 MA and MP Bonds. The partial refunding within five years of the original issuance triggered a recalculation of the arbitrage yield, reducing the Multiple Project Fund's rebate liability and resulted in additional savings over the remaining life of the 1989 Multiple Project Bonds. Recorded arbitrage rebate and yield restriction liabilities as of June 30, 2014, were $31,000 for Mead-Phoenix and $27,000 for Mead-Adelanto.

Revenues - Revenues consist of billings to participants for the sales of electric energy, natural gas, and transmission service in accordance with the participation agreements. Generally, revenues are fixed at a level to recover all operating and any debt service costs over the commercial life of the property.

67

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 2 - Summary of Significant Accounting Policies (continued)

In September 1998, the Palo Verde participants approved a resolution authorizing the Authority to bill the participants an additional $65 million annually through June 30, 2004 to pay for increased debt service costs as a result of a refunding completed in October 1997. In addition, the participants resolved to transfer any over billings, renewal and replacement excess funds, or surplus amounts through June 30, 2004 into the Palo Verde reserve account On November 20, 2003, the Authority adopted a resolution to utilize the amounts on deposit in the reserve accounts to pay a portion of the operating and maintenance expenses of the Palo Verde Project starting July 1, 2004. Funds held in the reserve account as a result of this resolution totaled $21.2 million and $27.6 million as of June 30, 2014 and 2013, respectively.

Transportation costs - As a result of the sales and purchases agreements for natural gas entered into by SCPPA, the participants receive less volume than processed incurring embedded transportation costs.

These costs are recorded as participants' revenue and expense to the Natural Gas Pinedale Project At June 30, 2014 and 2013, transportation costs were approximately $258 thousand and $445 thousand, respectively, for the Natural Gas Pinedale Project.

Non-exchange contribution - Each participant of the Magnolia Power Plant is responsible for its own share of natural gas. They may elect to bring fuel to the plant or purchase fuel from Occidental Energy Marketing, Inc. (OEMI). OEMI computes the daily imbalances of fuel volume per participant using the daily consumption data that the operating manager provides. Monthly, actual fuel burnt is reported together with the daily imbalances, participants' in kind contribution, and fuel purchases from OEMI.

Non-exchange contributions are valued at fair market value and recorded as participant revenue and fuel expense to the Magnolia Power Project SCPPA values the participants' fuel contribution using monthly average pricing from the Project's OEMI fuel purchases. During the fiscal years ended June 30, 2014 and 2013 the participants' contribution in kind was approximately 11.0 million MMBtu and 5.8 million MMBtu and was valued at approximately $53.7 million and $20.9 million, respectively.

Build America Bonds (BABs) - These are taxable municipal bonds that were created under the American Recovery and Reinvestment Act of 2009, and carry special tax credits and federal subsidies for either the bond issuer or the bondholder. BABs provide for a subsidy payment from the Department of the Treasury to be paid directly to the issuer (Direct Payment) or the bondholder (Tax Credit BABs) in an amount equal to 35% of the bond's interest On June 9, 2010, SCPPA issued $191 million of Canyon Power 2010 Series B, Direct Payment BABs. $41.5 million of the Linden Wind 2010 Series B, Direct Payment BABs, were issued on September 28, 2010.

The budget sequestration or automatic spending cuts of the United States Government that went into effect in 2013 resulted in a 7.2% decrease of the BABs subsidies received by the Authority for the related bonds.

68

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 3 - Utility Plant At June 30, 2014, Utility Plant, net consisted of the following (amounts in thousands):

lone 30,2014

• DATINM Magnolia Canyon Hoover Linden Palo Verde San Juan Power Power Apex Power Uprating Tieton Hydro- Wind Proect Project Project Project Project Project power Energy Utility plant Production $ 713,228 $ 258,334 $ 286,103 $ 252,426 $ 288,841 $ $ 47,799 $ 123.082 Transmission 16,639 15.247 31,853 - 23,431 General 3,564 6,802 15,495 488 4,956 21 11 Natural gas reserves - - -

733,431 26S,136 316,845 284,767 293,797 21 47,810 146,513 Lessaccumulated depreciation 730,940 193,570 98,148 26,632 3,015 21 6686 22,043 2.491 71,566 218,697 258,135 290,782 41,124 124,470 Construction work in progress 28,037 3,895 971 81 Nuclear fuel, at amortized cost 42-454 . - -

Net utility plant S 72982 S 75461r, $ 219668 $ 258135 S 290782 S - $ 41 205 S 124470 Southern Transmission Mead-System Mead- Phoenix Adelanto Plnedale SCPPA Building Project Project Project Project Barnett Project Fund Total Utility plant Production $ - $ $ $ - 1,969,813 Transmission 770,498 54,825 173,101 1,085,594 General 44,400 2,730 473 4,090 4,386 87,416 Natural gas reserves - 73,126 84,117 - 157243 814,898 57,555 173,574 77.216 84,117 4,386 3.300,066 Less accumulated depreciation 553.131 Z6,477 82,348 28,538 30,242 234 1,802,025 261,767 31,078 91,226 48,678 53,875 4,152 1.498,041 Construction work in progress 209 69 365 72 33,699 Nuclear fuel, at amnortized cost - 42,454 Netotilityplant $ 261.767 $ 31287 $ 91226 , 48747 $ 54240 4224 , 1574194 69

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 3 - Utility Plant (continued)

In June, 2011, the Authority made a one-time payment to acquire an 11,500 sq. ft. building located in the city of Glendora to be used as SCPPA office facilities. The building was renovated and put into service during fiscal year 2012. Acquisition and construction costs were financed by contributions from SCPPA members. On July 18, 2013, the SCPPA Board authorized the installation of Solar Voltaic Equipment and Carports at the SCPPA Glendora Office Building. The estimated cost was financed by the SCPPA Members in accordance with their ownership interests in the SCPPA Building. Construction is currently underway.

(See Note 1)

At June 30, 2013 Utility Plant, net consisted of the following (amounts in thousands):

June 30, 2013 CI'eNFOl'gATIflI, tuRcN PAWRtA Palo Magnolia Canyon Hoover Verde San Juan Power Power Uprating Tieton Hydro- Linden Wind Project Project Project Project Project Power Enerfy Utility plant Production $ 707,277 $ 250,924 $ 284 434 $ 245,397 $ $ 34,509 S 123,082 Transmission 16,158 - 35,247 31,853 13,290 23,431 General 3,547 7,039 15,422 488 21 11 Natural gas reserves 726,982 257,963 315,103 277,738 21 47,810 146,513 Less accumulated depreciation 711,118 180414 86,710 17,051 21 5,221 16,230 15,864 77,549 228,393 260,687 42,589 130,283 Constru-tton work in progress 24,263 7:412 2,002 - -

Nuclear fuel, at amortized cost 44783 .-

Net utility plant $ 84,910 $ - $ 42,589 $_ 130,283 TRANSMISSION NATURALGAS OTHERS Southern Transmission Mead-System Mead- Phoenix Adelanto Pinedale SCPPA Projec Project Project Project Barnett Project Buildinp Fund Total Utility plant Production - $ - - - $ $ 1,645,623 Transmission 769,578 54,825 173,101 1,097,483 General 4S,319 2,730 473 3,985 4,386 83,421 Natural gas reserves 72,162 78,673 - 150,835 814,897 57,555 173.S74 76,147 78.673 4.386 2,977,362 Less accumulated depreciation 530,376 24,9S3 77,826 23,492 26,173 122 1,699,707 284,521 32,602 95,748 52,655 52,500 4,264 1,277,655 Construction work In progress - 144 1,069 5,444 40,334 Nuclear fuel, at amortized cost 44,783 Net utility plant $ 284,521 $ 32,746 $ 95,748 53.724 $ 57,944 $ 4,264 $ 1 362772 70

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 3 - Utility Plant (continued)

Asummary of changes in Utility Plant follows (amounts in thousands):

Balance Balance July 1, 2013 Additions Disposals Transfers June 30, 2014 Nondepreciable utility plant Land $ 44,416 $ 4,856 $ - $ - $ 49,272 Construction work in progress 33,821 16,586 (34) (17,108) 33,265 Construction work in progress - gas 6,513 434 (6,513) 434 Nuclear fuel* 44,783 11,820 (14,149) - 42,454 Total nondepreciable utility plant 129,533 33,696 (14,183) (23,621) 125,425 Depreciable utility plant Production Nuclear generation (Palo Verde Project) 706,362 (509) (3,711) 10,172 712,314 Coal-fired plant (San Juan Unit 3 Project) 250,923 5,140 2,270 1,669 260,002 Gas-fired plant 529,829 295,870 - - 825,699 Green power 156,419 - - 156,419 Transmission 1,056,717 654 (172) - 1,057,199 General 79,131 188 (309) 73 79,083 Natural gas reserves 153,565 - - 6,513 160,078 Total depreciable utility plant 2,932,946 301,343 (1,922) 18,427 3,250,794 Less accumulated depreciation (1,699,707) (103,338) 1,020 - (1,802,025)

Total utility plant, net $ 1,362,772 $ 231,701 $ (15,085) $ (5,194) $ 1,574,194

• Nuclearfueldisposals representamortization.

Note 4 - Investments The Authority's investment function operates within a legal framework established by Sections 6509.5 and 53600 et. seq. of the California Government Code, Indentures of Trust, and instruments governing financial arrangements entered into by the Authority to finance and operate Projects and the Authority's Investment Policy.

Guaranteed investment contracts (GICs) are contracts that guarantee the owner principal repayment and a specified interest rate for a predetermined period of time. GICs are typically issued by insurance companies and marketed to institutions that qualify for favorable tax status under federal laws. These types of securities provide institutions with guaranteed returns. GICs are negotiated on a case-by-case basis.

71

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 4 - Investments (continued)

Based on SCPPA's Investment Policy, certain vehicles such as GICs, flexible repurchase agreements or forward debt service agreements, may be entered into only upon approval of the SCPPA Board. In addition, eligible securities and general limitations are derived from each Project's Indenture of Trust, the Government Code and SCPPA's evolving investment practices.

The operative Indentures of Trust in which securities are authorized for investment purposes relate to the Palo Verde Project Bonds, the Southern Transmission System Project Bonds, the Hoover Uprating Project Bonds, the Mead-Phoenix Project Bonds, the Mead-Adelanto Project Bonds, the Multiple Project Fund Bonds, the San Juan Project Bonds, the Magnolia Power Project Bonds, the Natural Gas Projects Bonds, Prepaid Natural Gas Project No. 1 Bonds, the Canyon Power Project Bonds, the Milford Wind Phase I Project Bonds, the Milford Wind Phase II Project Bonds, the Linden Wind Project Bonds, the Tieton Project Bonds, the Windy Point/Windy Flats Bonds, and the Apex Power Project Bonds.

Authorized investments for the Projects' Stabilization Fund are set forth in a resolution approved by the Board in 1996.

Eligible securities include:

• United States Treasury Securities, which are bonds or other obligations secured by the full faith and credit of the United States of America;

• Federal Agency Obligations, which have the full financial backing of the U.S. Government;

• Government Sponsored Enterprise Obligations, which are created by acts of Congress to provide liquidity for selected lending programs targeted by Congress;

" Repurchase Agreements, which are collateralized loan contracts where the seller includes a written agreement to repurchase the securities at a later date for a specified amount;

" Negotiable Certificates of Deposit, which are deposit liabilities issued by a nationally or state-chartered bank, a savings or a federal association or by a state-licensed branch of a foreign bank, which has short-term ratings of at least "A-i" by S&P and at least "P-1" by Moody's;

• Bankers' Acceptances, a short-term draft or bill of exchange guaranteed for payment at face value to the holder of the instrument on its maturity date, which has a short-term rating of at least "A-i" by S&P and at least "P-i" by Moody's;

• Commercial Paper, a short-term unsecured promissory note issued by non-financial or financial firms with a rating of at least "A-1" by S&P and at least "P-i" by Moody's;

• Medium Term Notes rated "A" or better and only those issued by corporations organized and operating within the United States, or by depository institutions licensed by the United States or any state and operating within the United States; and

• Equity-Linked Notes, which are categorized as medium-term corporate notes and are subject to the constraints set forth in the Government Code and the Authority's Investment Policy.

72

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 4 - Investments (continued)

As of June 30, 2014, the Authority held the following as cash and cash equivalents and investments:

Carrying Value Weighted Average Investment Type (in thousands) Maturity (Years) Percent of Portfolio U.S. Agency Securities $ 452,088 0.94 46.1%

Guaranteed Investment Contracts 52,277 9.61 5.3%

Money Market Funds 291,265 0.08 29.7%

Commercial Paper 100,192 0.08 10.2%

Negotiable CDs 43,200 0.06 4.4%

U.S. Discount Notes 42,300 0.03 4.3%

Total $ 981,322 0.98 100.0%

The "weighted average maturity in years" calculation assumes that all investments are held until maturity.

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 4 - Investments (continued)

Investments at June 30, 2014 are as follows (amounts in thousands):

GENERATION GREEN POWER TRANSMISSION Magnolia Canyon Hoover Tieton Transmission Mead- Mead-Palo Verde San Juan Power Power Apex Power Uprating Hydro- Milford I Milford II Windy Point Linden Wind System Phoenix Adelanto Project Proiect Proiect Proiect Project Project power Wind Wind Project EnerhV Proiect Proiect Proiect U.S. Agencies S 190.588 $ 7,902 S 43.995 $ 19,297 S 5,477 S 2,242 $ 5,383 $ 24,019 $ 3,273 $ 10,312 S 2,274 $ 9,509 $ $

Agency Discount Notes 9,000 7,700 2,000 1,300 - 2,600 - 2,500 1,100 8,100 Negotiable CDs - 4,500 7,900 - - 13,000 1,800 3,100 Commercial Paper 2,900 3,498 - 2,000 18,000 4,600 3,700 10,000 1,300 27,694 501 14,800 GIC's 21,248 7,798 3,863 - 7,789 Money Market Funds 18.189 19,843 25,845 9,273 33,736 968 2,808 15,198 11,304 24,882 7,306 32,731 4 j42210,408

$ 241 925 $ 43541 $ 89,303 $ 32,570 $ 57,213 $ 4510 $ 8.191 $ 46,417 $ 18,.277 $ 47.694 $ 11,980 $ 98,823 $ 6,722 $28.308 Total Restricted investments $ 194,156 $ 21,213 $ 55,558 $ 23,297 $ 23,477 $ 2,982 $ 5,383 $ 31,219 $ 6,973 $ 22,812 $ 4,674 $ 66,092 $ 2,300 $ 17,900 Unrestricted investments 30,477 560 - - - - -

Cash and cash equivalents 17,292 22,328 33r745 9,273 33,736 968 2,808 15.198 11,304 24,882 7,306 32,731 4,422 10,408 24,1925 $ $ 9303 $ 463417 $ 18.277 $ 47694 $ 11.980 $ 98,823 $ 6722 $ 28308 Total $4192 4354 __ 8930 ___ 32570 ___, S7 __ __,50__811 _.7 POWER PURCHASE AGREEMENTS NATURAL GAS MISCELLANEOUS Ormat Geo- MW)D Ameresco Campbell Copper Project Projects' thermal Small Pebble Chiquita Wild Rose Mountain Pinedale Barnett Prepaid Development Stabilization SCPPA Building Proiect Hydro Springs Landfill Gas Geothermal Solar 3 Project Proiect Natural Gas Fund Fund Fund Total U.S. Agencies $$ - $ $ $ $ 21,550 $ $ 106,267 $ 452,088 Agency Discount Notes 1,000 7,000 42,300 Negotiable CDs 1,400 11,500 43,200 Commercial Paper 5,000 6,200 100,192 GIC's - - 11,579 - 52,277 Money Market Funds 2,819 1,221 3,123 2,041 67 1,615 19,290 16,109 6,062 65 20,826 314 291,265 Total $ 2.819 $ 1221 $ 4.123 $ 2 41 $ 67 $ 1615 $ 19 290 $ 44,059 $ 18.441 $ 65 $ 151,793 $ 314 $ 981,322 Restricted investments $ $ $ $ - $ $ - $ $27,950 $ 11,579 $ -$ 130,967 $ -$ 648,532 Unrestricted investments -- - 31,037 Cash and cash equivalents 2,819 1,221 4,123 2,041 67 1,615 19.290 16,109 6,862 65 20,826 314 301,753 Total $ 2,819 $ 1.221 $ 4,123 $ 2.041 $ 67 $ 1615 $ 19,290 $ 44,059 18441$ 65$ 151,793$ 314 74

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 4 - Investments (continued)

Investments at June 30, 2013 are as follows (amounts in thousands):

GENERATION GREEN POWER TRANSMISSION VlagnIuiip nuMver auULleIrn iLeU- iepU-Palo Verde San Juan Power Canyon Power Uprating Tieton Hydro. Milford I Milford II Windy Point Linden Wind Transmission Phoenix Adelanto Project Project Project Project Project power Wind Wind Project Energy System Project Project Project U.S.Agencies S 186,519 $ 9,861 $ 37,362 $ 18,970 $ 2,206 $ 5,293 $ 23,871 $ 3,265 $ 10,257 $ 2,242 $ 19,492 $ $

Agency Discount Notes 1,100 - 3,900 2,500 3,400 - 5,900 Negotiable CDs 5,000 9,100 2,800 - 4,300 2,500 6,290 1,050 17,001 360 Commercial Paper - 8,600 8,000 1,298 3,598 7,197 12,900 S,S97 29,801 -

GIC's 27,649 21,323 3,863 - - 7,789 5,509 22,686 Money Market Funds 20.956 17,338 28,747 9,383 881 2,729 9,939 4,646 13,869 5,270 22,788 1,659 4,466 Total $240,124 $ 48522 $ _87672 4 8022 45,608 $420,108 6.716 $ 14159 $ 102.771 $ 7,528 $ 27152 Restricted investments $ 178,911 $ 31,189 $ 52,625 $ 30,870 $ 2,344 $ 5,293 $ 32,071 $ 7,865 $ 29,347 $ 6,392 $ 66,384 $ 5,869 $ 22,686 Unrestricted investments 36,878 - - 1,160 - 1,498 5,497 - 2,497 - -

Cash and cash equivalents 24,335 17,333 35,047 9,383 881 2,729 12,039 6,746 17,369 5,270 36,387 1,659 4,466 Total $240,124 $ 48522 $ 87,672 40,253 $ 4,385 $ 81022 $ 45,608 $ 20,108 $ 46,716 $ 14,159 $ 102,771 S 7,528 $ 27152 POWER PURCHASE AGREEMENTS NATURAL GAS MISCELLANEOUS thermal MWD Small Pebble Chiquita Pinedale Barnett Prepaid Project Development Stabilization SCPPA Project Hydro Springs Landfill Gas Project Project Natural Gas Fund Fund Fund Buildlng Fund Total U.S.Agencies $ $ S 29,695 $ $$ $ $ 117,496 $ $ 466,529 Agency Discount Notes .- 16,800 Negotiable C~s 3,000 7,000 2,000 3,700 64,101 Commercial Paper - 1,599 2,700 - 81,290 GIC's - - 11,510 39,197 139,526 Money Market Funds S,386 1,993 4,713 2,284 15,483 8,463 2,250 154 9,813 46 193,2S6 Total $ 5,386 $ 1.993 $ 7,713 $ 2.284 $ 24,082 $ 42,858 $ 17,460 $ 39,197 $ 154 $ 127,309 $ 46 $ 961S52 Restricted investments $ $ $ - $ - $ 7,600 $ 34,395 $ 11,510 $ 39,197$ S 117,496 $ - $ 682,044 Unrestricted investments 999 - - 48,529 Cash and cash equivalents 5,386 1,993 7,713 2,284 15,483 8,463 5.950 154 9,813 46 230,929 Total $ 1.993 $ 7,713 $ 24082 42 858 17.460 $39197 _ 154 $ 127,309 $ 46 $ 961,502 75

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 4 - Investments (continued)

Interest rate risk - The Authority's investment policy limits the maturity of its investments to a maximum of five years for investments in the United States Treasury, Federal Agency, and Government Sponsored Enterprise securities, excluding: investments held in Project Debt Service Reserve; long-term commitments or agreements approved by the Authority's Board; five years for medium term corporate notes; 270 days for commercial paper; 180 days for bankers' acceptances; and one year for negotiable certificates of deposits.

Credit risk - Under its investment policy and the State of California Government Code, the Authority is subject to the prudent investor standard of care in managing all aspects of its portfolios. As an investment standard, each investment shall be made with "judgment and care under circumstances then prevailing, which a person of prudence, discretion and intelligence would exercise in the management of his/her affairs, not in regard for speculation, but in regard to the permanent disposition of funds, considering the probable income as well as the probable safety of the capital to be invested." The Authority's investment policy does not preclude active management of the portfolio to address market opportunities. All transactions shall be undertaken in the best interest of the Authority and its participants.

The Authority's investment policy specifies that all project funds may be invested in shares of beneficial interest for temporary periods, pending disbursement or reinvestment as allowed under the state of California Government Code (Code). The Code requires that the fund must have either 1) attained the highest ranking or highest letter and numerical rating provided by not less than two nationally recognized statistical rating organizations (NRSRO) 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, 2014, money market funds in the portfolios with Bank of New York Mellon have attained the following ratings: AAAm by Standard and Poor's, and AAA-mf by Moody's Investors Service; while money market funds in the portfolios with US Bank have attained ratings of A-l+ by Standard and Poor's, P-1 by Moody's Investors Service, and Fl+ by Fitch Ratings.

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, 2014 and 2013, the U.S. government agency securities in the portfolio carried the highest possible credit ratings by the NRSRO that rated them.

The Guaranteed Investment Contracts in the portfolio with American International Group (AIG) consist of securities issued by corporations and carry a rating of A- by Standard and Poor's, Baal by Moody's Investors Service and BBB+ by Fitch Rating.

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 4 - Investments (continued)

The Investment Agreement Contract with American General Life consists of securities issued by corporations and carries a rating of A+ by Standard and Poor's, A2 by Moody's and A+ by Fitch Ratings.

The Investment Agreement Contract in the portfolio with Assured Guaranty (formerly Financial Security Assurance) consists of securities issued by corporations and carries a rating of AA- by Standard and Poor's, and A2 by Moody's Investors Service.

Concentration of credit risk - The Authority's investment policy specifies a 50% to 100% limitation on the amount that can be invested in U.S. government agency securities, except in certain issues of other Authority projects, such as the Mead-Adelanto and Mead-Phoenix projects.

Of the Authority's total investments as of June 30, 2014, $129 million (13%) was invested in securities issued by the Federal Home Loan Bank; $235 million (24%) was invested in securities issued by the Federal National Mortgage Association; $58 million (6%) was invested with Federal Home Loan Mortgage; $100 million (10%) was invested in Commercial Paper; and $21 million (2%) was invested in GICs with Assured Guaranty.

Of the Authority's total investments as of June 30, 2013, $80 million (8%) was invested in securities issued by the Federal Home Loan Bank; $59 million (6%) was invested with Farm Credit Bank; $264 million (27%) was invested in securities issued by the Federal National Mortgage Association; $75 million (8%) was invested with Federal Home Loan Mortgage; $64 million (7%) was invested in Certificates of Deposit; $81 million (9%) was invested in Commercial Paper; and $67 million (7%) was invested in GICs with PNC Financial Securities Group.

Note 5 - Derivative Instruments Objective of the swaps - SCPPA uses derivative instruments to hedge its exposure to changing interest rates through the use of interest rate swaps and also to manage its exposure to fluctuating natural gas prices through the use of natural gas hedge contracts. An interest rate swap is the exchange of payments between SCPPA and a counterparty in order to potentially obtain a lower cost of funding than traditional fixed rate bonds, or to hedge interest rate exposure on SCPPA's assets or liabilities. The Authority has entered into separate pay-fixed, receive-variable interest rate swaps and four basis swaps to produce savings or to result in lower costs over the life of each transaction than what the Authority would have paid using fixed-rate debt. While these instruments carry additional risks, SCPPA's swap policy and favorable negotiations have helped to reduce such risks.

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 5 - Derivative Instruments (continued)

The Authority has adopted Statement No. 53 of the GASB, Accounting and Financial Reporting for Derivative Instruments (GASB 53). This Statement addresses the recognition, measurement, and disclosure of information regarding derivative instruments. In accordance with GASB 53, SCPPA recognizes the changes in fair values of effective hedging derivative instruments as either deferred inflows or outflows of resources on the Authority's Statement of Net Position and includes changes in the fair value of an ineffective derivative instrument in earnings.

For fiscal year ended June 30, 2013, the balance for the swaps deemed to qualify for effective hedge accounting under GASB 53 was a net liability and corresponding deferred outflows of resources of $13.5 million. During fiscal year ended June 30, 2014, the liability increased by $1.8 million for an ending liability balance of $15.4 million. For the swaps that were deemed ineffective derivative instruments under GASB 53, the changes were reported in the statement of operations. The net liability balance for fiscal year ended June 30, 2013 for the ineffective derivative instruments was $40.2 million, but during fiscal year ended June 30, 2014, the liability increased by $0.395 million for an ending liability balance of

$39.8 million.

Terms, fair values, and credit risk - The terms, including the fair values and credit ratings of the counterparties under the outstanding swaps as of June 30, 2014, are included in the table below. In most cases, and with the exclusion of basis swaps, the notional amount of any swap matches the principal amount of the associated debt. Except as discussed under the rollover risk, and when associated with basis swaps, the Authority's swap agreements contain scheduled reductions to outstanding notional amounts that are expected to approximately follow scheduled or anticipated reductions in the associated "bonds payable" category.

Fair Values Swap Notional Amount (in Effective (in Termination Counterparty thousands) Date Fixed Rate Paid Variable Rate Received thousands) Date Credit Rating-MAG 2010-1 Swap (Barclays) S 100,000 5/11/2010 SIFMA 80.4% of 3-month LIBOR $ (2,882) 7/1/2036 A/A2/A MAG2010.2 Swap (RBC) 100.000 5/12/2010 SIFMA 81% of3-month LIBOR (2.625) 7/1/2036 AA-/Aa3/AA MAG2009-1 Swap (ONYMelIon) 110.321 1/1/2012 3.125% SIFMA (6,856) 7/1/2036 AA-/Aa2/AA-MAG2009-2 Swap (JPMorgan) 110.205 8/21/2012 3.139% SIFMA (7,056) 7/1/2036 A+/Aa3/A+

STS Swaption/Swap 121,000 11/1/2011 4.250% 60% of LIBOR (28.028) 7/1/2022 AA./Aa3/AA-MA 2007 Swap 100,000 6/1/2018 1-month LIBOR 100% of 10-yr LIBORCMISrate les .414% 752 9/10/2030 A+/Aa3/A-PNG2007 Swap 36,000 5/1/2009 5.047S% 67% of3-MonthLIBORplus 1.47% (8,537 11/1/2035 A-/Baal/A S 6811526

• S&P/Moody's/Fitch ratings 78

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 5 - Derivative Instruments (continued)

MAG 2010-1 Swap - In May 2010, SCPPA executed $100 million SIFMA/LIBOR floating-to-floating basis swap related to Magnolia Power Project A Refunding Bonds 2009-1. SCPPA pays the 6-month average of the weekly reset SIFMA Municipal Swap Index semi-annually on an Actual/Actual basis in exchange for receiving 80.4% of average 3-Month LIBOR, reset quarterly and paid semi-annually on an Actual/360 day basis. The swap expires on July 1, 2036.

• MAG 2010-2 Swap - In May 2010, SCPPA executed $100,000,000 SIFMA/LIBOR floating-to-floating basis swap related to Magnolia Power Project A Refunding Bonds 2009-2. SCPPA pays the 6-month average of the weekly reset SIFMA Municipal Swap Index semi-annually on an Actual/Actual basis in exchange for receiving 81.0% of average 3-Month LIBOR, reset quarterly and paid semi-annually on an Actual/360 day basis. The swap expires on July 1, 2036.

" MAG 2009-1 Swap (restated/novated) - This swap transaction amends the MAG 2007-1 Swap, which had an original trade date of April 30, 2007. The transaction was amended and restated as of April 21, 2009. The Authority pays its counterparty a fixed rate of 3.125% in exchange for receiving 100% of the Securities Industry and Financial Markets Association Swap Index (SIFMA] on a notional amount of $110.9 million. In order to provide more favorable terms to the participants, SCPPA made a payment of $15.7 million to the counterparty which has been deferred and is being amortized as an interest yield adjustment over the life of the swap. The amendment allowed the parties to re-coupon the swaps, change the collateral posting requirements, and to move to uninsured swaps. In May 2012, the swap was novated to a new counterparty and the swap documents amended to raise the collateral threshold.

• MAG 2009-2 Swap (amended/restated) - This swap transaction amends the MAG 2007-1 Swap.

The original transaction was novated from Bear Stearns to JP Morgan on November 6, 2008 and was amended and restated on April 21, 2009. The Authority pays its counterparty a fixed rate of 3.139%

in exchange for receiving 100% of the SIFMA Index on a notional amount of $111.5 million. In order to provide more favorable terms to the participants, SCPPA made a payment of $15.7 million to the counterparty which has been deferred and is being amortized as an interest yield adjustment over the life of the swap. The amendment allowed the parties to re-coupon the swaps, change the collateral posting requirements, and to move to uninsured swaps. In August 2012, the swap documents were amended to raise the collateral threshold.

• STS 2006 Swap (terminated) - In October 2012, the STS 2006 Amended Swap was terminated and SCPPA received a termination payment in the amount of $4.03 million. In November 2004, the Authority entered into a floating-to-floating fixed-spread basis swap. The STS 2006 Swap was amended and suspended for five years in July 2006 and in March 2011 the suspension was extended for an additional three years.

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 5 - Derivative Instruments (continued)

STS Swaption/Swap (restated/novated) - In February 2001, the Authority entered into a transaction whereby it sold an option (the Swaption) on a floating-to-fixed interest rate swap. The Swaption was exercised on April 1, 2002. The floating rate on the swap paid by the counterparty is 60% of the one-month LIBOR; the annual fixed rate on the swap paid by the Authority is 4.25%. In exchange for the right to exercise the Swaption, the counterparty paid the Authority a one-time up front option premium amount of $7.9 million which has been deferred and is being amortized as an interest yield adjustment over the life of the option. The counterparty has the option to cancel the agreement at the counterparty's discretion. In November 2011, the swap was novated to a new counterparty. The swap documents were kept substantially the same and the swap insurance was cancelled. The swap expires on July 1, 2022.

" STS 2001 Swap (terminated) - In June 2013, the STS 2001 Series A Bonds were refunded and the STS 2001 Swap was terminated. In June 2001, the Authority entered into an interest rate swap agreement with counterparty for the purpose of hedging against interest rate variations arising from the issuance of the Southern Transmission Project 2001 Subordinate Refunding Series A Revenue Bonds. The notional amount of the Swap Agreement equaled the par value of the bonds.

• MP 2004 Swap (terminated) In September 2012, the Mead-Phoenix 2008 Series A and B Bonds were refunded and the MP 2004 Amended Swap terminated. In connection with the issuance of the Mead-Phoenix Project 2004 Revenue Bonds Series A auction-rate security in May 2004, the Authority entered into an interest rate swap on March 3, 2004. The floating-to-fixed rate swap created synthetic fixed-rate debt for the Authority. The Authority received approximately $1.8 million in an upfront payment in connection with the execution of the swap, which has been deferred and amortized as an interest yield adjustment over the life of the option. The MP 2004 bonds were refunded on October 2, 2008 and the related interest rate swap transferred to the MP 2008 Refunding Bonds.

" MA 2007 Swap (amended) - In January 2007, the Authority entered into a Constant Maturity Swap (CMS) in connection with its outstanding Mead-Adelanto Project bonds. The transaction consisted of a $100 million basis swap and does not relate to any single series of the Mead-Adelanto bonds. The amended swap terms became effective on February 1, 2008 and the Authority pays the swap counterparty 100% of the one month LIBOR in exchange for receiving 100% of the 10-year LIBOR minus 41.4 basis points. The swap expires on September 15, 2030. On November 5, 2008 the MA 2007 Swap was novated from Bear Stearns to JP Morgan. In addition, the swap was suspended until November 1, 2011. As part of the novation, the credit terms of the existing swap agreements were maintained and SCPPA received $4.1 million from JP Morgan as compensation for the suspension of the cash flows of the MA 2007 CMS. The $4.1 million was deferred to be amortized over the suspension term.

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 5 - Derivative Instruments (continued)

In June 2010, the MA 2007 CMS Agreement was amended to extend the suspension period from November 1, 2011 to June 1, 2018. SCPPA received $5 million as compensation for the suspension of the cash flows of the swap, which was deferred and is being amortized over the suspension term.

The credit terms of the existing swap agreements remains unchanged.

MA 2004 Swap (terminated) - In September 2012, the Mead-Adelanto 2008 Series A and B Bonds were refunded and the MA 2004 Amended Swap terminated. In connection with the issuance of the 2004 Mead-Adelanto Revenue Bonds Series A auction-rate security in May 2004, the Authority entered into an interest rate swap on March 3, 2004. The floating-to-fixed rate swap created synthetic fixed-rate debt for the Authority. The Authority received approximately $5.9 million in an upfront payment in connection with the execution of the swap, which has been deferred and amortized as an interest yield adjustment over the life of the swap. The MP 2004 bonds were refunded on October 2, 2008 and the related interest rate swap transferred to the MA 2008 Refunding Bonds.

• PNG 2007 Swap - In October 2007, SCPPA entered into an interest rate swap agreement in connection with the issuance of the Prepaid Natural Gas Project No. 1 Series 2007B Bonds. The swap hedges the interest-rate risk on the LIBOR Floating-rate bonds, where SCPPA pays a fixed rate of 5.0475% in exchange for receiving 67% of three-month LIBOR plus 1.47%. The floating index on the swap exactly matches the coupon on the Bonds and therefore provides a hedge with no tax or basis risk. The swap expires on November 1, 2035.

" PNG 2007 Commodity Swap - At the same time, SCPPA also entered into five commodity price swap agreements, on behalf of each of the Prepaid Natural Gas Project No. 1 Participants, in order to hedge against reductions to its gas sale revenues resulting from changes in monthly market index prices. SCPPA pays a floating natural gas price over a 30-year period and receives specified fixed natural gas prices at an agreed pricing point as determined in the Prepaid Natural Gas No. 1 Agreements. The swaps became effective on July 1, 2008 and will all expire on September 30, 2035.

Fair value - Fair values take into consideration the prevailing interest rate environment, the specific terms and conditions of a given transaction, and any upfront payments that were received. All fair values were estimated using the zero-coupon discounting method. This method calculates the future payments required by the swap, assuming that the current forward rates implied by the yield curve are the market's best estimate of future spot interest rates. These payments are then discounted using the spot rates implied by the current yield curve for a hypothetical zero-coupon rate bond due on the date of each future net settlement on the swaps. While some of SCPPA's current mark to market values are negative, this valuation would be realized only if the swaps were terminated at the valuation date, and only SCPPA retains the right to optionally terminate most of the transactions.

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 5 - Derivative instruments (continued)

Interest-rate risk - Interest rate risk is the risk that changes in interest rates will adversely affect the fair values of SCPPA's financial instruments or cash flows. SCPPA is exposed to interest-rate risk on its pay-fixed, receive variable interest rate swaps. As the LIBOR or the Securities Industry and Financial Markets Association (SIFMA) swap index decreases, SCPPA's net payment on swaps increases. In addition, SCPPA is exposed to interest rate risk if the counterparty to the swap defaults or if the swap is terminated.

Market access risk - Market access risk is the risk that SCPPA will not be able to enter credit markets or that credit will become more costly. SCPPA's financial rating is tied to the credit strength of the major participants of the specific project for which each financial instrument is issued. SCPPA is also exposed to market access risks caused by disruptions in the municipal bond market.

Credit risk - As of June 30, 2014, the net fair values of the Authority's applicable swaps for which payments were made were negative for each counterparty except for the MA 2007 swaps. However, should interest rates change and the fair values of the swaps become positive, the Authority may be exposed to credit risk in the amount of the derivatives' fair value.

The swap agreements contain varying collateral agreements with the counterparties. The swaps require full collateralization of the fair value of the swap should the counterparty's (or if applicable, the guarantors of the counterparty's) credit rating fall below AA- as issued by Standard & Poor's or Aa3 as issued by Moody's Investors Service for the MA 2007 Swaps; A/A2 for the PNG 2007 Commodity Swap; and A-/A3 for the MAG 2010-1, MAG 2010-2, MAG 2009-1, MAG 2009-2, and the STS Swaption/Swap.

Collateral on all swaps is to be in the form of U.S. government securities held by a third-party custodian.

The swap agreements provide that when the Authority has more than one derivative transaction with a given counterparty involving the same Authority project (and having the same swap/bond insurer),

should one party become insolvent or otherwise default on its obligations, close-out netting provisions permit the non-defaulting party to accelerate and terminate all such related transactions and net the transactions' fair values so that a single sum will be owed by, or owed to, the non-defaulting party.

Basis risk - Basis risk is the risk that the interest rate paid by the Authority on underlying variable rate bonds to bondholders exceeds the variable swap rate received from the counterparty, and the risk that both legs of a basis swap are not exactly equal. With the exception of the PNG 2007 Swap, the Authority bears basis risk on each of its swaps. The PNG 2007 Swap is perfectly hedged since the counterparty pays the Authority its actual variable bond rate on the related bonds. All the other swaps have a basis risk since under each of those swaps the Authority received a percentage of LIBOR or a percentage of, or spread to, SIFMA to offset the actual variable bond rate or variable swap rate the Authority pays on any related bonds or on any basis swap. The Authority is exposed to basis risk should the floating rate that it receives on a swap be less than the actual variable rate the Authority pays on any related bonds; or in the case of the floating-to-floating fixed-spread basis swap, less than the variable rate paid to the swap counterparty.

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 5 - Derivative Instruments (continued)

Depending on the magnitude and duration of any basis risk shortfall, the expected cost savings from a swap may not be fully realized.

The following is a summary of interest rates paid to and received from the counterparties as of June 30, 2014:

Type of Derivative STS Swaption/ MAG 2009-1 MAG 2009-2 MAG 2010-1 MAG 2010-2 PNG 2007 Swap Swap Swap Swap Swap Swap Payments to counterparty 4.250% 3.125% 3.139% 0.060% 0.060% 5.048%

Less, variable payments from counterparty 0.091% 0.060% 0.060% 0.188% 0.189% 1.621%

Net interest-rate swap payments 4.159% 3.065% 3.079% -0.128% -0.129% 3.427%

Add, variable-rate bond coupon payments N/A 0.040% 0.030% N/A N/A 1.621%

Synthetic interest rate on bonds 4.159% 3.105% 3.109% -0.128% -0.129% 5.048%

Termination risk - The Authority or the counterparty may terminate any of the swaps if the other party fails to perform under the terms of the contract. In addition, the Swap/Swaption provides the counterparty with an option to cancel the swap agreement if the consecutive 180-day averaged rate of the SIFMA index exceeds 7 .0%. If any of the swaps were terminated, any associated variable rate bonds would no longer be hedged to a fixed rate. If at the time of termination the swap has a negative fair value, the Authority would be liable to the counterparty for a payment equal to the swap's fair value.

Rollover risk - Rollover risk is the risk that the swap contract is not co-terminus with the related bonds. The Authority is exposed to rollover risk on the STS Swap/Swaption because the counterparty has the option to terminate the agreement prior to the maturity of the associated debt. In the event that this swap terminates, the Authority would be exposed to variable interest rates on the underlying bonds.

83

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 5 - Derivative Instruments (continued)

Swap payments and associated debt - Using rates as of June 30, 2014, debt service requirements of the Authority's outstanding variable rate debt and net swap payments are as follows. As rates vary, variable rate bond interest payments and net swap payments will vary.

(amounts in thousands)

Variable-Rate Bonds Interest-Rate Fiscal Year Endine lune 30, Principal Interest Swaps, Net Total 2015 $ 23,095 $ 93 $ 7,735 $ 7,828 2016 5,125 90 7,530 7,620 2017 750 90 7,507 7,597 2018 785 90 7,483 7,573 2019 815 90 7,457 7,547 2020-2024 14,595 440 36,567 37,007 2025-2029 111,975 357 29,681 30,038 2030-2034 175,655 233 19,516 19,749 2035-2039 184,975 343 5,039 5,382

$ 517,770 $ 1,826 $ 128,515 $ 130,341 The following table shows the changes in fair value of derivative instruments (amounts in thousands):

Change in Fair Description June 30, 2013 Value June 30, 2014 Assets Mead Adelanto - Derivative instruments $ 625 $ 127 $ 752

$ 625 $ 127 $ 752 Deferred outflows of resources Magnolia - Deferred outflows $ 5,405 $ 1,451 $ 6,856 Prepaid Natural Gas - Deferred outflows 8,137 400 8,537

$ 13,542 $ 1,851 $ 15,393 Liabilities Magnolia - Derivative instruments $ 15,972 $ 3,447 $ 19,419 STS - Derivative instruments 30,290 (2,262) 28,028 Prepaid Natural Gas - Derivative instruments 8,137 400 8,537

$ 54,399 $ 1,585 $ 55,984 84

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 6 - Long-Term Debt Long-term debt outstanding at June 30, 2014 consisted of "new money" bonds, refunding bonds, and subordinate refunding bonds due in varying annual amounts through July 1, 2040. The new money bonds were issued to finance the purchase and construction or acquisition of the Authority's interest in each of the Projects. The subordinate refunding bonds were issued to refund specified new money bonds.

In accordance with the bond indentures, the new money bonds and refunding bonds are special, limited obligations of the Authority. With the exception of the Magnolia Power Project B, Lease Revenue Bonds (City of Cerritos, California) 2003-1 (Project B Bonds), the bonds issued by each project are payable solely from and secured solely by interests in that project as follows:

" Proceeds from the sale of bonds;

" All revenues, incomes, rents, and receipts attributable to that project and interest earned on securities held under the bond indenture or indentures; and

• All funds established by the indenture or indentures.

The Authority has agreed to certain covenants with respect to bonded indebtedness, including the requirement to enforce the natural gas, power, and transmission sales agreements with the participants.

At the option of the Authority, all outstanding new money bonds and refunding bonds are subject to redemption prior to maturity, except for the 2006-1 Magnolia Revenue Bonds; the 2013 Series A and B Subordinate Refunding Bonds, the 2012 Series A Subordinate Refunding Bonds, the 2011 Series A Subordinate Refunding Bonds, and portions of the 1988A Refunding Bonds, the 1992, the 2008A, and the 2009A Subordinate Refunding Bonds issued for the Southern Transmission System; the 2012 Series A Mead-Phoenix and Mead-Adelanto Bonds; the 2007 Series A and B Prepaid Natural Gas Project No. 1 Bonds; portions of the 2010 Series A and B Canyon Power Revenue Bonds; portions of the 2010-1 Milford I Wind Revenue Bonds; portions of the 2010 Series A Linden Wind Revenue Bonds; and portions of the 2010-1 Windy Point/Windy Flats Revenue Bonds.

Variable rate debt includes debt with rates based on daily, weekly, and long-term rates as determined by a Remarketing Agent.

85

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 6 - Long-Term Debt (continued)

Asummary of changes in long-term debt follows (amounts in thousands):

GENERATION GREEN POWER Magobta C-Y H-Jonln Power Pow ApexPower Upraong TletonHydro- WindyPoint Unden.lnd P"loVerdePro)ert P00000 Prol ProI Prof Pr t poer MitordI WInd MilfordI Wad "r Eer TolaoIlaeq-trndubtatJunoe30.2013 5 47.460 S 74.083 $343.455 $310,102 S $

S 7,983 S 51.716 S 224.612 $ 164.762 $ 513,295 $ 13(.972 Totaldtduewrithin o ,eyaalune30.2013 10.980 27r250 4S2i.. - 1,755 790 8.135 5.065 171B50 3,425 Total debt at June 30,2013 50.440 101.333 359.060 310,102 9.738 52.S06 232.747 169.827 531.14S 140.397 Pr`nopa p.yPay (10,980) (27,250) (10.605} t-1.755) (790) (8.135) (5.065) (17.850) (3.425)

Revenuebondsissued 318.860 Bondsrefunded/defeased RefundingbondsIssued Chbarg In

.... ......... bl.. .d n. r722) (13261 1.057 144 f211 214 (651 (1.3891 U2,292) 6.451 1,06 Totaldebt at Jun, 30.2014 47.460 73.361 342.129 309.04S 333684 7,962 51.611 223,223 162,470 506.040 135.912 Tntldebtduewthin oneyearat[lme30.2014 (11330) 1132001 (10.565) - (1.835) (813I 8.4508 01270) (18.53S) (3530)

Totalong-neredebtatlJune30,2014 $ 36130 S 60.161 9331.564 $3096095 S 333,684 S 50.836 $ 214.773 S 157,200 S 408.305 S 132,382 TRANSMISSION N6AIRALGAS M0SC.

Southen, Read- Mood.

Toarosnl68on Phoenix Odetanto PlZedale Prepaid Multple S;Prem Pr1e Pr0)00 PrJe RoFo*rtP)e NaturelG25 Proje) Fund Tom)

Tota long-lor mdebtatJun, 30.2013 S 737,010 S 41.695 0140.042 S 26.982 S 63373 S 315.73 S - S 3,200,415 Totaldebt deoeritinoneyearatJune30,2013 49,130 6,505 17,820 2,253 5.302 4,065 13800 189,730 Total debt at J...30, 2013 786,140 48,200 157,862 29,235 68.675 320,938 13,800 3,390.145 Prlintipapaynents (49,130) (63005 (17.820) (2.253) (S.302) (4.065)J t13.800) (189.730)

Rnenue bondsIssued - 318^860 Bonds rofunded/defeasnd Refunding bondsIosed ChangeIn onamordzed deb-related c0a,net 14.402) (5521 (2.4731 (2741 17.2(31 Total debt at June 30. 2014 732,608 41.143 137,570 26.98Z 63,373 316,599 3.612.012 Total debt due within oneyear at June30, 2014 (50.8851 525) I 017,3) (2.2191 S.211 1387550I0S.20) -

To1) long-tern debt .1 June30, 2014 S 6 3 35,928 120,185 24,763 0 5&162 312724 S S - $ 3,353.692 Palo Verde Project - Debt consists of subordinate refunding series bonds with variable interest rates and final maturities during 2017.

San Juan Project - Debt consists of refunding series bonds with fixed interest rates of 5.00% and final maturities during 2020.

Magnolia Power Project - Debt consists of revenue and refunding series bonds with variable and fixed interest rates between 3.00% and 5.00% with final maturities occurring in 2036.

86

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 6 - Long-Term Debt (continued)

Magnolia Power Project Refunding Revenue Bonds - On December 7, 2011, SCPPA issued $62,265,000 Magnolia Power Project A Refunding Revenue Bonds, 2011-1 Refunding Series. These fixed rate bonds were issued to provide funds, together with certain available amounts, to refund a portion of the Magnolia Power Project A, Revenue Bonds 2003-1, to fund a Debt Service Reserve Account, and to pay costs of issuance relating to the 2011 Bonds. The transaction generated present value savings of over

$5.0 million, or 8.25% of refunded par. This transaction resulted in a net loss for accounting purposes of

$3.5 million. The true interest cost of the bonds was 2.48%.

Of the outstanding Magnolia Power Project Revenue Bonds, $124 million of "Project B Bonds" are secured by lease rental payments to be made by the City of Cerritos (the City) in connection with the lease of certain facilities and premises owned by the City to the Authority and the leaseback of such facilities and premises to the City. The Base Rental Payments will be equal to the principal and interest on the Project B Bonds. In accordance with the Assignment Agreement between the Authority and the Trustee, the Authority will assign certain of its rights under the Lease, including its right to receive the Base Rental Payments, to the Trustee for the benefit of the owners of the Project B Bonds.

The City has covenanted to budget and appropriate sufficient funds to make all payments required to be made under the Lease. The Lease has a term of 55 years.

Canyon Power Project - As of June 30, 2014, debt consists of revenue bonds with fixed interest rates ranging from 4.00% to 5.94% and final maturity occurring in 2040.

On June 9, 2010 the 2010 Series B Bonds were issued as Build America Bonds that are "qualified bonds" under the provisions of the American Recovery and Reinvestment Act of 2009. The interest on these bonds will not be excluded from gross income for federal income tax purposes, but will be exempt from the State of California personal income taxes. As such, the Authority may receive a cash subsidy from the United States Treasury up to 35% of the interest payable on the 2010 Series B Bonds which is applied to offset the interest costs of the 2010 Series B Bonds.

Apex Power Project - Debt consists of revenue bonds with fixed interest rates between 0.446% and 5.00% and final maturity occurring in 2038.

Apex Power ProjectRevenue Bonds - On March 26, 2014, SCPPA issued $151,880,000 2014 Series A (Tax-Exempt) and $166,980,000 2014 Series B (Taxable) Apex Power Project Revenue Bonds, together the "2014 Bonds". These fixed rate bonds were issued to provide funds to pay the acquisition costs of the Apex Power Project; to pay the costs of certain replacement parts for and capital improvements to the Project; to fund a debt service reserve account; and to pay the costs of issuance relating to the 2014 Bonds.

87

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 6 - Long-Term Debt (continued)

Hoover Uprating Project - Debt consists of refunding series bonds with fixed interest rates of 5.25%

and a final maturity occurring in 2017.

Tieton Hydropower Project - As of June 30, 2014, debt consists of revenue bonds with fixed interest rates between 3.326% and 5.798% and a final maturity occurring in 2040.

Milford I Wind Project - As of June 30, 2014, debt consists of revenue bonds with fixed interest rates ranging from 2.50% to 5.00% and final maturity occurring in 2030.

Milford Ii Wind Project - As of June 30, 2014, debt consists of revenue bonds with fixed interest rates ranging from 2.00% to 5.25% and final maturity occurring in 2031.

Milford Wind CorridorPhase I1Revenue Bonds - On August 25, 2011, SCPPA issued $157,465,000 of Milford Wind Corridor Phase 1IProject Revenue Bonds, 2011-1. These fixed rate bonds were issued for the purpose of financing the prepayment of a specified supply of electricity from a 102 MW nameplate capacity wind powered electric generating facility comprised of 68 wind turbines and related facilities located near Milford, Utah; to pay related development costs of the Project; to fund a deposit to the 2011-1 Debt Service Reserve; and to pay costs of issuance of the 2011-1 Bonds. The true interest cost of the 2011-1 Bonds was 3.75%.

Linden Wind Energy Project - As of June 30, 2014, debt consists of revenue bonds with fixed interest rates between 4.00% and 5.92% and final maturity occurring in 2035.

Linden Wind Energy ProjectRevenue Bonds - On September 28, 2010, SCPPA issued $138.3 million of the Linden Wind Energy Project Revenue Bonds, consisting of $96.8 million of 2010 Series A Tax Exempt Bonds and $41.5 million of the Series B Taxable Build America Bonds, together the 2010 Bonds.

The 2010 Series B Bonds were issued as Build America Bonds that are "qualified bonds" under the provisions of the American Recovery and Reinvestment Act of 2009. The interest on these bonds will not be excluded from gross income for federal income purposes, but will be exempt from the State of California personal income taxes. As such, the Authority receives a cash subsidy from the United States Treasury up to 35% of the interest payable on the 2010 Series B Bonds which is applied to offset the interest costs of the 2010 Series B Bonds.

Southern Transmission System Project - Debt consists of refunding and subordinate refunding series bonds with fixed interest rates ranging from 0.350% to 6.125% and final maturities occurring in 2027.

88

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 6 - Long-Term Debt (continued)

STS Project Refunding Bonds - On June 5, 2013, SCPPA issued $65.1 million 2013 Series A and $27.6 million 2013 Series B (Taxable) Southern Transmission Project, Subordinate Refunding Bonds, together the 2013 Bonds. These fixed rate bonds were issued for the purpose of refunding the outstanding Transmission Project Subordinate Refunding Bonds, 2001 Series A; to terminate the related interest rate swap; and to pay the related costs of issuance. The 2013 Bonds are not subject to redemption prior to maturity. This transaction generated present value savings of over $0.9 million or 1.1% of refunded par for SCPPA and its members. This transaction resulted in a net loss for accounting purposes of $20.4 million. The true interest cost of the 2013 Bonds was 1.21%.

STS Project Refunding Bonds - On April 3, 2012, SCPPA issued $39,935,000 Transmission Project Revenue Bonds, 2012 Subordinate Refunding Series A. These fixed rate bonds were issued for the purpose of refunding the outstanding 2002 Series A Subordinate Refunding Transmission Project Revenue Bonds, maturing on and after July 1, 2013. The transaction generated present value savings of over $8 million or 18.25% of refunded par for SCPPA and its members. This transaction resulted in a net loss for accounting purposes of $2.0 million. The true interest cost of the 2012A bonds was 1.30%.

Windy Point/Windy Flats Project - As of June 30, 2014, debt consists of revenue bonds with fixed interest rates between 3.00% and 5.00% and final maturity occurring in 2030.

Mead Phoenix/Mead Adelanto Projects - Debt consists of revenue and refunding series bonds with variable interest and fixed interest rates. Fixed interest rates range from 0.787% and 5.15% with final maturities occurring in 2020.

Mead Phoenix/Mead Adelanto Refunding Bonds - On September 12, 2012, SCPPA issued Mead-Adelanto and Mead-Phoenix 2012 Series A and B Revenue Bonds (the "2012 Bonds") in the aggregate principal amount of $127.8 million, consisting of $79.4 million Mead-Adelanto 2012 Series A, $16.6 million Mead-Adelanto 2012 Series B (Taxable), $24.5 million Mead-Phoenix 2012 Series A, and $5.3 million Mead-Phoenix 2012 Series B (Taxable). These fixed rate bonds were issued to provide moneys, together with other available funds, to refund the outstanding Mead-Adelanto and Mead Phoenix Revenue Bonds, 2008 Series A and B (the "2008 Bonds"); to terminate the related interest rate swap agreement; and to pay the related cost of issuance of the 2012 Bonds. The transaction generated present value savings of over $1.97 million or 1.5% of refunded par for SCPPA and its members. This transaction resulted in a net loss for accounting purposes of $31.4 million. The true interest cost of the 2012 Bonds was 1.39%.

Natural Gas Projects - Debt consists of revenue bonds with fixed interest rates ranging from 4.55% to 6.03% and final maturities occurring in 2032.

Prepaid Natural Gas Project No. I - Debt consists of revenue bonds with variable and fixed interest rates ranging from 5.00% to 5.25% and final maturity occurring in 2035.

89

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 6 - Long-Term Debt (continued)

On September 19, 2013, the credit restructure of the Prepaid Natural Gas Project was completed to reduce risk and exposure to various counterparties, obtain ratings upgrade on the related 2007 Gas Prepay Bonds (the "Bonds") and to capture projected savings and gas flows through 2035. As a result of the restructuring, the Bonds received ratings of A3/A from Moody's and Fitch, respectively; Standard &

Poor's affirmed its A rating; and the project participants received $3.4 million in upfront savings.

In October 2009, the Series 2007A Fixed Rate Bonds, the Prepaid Natural Gas Agreements, and certain other agreements were restructured to reduce risk, realize savings, provide an acceleration of the long-term savings, reduce the remaining volumes of gas to be delivered from 135 billion to 90 billion cubic feet, and shorten the term of the agreements from 30 to 27 years. As a result of the restructure, $165.5 million principal amount of the bonds were canceled, leaving $333.4 million of total bonds outstanding subsequent to the November 1, 2009 principal maturity.

Multiple Project Fund -Final maturity occurred on July 1, 2013. (See Note 2) 90

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 6 - Long-Term Debt (continued)

Premiums / Discounts- Unamortized premiums and discounts, net, which are included in the statements of net position as a component of long-term debt, are as follows (amounts in thousands):

June 30, 2014 (Premium)

Unamortized (Premium) Discount, Net Discount Palo Verde Project San Juan Project (1,481)

Magnolia Power Project (5,034)

Canyon Power Project (7,575)

Apex Power Project (14,824)

Hoover Uprating Project (32)

Tieton Hydropower Project (1,166)

Milford I Wind Project (9,578)

Milford II Wind Project (14,305)

Windy Point Project (41,530)

Linden Wind Energy Project (6,882)

Southern Transmission System Project (24,092)

Mead-Phoenix Project (2,753)

Mead-Adelanto Project (11,399)

Prepaid Natural Gas Project No. 1 (3,109)

$ (143,760)

June 30, 2013 (Premium)

Unamortized fPremiuml Discount. Net Discount Palo Verde Project $

San Juan Project (2,203)

Magnolia Power Project (6,360)

Canyon Power Project (8,632)

Hoover Uprating Project (53)

Tieton Hydropower Project (1,231)

Milford I Wind Project (10,967)

Milford 11Wind Project (16,597)

Windy Point Project (47,985)

Linden Wind Energy Project (7,942)

Southern Transmission System Project (28,494)

Mead-Phoenix Project (3,305)

Mead-Adelanto Project (13,871)

Prepaid Natural Gas Project No. 1 (3,383)

Multiple Project Fund

$ (151,023) 91

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 6 - Long-Term Debt (continued)

Advance refundings - The Authority has established irrevocable escrow trusts with the proceeds from issuance of subordinate refunding bonds. These investments will be used to pay specified revenue bonds called at scheduled redemption dates.

Defeasance of debt - The Authority has defeased specified revenue bonds by placing the proceeds from the issuance of subordinate refunding bonds in irrevocable trusts to provide for all future debt service payments on the refunded bonds. The trust investments and related liability for bonds that are considered legally defeased are not included in the Authority's financial statements. At June 30, 2014 and 2013, $378.4 million and $622.5 million, respectively, of revenue bonds outstanding are considered legally defeased.

The refunded bonds constitute a contingent liability of the Authority only to the extent that cash and investments presently in the control of the refunding trustees are not sufficient to meet debt service requirements and are therefore excluded from the combined financial statements because the likelihood of additional funding requirements is considered remote.

Debt service - The scheduled debt service payments for future years ending June 30 are included in the table on the following page. The variable rates used for the PV 2008 Subordinate Refunding Series A and B Bonds were both 0.06%. The variable rate used for the STS 2000 Subordinate Refunding Series Awas 0.06%. The variable rates used for the MAG 2009-1 and MAG 2009-2 were 0.04% and 0.03%,

respectively. All of the preceding variable rates were the rates at June 30, 2014. The variable rates are set by the bond-remarketing agent on a weekly basis based on economic conditions and bond ratings.

92

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 6 - Long-Term Debt (continued)

Future principal and interest payments are as follows (amounts in thousands):

GENERATION GREEN POWER Magnolia Powr PpPo Hoover Tieton Hydro- Unden Wind PaIoVerde San]-uan Power Proect pro Uwn .prating Power Milford IWind Milford 1IWind W Ener" 2015 Principal 11.330 S 13.200 S 10.565 S - S 1.835 S 011 $ 8,450 1,270 5 $ 18,S35 S 3.530 2015 Interest 1,045 3,594 11,622 16,732 9,632 368 2,532 10,236 7.463 22,081 6"55 2016 PrincipaI 11.690 13.0.1 10905 9-3" 1,930 040 8.820 5,530 19,390 3,670 2016 Interest 757 2.934 11.176 161732 12,588 270 2.503 9,874 7,201 21,277 6.411 2017 Principal 12,030 14.150 11,470 6,735 9,375 2,030 070 9.17S 5.795 20,14S 3,820 2017 Internest 461 2.241 10,672 16,597 12.537 165 2.460 9.476 6,934 20,449 6,Z61 2010 Principal 12,410 152015 7,230 7.001 9,435 2,135 910 9,615 6,065 21.041 3.970 2018 Interest 155 1,514 10,242 16,287 12,453 55 2,429 9,022 6,646 19,513 6,080 2019 Principal 3,560 7.560 7,355 9,045 950 10,085 6,370 22,020 4.170 2019 1nterest 749 9,903 15,965 12,316 2,385 8,545 6,346 18,515 5,902 2020 - 2024 Principal 11,430 43.825 42,85 51,131 S,545 50,300 36,835 126,680 23,791 2020 .2024 Interest 571 43.027 74.194 57.841 11,107 34.634 26.539 75,477 26.418 202S.2029 Principal 64.270 53,765 60.415 9.120 74.110 47.435 161,175 30,215 2025 - 2029 Interest 34,238 62.156 48,123 9,007 18,395 15.633 40.013 19,802 2030 - 2034 Principal 78,590 66.070 74.090 9,745 35,090 34,865 76,320 38.295 2030- 2034 Interest 22.064 45,169 33,349 6,688 1,775 2.808 3.862 10.930 2030:239 Pincipal 102600 80,795 95,030 12.435 - 17.165 2035 -2039 I=ee 6.468 23,320 12,343 3,929 1,050 2040-2041 Principal - 36.860 9,255 2040. 2041 Inters - 2,211 S51 Principal $ 47,460 $ 7105 $ 337 095 $ 301,470 $ 310060 7930 $ 50,485 1 213.645 $ 148,165 $ 46010 $ 129030 Interest $ 2,410 11603 S 161,012 289,3,53 S 2111102 $. . 850 3 101,957 $ 9 0 221.187 0 00.414 TRANSMISSION NATURALGAS rransmosoon Mead- Mead- Prepaid System Phoenix Adelanto Pinedale Barnett Naturl Gas Totlo 2015 Principal S s00,885 5.215 S 17,3035 2,219 S 5,211 3 3,875 158,320 2015 Interest 30,S1 1.51 5,480 1.439 3,384 15,858 150.103 2016 Principal 52,600 5:400 17,690 2,274 5,326 4,075 173,540 2016 Interest 29,346 1.249 4,625 1,331 3,128 15,659 147,061 2017 Prionipal 52,430 S.110 17,985 2.249 5,266 4.275 183,715 2017 Intlers 27,788 1,029 3,002 1.210 2,855 15,450 140,480 2018 Principal 53,090 5,688 10.450 1,980 4.640 4,605 183,535 2010 Interest 25,533 79 3,.105 1.104 2,596 11,228 132.762 2019 Princplo 54,860 5,875 19,.00 1.770 4,150 5,325 162.04' 2019 Interest 22,847 051 2,164 1.003 2,357 14,978 124,126 2020 2024 Principal 319,058 10,645 35,470 7,191 16,889 44,065 033,480 2020 - 2024 Interest 74.165 430 1,026 3,704 8,720 69.044 500,197 2025-2029 Principal 125,005 5.516 12.974 81,025 725,025 2025-2029 Interest I0,019 1,914 4.520 52.945 322,265 2030 - 2034 Principal - 3,783 0,917 130.185 557,250 2030-2034 Interest 443 1,04I 26,448 155,380 2035 .2039 Principal - 36.000 344,425 2035 - 2039 Interest 1,815 48,925 2040-2041 Principal 46,115 2040 - 2041 Interost 2,762 2,-

Principal 700510 $S 38,390 $ 126.170 $ 26,982 S 63,373 S 313,490 Interest S 225.779 $ 5555 0 20,782 12113 S 28604 $S 227,425 $ 1 732 461 93

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 7 - Notes Payable and Other Liabilities Notes payable and other liabilities consist mainly of Palo Verde Participants' overbillings from prior periods; an allowance for future major maintenance expenses for the Magnolia Power Project; and swap-related transaction fees received in the Mead Adelanto Project The notes payable held in the Palo Verde Project are invested in a guaranteed investment contract (GIC) that will mature in June 2017. The GIC is unsecured, bears an interest rate at 4.97%, and is paid out in monthly installments of $0.6 million.

On June 30, 2014, the remaining balance of the GIC is $21.2 million.

The three-year suspension of the Mead Adelanto 2007 CMS (the CMS Swap) in November 2008 netted a compensation of $4.1 million. In June 2010, the suspension was extended to June 2018 for a net compensation of $5.0 million. The total deferred balance of the CMS Swap is $2.5 million as of June 30, 2014 (see Note 5).

Notes payable and other liabilities rollforward (amounts in thousands):

Amortization Payments/ of Surplus June 30, Description June 30, 2013 Additions Amortization Fund 2014 PV prior year overbillings $ 26,074 $ $ (6,401) $ 393 $ 20,066 MPP major maintenance 4,607 4,015 - 8,622 Mead Adelanto 2007 Swap suspension 3,105. (628) 2477

$,, 33,786 $ 4,015 $ (7,029) $ 393 $ 31,165 Note 8 - Advances from Participants Advances from participants consist mainly of billings to participants related to acquisition, capital drilling, and inventory wherein the matching operating expenses will be recognized at a future date.

Also, and specific only to the Natural Gas Pinedale Project, advances held by the project are funds from LADWP and TID, both owners independent of SCPPA, and are for their share of operating costs and capital expenditures pursuant to their respective Agency Agreements.

94

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 8 - Advances from Participants (continued)

Advances from participants' rollforward (amounts in thousands):

Description June 30, 2013 Activity June 30, 2014 San Juan advances from participants $ 4,071 $ 5,011 $ 9,082 MAG advances from participants 21,479 950 22,429 Canyon Power advances from participants 2,225 - 2,225 Apex advances from participants - 2,500 2,500 Tieton advances from participants 202 - 202 Milford I advances from participants 250 - 250 Milford II advances from participants 250 - 250 Windy Point advances from participants 1,000 - 1,000 Linden Wind Energy advances from participants 2,004 - 2,004 NG Pinedale advances from participants 33,060 (3,754) 29,306 NG Barnett advances from participants 11,054 (607) 10,447 Ormat advances from participants 1,045 (188) 857 MWD advances from participants 500 - 500 Ameresco advances from participants 400 - 400 PDF advances from participants 154 (89) 65 SCPPA Building advances from participants 13 269 282

$ 77,707 $ 4,092 $ 81,799 Note 9 - Net Position The Authority's billing amounts to the participants are determined by its Board of Directors and are subject to review and approval by the participants. Billings to participants are designed to recover "costs" as defined by the power sales, natural gas sales, and transmission service agreements. The billings are structured to systematically provide for debt service requirements, operating funds, and reserves in accordance with these agreements. The accumulated difference between billings and the Authority's expenses calculated in accordance with accounting principles generally accepted in the United States of America are presented as Net Position. It is intended that this difference will be recovered in the future through billings for repayment of principal on the related bonds.

95

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 9 - Net Position (continued)

Net position is comprised of the following (in thousands):

Fiscal Year Fiscal Year June 30, 2012 2013 June 30, 2013 2014 (as restated) Activity (as restated) Activity June 30, 2014 GAAP items not included in billings to participants Depreciation of plant $ (1,428,032) $ (94,334) $ (1,522,366) $ (97,964) $ (1,620,330)

Nuclear fuel amortization (5,860) (5,860) (5,860)

Decommissioning expense (212,076) (6,755) (218,831) (5,679) (224,510)

Amortization of bond discount, debt issue costs, and loss on refundings (794,137) (2,511) (796,648) (10,009) (806,657)

Interest expense (43,115) (12,666) (55,781) 833 (54,948)

Loss on defeasance of bonds (85,827) (85,827) (85,827]

Derivatives and related charges (100,422) 60,515 (39,907) 395 (39,512)

Bond requirements Included in billings to participants Operations and maintenance, net of investment income 205,849 (70,378) 135,471 (53,424) 82,047 Costs of acquisition of capacity 7,908 (1,429) 6,479 (1,496) 4,983 Billings to amortize costs recoverable 382,050 - 382,050 382,050 Reduction In debt service billings due to transfer of excess funds (90,020) - (90,020) - (90,020)

Principal repayments 1,618,100 169,036 1,787,136 165,388 1,952,524 Withdrawal of funds - - (24,821) (24,821)

Other 258,692 10,830 269,522 10,645 280,167 (286,890) 52,308 (234,582) (16,132) (250,714)

Multiple Project Fund net position (2,516) 2,516 -

Projects' Stabilization Fund net position 112,419 15,164 127,583 24,444 152,027

$ (176,987] $ 69,988 $ (106,999) $ 8,312 $ (98,687)

Note 10 - Retirement Plan The Authority is a participating public employer in the California Public Employees Retirement System (CaIPERS) Miscellaneous 2.5% at 55 and 2.0% at 62 Risk Pool Employees' Retirement Plans, which are agent multiple-employer public employee defined benefit pension plans. CaIPERS provides retirement and disability benefits, annual cost-of-living adjustments, and death benefits to plan members and beneficiaries. CalPERS acts as a common investment and administrative agent for participating public entities within the State of California. Benefit provisions and all other requirements are established by state statute and Authority resolution. CaIPERS issues a separate comprehensive annual financial report, which is available from the CaIPERS' Executive Office, 400 P Street, Sacramento, California 95814.

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The Authority makes the plan contributions required of its employees on their behalf and for their account. The Authority is required to contribute at an actuarially determined rate of annual covered payroll. The contribution requirements of plan members and the Authority are established and may be amended by CalPERS. I In 2012, the Public Employees' Pension Reform Act (PEPRA) became law that implemented new benefit formulas and final compensation period, as well as, new contribution requirements for new employees hired on or after January 1, 2013 who meet the definition of new member under PEPRA. Employees hired prior to January 1, 2013 and those new employees not meeting the PEPRA definition of new member are considered classic employees.

Summary of certain plan provisions and benefits in effect for fiscal year ended June 30, 2014:

Classic Members:

Required service for eligibility 5 full-time years Benefit payments (% of final annual salary) Monthly for life Minimum retirement age 50 Monthly benefit 2.00% at age 50 to 2.50% at age 55 and up Required employee contribution rate 8.00%

Required employer contribution rates 18.58%

New Members:

Required service for eligibility 5 full-time years Benefit payments (%of final annual salary) Monthly for life Minimum retirement age 52 Monthly benefit 2.00% at age 60 to 2.50% at age 67 and up Required employee contribution rate 6.50%

Required employer contribution rates 6.70%

Actuarial annual required contribution (based on estimated payroll) $199,721 Actual employer portion contributions to the plan totaled $971,112 for fiscal year 2014, including

$627,515 for catch-up contributions. Actual employer portion contributions to the plan totaled

$309,900 for fiscal year 2013. The Agency's annual required contribution (based on actuarially established rates) was determined as part of a June 30, 2012, actuarial valuation using the entry age normal actuarial cost method. The primary actuarial assumptions included a 7.50% annual investment rate of return (net of administrative expenses); forecasted annual salary increases that vary by age, service and type of employment ranging from 3.30% to 14.20%; a 3.00% overall annual payroll growth; an individual salary growth of 3.00%; an annual production growth of 0.25%; and, an inflation component of 2.75%. A 15-year rate smoothed market approach is used to spread investment returns.

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At fiscal year-end June 30, 2012 (the date of the actuarial valuation), the Agency had ten eligible active employees and three retirees drawing benefits under this program.

Trend Information for Agency CaIPERS Retirement Plan Annual Percentage Net Fiscal Year Pension of APC Pension Ending Cost (APC) Contributed Obligation June 30, 2010 $ 168,308 100.0%

June 30, 2011 209,933 100.0%

June 30, 2012 256,248 100.0%

June 30, 2013 309,900 100.0%

June 30, 2014 343,597 100.0%

Funded Status of the CalPERS Miscellaneous 2.5% at 55 Risk Pool (in thousands):

Unfunded Actuarial Actuarial Actuarial Actuarial Accrued Annual Accrued Actuarial Accrued Value of Unfunded Funded Covered Liability as %

Valuation Liability Assets Liability Ratio Payroll of Payroll Date (a) (b) (a) - (b) (b) / (a) (c) [(a) - (b)] / (c)

June 30, 2010 1,972,911 1,603,482 369,429 81.3% 352,637 104.8%

June 30, 2011 2,135,350 1,724,201 411,149 80.8% 350,122 117.4%

June 30, 2012 2,254,622 1,837,489 417,133 81.5% 229,228 123.0%

Initial unfunded liabilities are amortized over a closed period that depends on the plan's date of entry into CalPERS. The unfunded actuarial accrued liability is being amortized as a level percentage of projected payroll on a closed basis. All changes in liability due to plan amendments, changes in actuarial assumptions, or changes in actuarial methodology are amortized over a period of time. The average remaining amortization period at the June 30, 2012 valuation date was approximately 19 years.

Operating gains and losses of the plan are amortized over a 30-year rolling period with the exception of gains and losses in fiscal years 2008-2009, 2009-2010, and 2010-2011 in which each year's gains and losses will be isolated and amortized over fixed and declining 30-year periods. If the plan's accrued liability exceeds the actuarial value of plan assets, then the amortization payment on the total unfunded liability may not be lower than the payment calculated over a 30-year amortization period. CalPERS actuarial valuations become available approximately two years after the Agency's fiscal year-end.

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On April 17, 2013, the CalPERS Board of Administration approved a recommendation to change the CaIPERS amortization and rate smoothing policies. Beginning with the June 30, 2013 valuation that will set the 2015-16 contribution rates, CaIPERS will employ an amortization and smoothing policy that will pay for all gains and losses over a fixed 30-year period with the increases or decreases in the rate spread directly over a 5-year period.

Note 11 - Commitments and Contingencies Public benefits - The members continue to collect the public benefit charge through existing rate structures and have instituted programs to benefit their customers including conservation and energy efficiency programs, public educational programs, research and development, and low income rate subsidies, totaling a combined $1.7 billion since their inception in 1997. The decisions on how these funds are allocated are made by the local governing authority, in most cases this is the city council.

Executive action and state legislation - The California Legislature approved several bills that affected the electric utility industry. In general, these bills provide for reduced greenhouse gas emission standards and greater investment in energy-efficient and environmentally friendly generation alternatives through more stringent renewable resource portfolio standards. The following is a brief summary of certain of these bills:

Greenhouse gas emissions - Executive Order 5-3-05 placed an emphasis on efforts to reduce greenhouse gas emissions by establishing statewide greenhouse gas reduction targets. The targets are:

(i) a reduction to 2000 emission levels by 2010; (ii) a reduction to 1990 levels by 2020; and (iii) a reduction to 80% below 1990 levels by 2050. The Executive Order also called for the California Environmental Protection Agency (the "EPA") to lead an effort to examine the impacts of climate change on California and develop strategies and mitigation plans to achieve the targets. In addition, Executive Order S-06-06 directs the State of California to meet a 20% biomass utilization target within the renewable generation targets of 2010 and 2020 for the contribution to greenhouse gas emission reduction.

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Assembly Bill 32, the Global Warming Solutions Act of 2006 (the GWSA) became effective as law on January 1, 2007. The GWSA prescribed a statewide cap on global warming pollution with a goal of reaching 1990 greenhouse gas emission levels by 2020. In addition, the GWSA establishes an annual mandatory reporting program for all investor-owned utilities (IOUs), local publicly-owned electric utilities ("POUs"), and other load-serving utilities (electric utilities providing energy to end-use customers) to inventory and report greenhouse gas emissions to the California Air Resources Board (CARB) and requires CARB to adopt regulations for significant greenhouse gas emission sources (allowing CARB to design a cap-and-trade system), and gives CARB the authority to enforce such regulations beginning in 2012. CARB adopted a "scoping plan" to reduce greenhouse gas emissions which included a mixed approach of market structures, regulation, fees and voluntary measures. The scoping plan included a cap-and-trade system that covers 85% of all California greenhouse gas emissions. In August 2011, CARB revised the scoping plan in response to litigation. The revised scoping plan continued to include a cap-and-trade program. The scoping plan is required to be updated every five years and the updated scoping plan was approved on May 22, 2014.

On October 20, 2011, CARB adopted a regulation, which was approved on December 13, 2011, implementing a cap-and-trade system. The cap-and-trade regulation became effective on January 1, 2012, and emission compliance obligations under the cap-and-trade regulation began on January 1, 2013. The cap-and-trade program is the largest of its type in the United States and covers sources accounting for 85% of California's greenhouse gas emissions.

The cap-and-trade program is being implemented in phases. The first phase of the program will be implemented from January 1, 2013 to December 31, 2014 and introduces a hard emissions cap that covers emissions from electricity generators, electricity importers, and large industrial sources emitting more than 25,000 metric tons of carbon dioxide-equivalent greenhouse gases per year. In 2015, the program will be expanded to cover emissions from transportation fuels, natural gas, propane, and other fossil fuels. The cap will decline each year until the end of the program, which is currently set as December 2020.

The cap-and-trade program includes the distribution of carbon allowances equal to the annual emissions cap. Initially, as part of the transition process, most of the carbon allowances will be distributed for free. Quarterly auctions for additional allowances began in November 2012. lOUs, as well as POUs that sell electricity into the ISO markets (including some Project Participants), will be required to auction their allowances. They will then need to purchase allowances to meet their compliance obligations, and use the remaining from the sale of their allocated allowances for the benefit of their rate payers.

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On January 1, 2014, the California cap and trade program was linked to the equivalent program in Quebec, Canada as part of the Western Climate Initiative. The Western Climate Initiative is a regional effort consisting of California and four Canadian provinces (Quebec, British Colombia, Ontario, and Manitoba), which have established a greenhouse gas reduction trading framework.

The Authority and the Project Participants are unable to predict at this time the full impact of the cap-and-trade program on the Project Participants' respective electric utilities or on the electric utility industry in general. However, the Project Participants could be adversely affected if the carbon emissions of their respective resource portfolios are in excess of the allowances administratively allocated to them, and they are required to purchase allowances on the market to cover their emissions.

Senate Bill 1368 (SB 1368) became effective as law on January 1, 2007. It provides for an emission performance standard, restricting new investments in baseload fossil fuel electric generating resources that exceed the rate of greenhouse gas emissions for existing combined-cycle natural gas baseload generation. SB 1368 allows the California Energy Commission (CEC) to establish a regulatory framework to enforce the greenhouse gas emission performance standard for POUs such as the Project Participants.

In December 2011, the CEC decided to undertake a review of these regulations to ensure there is adequate review of investments in facilities that do not meet the emission performance standard. The CEC issued its Proposed Final Conclusions in the EPS proceeding on April 5, 2013. The proposed changes and any future changes to the EPS regulations may impact the Project Participants.

In addition, Assembly 1925 signed into law on September 26, 2006, requires the CEC to develop a cost effective strategy for the geologic sequestration and management of industrial carbon dioxide.

Energy procurement and efficiency reporting - Senate Bill 1037, which was signed into law on September 29, 2005, requires that each POU, including the Project Participants, prior to procuring new energy generation resources, first acquire all available energy efficiency, demand reduction, and renewable resources that are cost effective, reliable and feasible, then report annually to its customers and to the CEC its investment in energy efficiency and demand reduction programs. Each Project Participant has complied with such reporting requirements.

Assembly Bill 2021, signed on September 29, 2006, requires that POUs establish, report, and explain the basis of the annual energy efficiency and demand reduction targets every three years for a ten-year horizon since 2007. Each of the Project Participants has complied with this reporting requirement.

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Renewable Portfolio Standard (RPS) - Senate Bill X1 2 (SBX1 2), the "California Renewable Energy Resources Act," was signed into law on April 12, 2011. SBX1 2 codifies the RPS target for retail electricity sellers to serve 33% of their loads with eligible renewable energy resources by 2020 as provided in Executive Order S-14-08. As enacted, SBX 1 2 makes the requirements of the RPS program applicable to POUs. The governing boards of POUs are responsible for implementing the requirements and each POU is required to adopt and implement a renewable energy resources procurement plan. The plan must require the utility to procure a minimum quantity of electricity product from eligible renewable energy resources, including renewable energy certificates ("RECs"), as a specified percentage of total kilowatt hours sold to the utility's retail end-use customers to achieve specific targets. Certain enforcement authority with respect to POUs is given to the CEC and CARB, including authority to impose penalties.

SBX1 2 grandfathers any facility approved by the governing board of a POU prior to June 1, 2010 for procurement to satisfy renewable energy procurement obligations adopted under prior law if the facility is a "renewable electrical generation facility" as defined in the bill (subject to certain restrictions). The CEC has developed detailed rules to implement SXB1 2 and on June 12, 2013, the CEC adopted regulations for the enforcement of the RPS program requirements for POUs.

In connection with the implementation of SBX1 2, the CEC is responsible for certifying the electric generation facilities as "eligible renewable energy resources" for purposes of the RPS program and has adopted guidelines for this purpose that identifies the requirements, conditions and process for certification of facilities as eligible renewable energy resources. The current guidelines identify bio-methane as an eligible renewable energy resource. Under these guidelines adopted on April 30, 2013, utilities that procure bio-methane were required to reapply for certification of the generating facilities that use bio-methane.

Solar power - Senate Bill 1 (also known as the California Solar Initiative), which was signed into law on August 21, 2006, requires POUs, including the Project Participants, to establish a program supporting the stated goal of the legislation to install 3,000 MW of photovoltaic energy in California. POUs are also required to establish eligibility criteria in collaboration with the CEC for the funding of solar energy systems receiving ratepayer-funded incentives. Certain reporting requirements also have to be met by the POUs. Each of the Project Participants has established programs in accordance with the requirements of the California Solar Initiative.

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The effect of these developments in the California energy markets on the Project Participants cannot be fully ascertained at this time. Also, volatility in energy price in California may return due to a variety of factors which affect both the supply and demand for electric energy in the western United States. This price volatility may contribute to greater volatility in the revenues of their respective electric systems from the sale (and purchase) of electric energy and, therefore, could materially affect each Project Participant's financial condition. Each Project Participant undertakes resource planning, risk management activities, and manages its resource portfolio to mitigate such price volatility and spot market rate exposure.

Federal energy legislation - Under the federal Energy Policy Act of 2005 (EPACt 2005), FERC was given refund authority over municipal utilities if they sell into short-term markets, like the ISO markets, and sell eight million MWhs or more of electric energy on an annual basis. In addition, FERC was given authority over the behavior of market participants and the authority to issue permits to construct or modify transmission facilities located in a national interest electric transmission corridor. EPAct 2005 requires the creation of an electric reliability organization (ERO) to establish and enforce, under FERC supervision, mandatory reliability standards to increase system reliability and minimize blackouts. Failure to comply with such mandatory standards exposes a utility to significant fines and penalties by the ERO.

NERC Reliability Standards - EPAct 2005 required FERC to certify an ERO to develop mandatory and enforceable reliability standards, subject to FERC review and approval. On February 3, 2006, FERC issued Order 672, which certified the North American Electric Reliability Corporation (NERC) as the ERO. Many reliability standards have since been approved by FERC. FERC Order 693 further provided ERO and Regional Entities (entities to which NERC has delegated enforcement authority through an agreement approved by FERC) with the discretion to calculate a penalty without collecting the penalty if circumstances warrant Other legislation - Numerous bills have been under consideration in Congress addressing United States energy policies and various environmental matters, including those related to energy supplies (such as a federal clean energy portfolio standard), global warming, cybersecurity, and water quality. Many of these bills, if enacted into law, could have a material impact on the Authority, the Project Participants, and the electric utility industry in general. The Authority and the Project Participants are unable to predict the outcome or potential impacts of any possible legislation at this time.

Environmental issues - Electric utilities are subject to continuing environmental regulation. Federal, state and local standards and procedures which regulate the environmental impact of electric utilities are subject to change. There is no assurance that any Authority or Project Participant facility or project will remain subject to the laws and regulations currently in effect, will always be in compliance with future laws and regulations, or will always be able to obtain all required operating permits. The Authority is unable to predict the outcome of these legal and legislative challenges at this time.

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Greenhouse Gas Regulations Under the Clean Air Act - The United States Environmental Protection Agency (the "EPA") has taken steps to regulate greenhouse gas emissions under existing law. In 2009, the EPA issued a final "endangerment finding," in which it declared that the weight of scientific evidence requires a finding that six identified greenhouse gases, namely, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride, cause global warming, and that global warming endangers public health and welfare. The final rule for the "endangerment finding" was published in the Federal Register on December 15, 2009. As a result of this finding, the EPA considered it was authorized to issue regulations limiting carbon dioxide emissions from, among other things, stationary sources such as electric generating facilities, under the federal Clean Air Act. The "Tailoring Rule," published in the Federal Register on June 3, 2010, states that greenhouse gas emissions will be regulated from large stationary sources, including electric generating facilities, if the sources emit more than the specified threshold levels of tons per year of carbon dioxide. Large sources, with the potential to emit in excess of the applicable threshold, will be subject to the major source permitting requirements under the Clean Air Act. Permits would be required in order to construct, modify, and operate facilities exceeding the emissions threshold. The endangerment finding and the Tailoring Rule have been challenged in court, but were upheld on June 26, 2012. The appealed petition for rehearing was denied on December 2012. Legislation has been introduced in the United States Congress that would repeal the EPA's endangerment finding or otherwise prevent the EPA from regulating greenhouse gases as air pollutants.

On September 22, 2009, the EPA issued the final rule for mandatory monitoring and annual reporting of greenhouse gas emissions from various categories of facilities, including fossil fuel suppliers, industrial gas suppliers and direct greenhouse emitters such as electric generating facilities and industrial processes. This rule does not require controls or limits on emissions, but required data collection to begin on January 1, 2010. The Project Participants are complying with the data collection and reporting requirement to which they are subject. Such data collection and reporting lays the foundation for controlling and reducing greenhouse gas emission in the future, whether by way of the EPA regulation under existing Clean Air Act authority or under a new climate change federal law.

Pursuant to a December 23, 2010 settlement agreement, the EPA proposed on April 13, 2012 to establish New Source Performance Standards limiting carbon dioxide emissions from fossil-fuel fired electric generating units. In response to a June 25, 2013 Presidential Memorandum, the EPA rescinded the April 13, 2012 proposal and re-proposed standards that they stated would apply only to new facilities, not reconstructed or modified facilities. The EPA is required by the Presidential Memorandum to propose by June 1, 2014, and finalize by June 1, 2015, standards, regulations, or guidelines that address carbon pollution from modified, reconstructed and existing power plants.

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The Authority and the Project Participants are unable to predict the outcome of these challenges to the EPA's endangerment finding and subsequent rulemaking or the effect that any final rules promulgated by the EPA regulating greenhouse gas emissions from electric generating units and other stationary sources would have on the Authority's projects or the Project Participants and their respective electric systems.

National Ambient Air Quality Standards - The Clean Air Act requires that the EPA establish National Ambient Air Quality Standards (NAAQS) for certain air pollutants. Once NAAQS have been established, each state must identify areas that do not meet the EPA standard ("non-attainment areas") and develop regulatory measures in its state implementation plan to reduce or control the emissions of that air pollutant in order to meet the applicable standard and become an "attainment area". A proposal to lower the NAAQS for ozone was submitted and withdrawn and the EPA resumed the process of issuing non-attainment designations for the ozone NAAQS under the standard set in 2008. These developments may result in stringent permitting processes for new sources of emissions and additional state restrictions on existing sources of emissions.

Mercury and Air Toxic Standards ("MATS") - On December 16, 2011, the EPA signed a rule establishing new standards to reduce air pollution from coal- and oil-fired power plants under sections 111 (new source performance standards) and 112 (toxics program) of the Clean Air Act. The EPA updated the MATS emission limits on November 30, 2012 and again on March 28, 2013 and is currently reconsidering certain aspects of the regulation. Power plants have up to four years to meet these standards. While many plants meet some or all of these new standards, some plants will be required to install new equipment to meet the standards. The Project Participants purchase power from coal-fired power stations that may be affected by these new rules, and may be exposed to increased costs.

Other Proposals - The EPA has proposed regulations relating to the Coal Combustion Residuals such as ash; Cooling Water Intake Structures at certain existing power plants in order to reduce the number of fish and other aquatic organisms that are trapped against intake screens or drawn into the generating unit; and setting technology-based effluent limitations guidelines and standards for metals and other pollutants in wastewater discharged from steam electric power plants. These regulations, when finalized could increase the cost of power the Project Participants purchase from coal-fired units.

Other factors - The electric utility industry in general has been, or in the future may be, affected by a number of other factors which could impact the financial condition and competitiveness of many electric utilities and the level of utilization of generating and transmission facilities. Such factors, including those discussed above, could have an adverse effect on the financial condition of any given electric utility and likely will affect individual utilities in different ways.

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The Authority is unable to predict what impact such factors will have on the business operations and financial condition of its members but the impact could be significant. Extensive information on the electric utility industry is available from the legislative and regulatory bodies and other sources in the public domain.

Nuclear spent fuel and waste disposal - Under the Nuclear Waste Policy Act, the Department of Energy (DOE) was to develop the facilities necessary for the storage and disposal of spent fuel and to have the first such facility in operation by 1998. DOE collected a fee of 0.1 cents/kwh of electric generation from the nuclear plant operators to fund the development and operation of the disposal facility.

In July 2002, a measure was signed into law designating the Yucca Mountain, in the state of Nevada, as the nation's high-level nuclear waste repository. This meant that the DOE could then file a construction and operation plan for Yucca Mountain with the Nuclear Regulatory Commission (NRC). Due to a series of setbacks including scientific challenges by the National Academy of Science, falsified research data by consultants, and delays in submitting the construction application to the NRC, the operation date of the repository was pushed back several times.

In June 2008, the DOE submitted to the NRC a license application to construct the repository. In 2009, the federal government, under the new administration, decided to cut off all the appropriated funds for the development of the repository at Yucca Mountain, at the urging of the Congress, except a small budget allocation for the closing of the project. The DOE subsequently submitted a request to the NRC to withdraw the license application. The withdrawal request was denied by the NRC due to a lack of valid reasons. Concurrently, an independent commission was formed by the DOE to find a solution for the nuclear waste disposition that would include Yucca Mountain among the different options. There are questions among utilities, as well as public utility commissions nationwide, about the continued collection of disposal fees by DOE for the Nuclear Waste Fund recognizing that there is a lack of spent fuel disposal policy from the federal government. After further contest by the Public Utility Commissions of several states as well as the nuclear operators, the DOE suspended the collection of the 0.1 cents/kwh nuclear waste fee effective May 16, 2014.

The Palo Verde Operating Agent, on behalf of the co-owners, has litigated the DOE to recover the costs of storing spent fuel at Palo Verde because the DOE failed to honor the contract to remove and dispose of spent fuel as scheduled. In 2010, the federal court ruled in favor of Palo Verde and granted a compensation of $30 million which covered costs incurred up to 2006. The Authority's share of the settlement was $1.8 million. Palo Verde continues to pursue cost recovery through the DOE as additional spent fuel related expenses are accumulated for the continued operation of the plant In 2012, Palo Verde filed a claim of $59 million for costs associated with the storage of spent fuel at the plant site for the period 2007-2011. Settlement was reached with the DOE for $57.4 million of which the Authority's share is $3.4 million.

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The spent fuel storage in the wet pool at Palo Verde exhausted its capacity in 2003. A Dry Cask Storage Facility (the Facility), also called the Independent Spent Fuel Storage Installation (ISFSI), was built and completed in 2003 at a total cost of $33.9 million (about $2 million for the Authority). In addition to the Facility, the costs also include heavy lift equipment inside the units and at the yard, railroad track, tractors, transporter, transport canister, and surveillance equipment The Facility has the capacity to store all the spent fuel generated by the Palo Verde plant until 2027. To date, over 117 casks, each containing 24 spent fuel assemblies were placed in the Facility. The original plan called for the annual transfer of about 240 fuel assemblies from the wet pool to the Facility. In the aftermath of the nuclear incident at Fukushima Daiichi Nuclear Station in Japan, following the strong earthquake and subsequent tsunami in 2011, Palo Verde decided to accelerate its campaign to transfer spent fuel from the spent fuel pool to the Facility to relieve the congestion within the pool. The plan in the future is the purchase of new large-capacity casks that were designed to hold 36 assemblies per cask and help to extend the storage capacity of the current Facility possibly until 2047. Storing spent fuel at Palo Verde is now considered indefinite with undetermined costs until spent fuel is removed from the plant site.

Nuclear insurance - The Price-Anderson Act (the Act) requires that all utilities with nuclear generating facilities share in the payment for liability claims resulting from a nuclear incident. The Act limits liability from third-party claims to approximately $12.6 billion per incident Participants in the Palo Verde Nuclear Generating Station (PVNGS) currently insure potential claims and liability through commercial insurance with a $375 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 $127.3 million per operating reactor for each licensee (there are about 100 operating reactors in the U.S.) for each nuclear incident occurring at any nuclear reactor in the United States; payments under the program are limited to $22.51 million per reactor, per incident, per year to be indexed for inflation every five years. Based on the Authority's 5.91% interest in Palo Verde, the Authority would be responsible for a maximum assessment of $22.6 million per incident for all three units, limited to payments of $4.0 million per incident, per year.

In addition to the above, the Authority may be subject to retroactive insurance assessments for its participation in the Neil Property Insurance Program in the amount of $2.5 million.

Other Commitments - The NRC guidelines require improved security in immediate areas surrounding the reactor buildings. PVNGS has enlarged the protected area with the inclusion of an outage support facility, a new warehouse, a minor vehicle maintenance facility, and a fuel depot to reduce vehicular traffic in and out of the protected area. While some of these facilities have already been constructed and are currently in service, the estimated cost for the remaining facilities is approximately $1.1 million to the Authority.

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Other major capital projects that are currently in progress include the digital upgrade of the Generrex generator excitation system, the life extension of the Water Reclamation Facility's clarifiers, the spray pond concrete replacement, the Nuclear Administrative and Technical Manual replacement, and the construction of the Learning Center-In Processing facility. These, along with other regulatory plant modifications, are currently estimated at $230 million which translates to approximately $13.6 million for the Authority. Also anticipated in the long-range plan are $270 million ($16 million for the Authority) worth of capital projects which include the cooling tower life extension long-range plan, upgrades to the high-pressure turbines and electro-hydraulic controls, the replacement of the reactor coolant pumps, Control Element Drive Mechanism Control System (CEDMCS), plant cooling water pipelines, and the Site Work Management System (SWMS).

In response to the nuclear event in Fukushima, Japan, the NRC has required PVNGS to implement the following: increase the redundancy in its power supply to emergency cooling systems, reinforce its spent fuel pool, accelerate the transfer of spent fuel from the pool to the dry cask storage, add pipelines and associated equipment necessary for supplying additional cooling water to the reactors, and upgrade the communication and control system to allow remote access to the plant. To date, the station has purchased additional diesel generators, pumps, hoses, fire trucks and stages at the plant site. It also has access to other emergency equipment stored by the nuclear industry in two facilities in Memphis, Tennessee and Phoenix, Arizona. In addition to these, Palo Verde has allotted approximately $122 million (approximately $7.2 million for the Authority) for Fukushima initiatives which include fuel building modifications, an emergency equipment storage facility, temporary power connections, seismic and flood hazards validation, and corresponding mitigating strategies, among several others. Additional NRC-mandated requirements are anticipated but the costs associated with these future projects are unknown at this time.

Other legal matters - Claims and a lawsuit for damages have been filed with the Authority, Intermountain Power Authority (the IPA), and LADWP seeking $100 million in special damages and a like amount in general damages. An expert report has since been filed alleging that plaintiffs' damages are $250 million. The claimants allege, among other things, that due to improper grounding of the transmission line of STS, their dairy herds were damaged and the value of their land was diminished.

The Authority believed these claims were substantially without merit as to itself because the Authority has no ownership or operational control over the subject transmission lines, and merely acted as a financing agency with respect to STS. SCPPA moved the Utah court to dismiss the action as to SCPPA This motion resulted in the dismissal of certain of the causes of action in the complaint against SCPPA; however, other causes of action still remain. Phase 1 of the trial, limited to the owners of six dairies, began on September 30, 2013, but after 20 trial days ended in a mistrial. A new trial date has not yet been set. No determination can be made at this time whether an unfavorable outcome is probable or remote, nor can an accurate estimate be made of the range of potential loss.

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SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 11 - Commitments and Contingencies (continued)

During May 2010, the California Public Employees Retirement System (CaIPERS) carried out a routine audit of SCPPA's personnel and accounting procedures for compliance with requirements for reporting employee compensation and enrollment of employees as CaIPERS members. The SCPPA audit was carried forth under a standard CaIPERS audit regimen to assess the "Risks" associated with twelve different areas. The conclusion that CaIPERS reached for Risk Item 6 was the only risk item that SCPPA disputed.

Risk Item 6 examined the employment of a retired annuitant under the California Public Employees Retirement Law and determined that the annuitant had exceeded the limitation that prohibits a retired annuitant from working more than 960 hours0.0111 days <br />0.267 hours <br />0.00159 weeks <br />3.6528e-4 months <br /> per year for another CaIPERS contracting agency. The Authority subsequently took steps to satisfy all the corrective measures that CalPers required, including reimbursement of annuity payments made to the annuitant and his spouse during a specified period.

However, on April 23, 2014, CalPers notified the Authority that the reimbursement payment should have been made by the annuitants and not by the Authority. The Authority is currently seeking to resolve this matter through negotiations with CaIPERS. It is not possible to predict when and how this matter might eventually come to a final resolution.

Public Service Company of New Mexico, the operating agent of the SJGS, initiated an action to challenge an administrative order issued by the EPA pursuant to the Federal Clean Air Act requiring installation of pollution controls meeting a "Best Available Retrofit Technology" ("BART") standard to address regional haze.

If the order stands, the cost of the retrofit project could reach $1 billion with approximately $100 million of that being the responsibility of the Authority members who are participants in the project However, discussions about less costly alternatives among the owners and operators of SJGS, the State of New Mexico, and the EPA are ongoing, and the number, range, and likelihood of possible alternative outcomes make it impossible to determine whether an unfavorable outcome for the Authority or its members is probable or remote, and no accurate estimate can be given as to the range of potential costs at this time.

)

The Authority is also involved in various other legal actions. In the opinion of management, the outcome of such litigation or claims will not have a material effect on the financial position or the results of operations of the Authority or the respective separate Projects.

109

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS Note 12 - Restatement With the implementation of GASB 65, the Authority restated the 2013 financial statements to conform to the 2014 financial statements and expensed debt issuance costs which were previously being amortized over the life of the related bonds.

Unamortized bond issue costs of $47,679,000 at the beginning of fiscal year 2013 are included as part of the cumulative effect of the restatement and reduce the beginning net position. The total impact on the statement of net position at June 30, 2013 includes a decrease in noncurrent assets of $43,467,000 and a decrease in net investment in capital assets of $4,212,000.

The total impact on the statement of revenues, expenses and changes in net position for the year ended June 30, 2013 includes an increase in the change in net position of $4,212,000 due to the elimination of related amortization. This restatement results in a cumulative effect of $47,679,000 that decreases beginning net position at July 1, 2012. Ending net position as of June 30, 2013 decreased from

$(63,532,000) to $(106,999,000) as restated.

GASB 65 also restricts the use of the term "deferred" to only those items designated as deferred outflows or deferred inflows of resources by GASB Statement No. 63 and GASB 65. Loss on refunding was appropriately reclassified as a deferred outflow of resources. This reclassification has no impact on total net position.

Note 13 - Subsequent Events Columbia Two Solar Project - On September 19, 2013 SCPPA entered into a power purchase agreement with RE Columbia Two, LLC to purchase all of the Facility Output of the Columbia Two Project (the "Facility"), and to acquire other rights and resources, including but not limited to the purchase option and the rights under other ancillary agreements associated with the Facility. The Facility, when fully developed, is contemplated to entail a photovoltaic solar power generating facility located in Kern County, California with an expected nameplate capacity of 15 MW. The planned Commercial Operation Date is December 20, 2014. The term of the contract is 20 years. The city of Riverside is the scheduling coordinator on behalf of the project participants.

110

SUPPLEMENTAL INFORMATION SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY PALO VERDE PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

Decom- General Debt Service missioning Escrow Reserve Issue Operating Reserve & Revenue Fund Trust Fund Account Account Account Account Contingency Fund Total Balance at June 30, 2013 $ $ 168,005 $ 186,630 $ 1,305 $ 12,946 $ 42,998 $ 19,286 $ $ 431,170 Additions Investment earnings 2,196 26,099 13 4 1,331 141 29,784 Discount on investment purchases 1 1 1 3 Distribution of investment earnings (13) (5) (99) (142) 259 Revenue from power sales - - - 75,291 75,291 Distribution of revenue 11,426 51,939 12,185 (75,550)

Transfer from escrow 32,699 (50,083) 17,384 - -

Total additions 32,699 2,196 (23,984) 28,810 53,172 12,185 105,078 Deductions Construction expenditures - - 13,905 13,905 Operating expenditures 3 39,630 - 39,633 Fuel costs 14,541 14,541 Payment of principal 10,980 10,980 Interest paid - non-escrow - 275 275 Payment of principal and interest- escrow 32,699 - 17,384 - - 50,083 Total deductions 32,699 3 28,639 54,171 13,905 129,417 Balance at June 30, 2014 $ - $ 170,198 $ 162,646 S 1,305 $ 13,117 $ 41,999 $ 17,566 $ $ 406,831 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $34 held in the revolving fund at June 30, 2014 and 2013.

111

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY SAN JUAN PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

Debt Service Reserve &

Debt Service Reserve Operating Contingency Escrow Fund Account Revenue Fund Fund Fund Account Total Balance at June 30, 2013 $ 2,547 $ 21,323 $ $ 11,435 $ 11,324 $ 1,933 $ 48,562 Additions Investment earnings 3 733 5 57 20 818 Discount on investments 6 - 3 8 - 17 Distribution of investment earnings (8) (733) 814 (8) (65)

Revenue from power sales - - 86,764 - - 86,764 Distribution of revenues 23,568 (87,578) 61,358 2,652 -

Other 13,524 (13,524) 489) - 489 Total additions 37,093 (13,524) 60,869 2,652 509 87,599 Deductions Operating expenses 58,591 - - 58,591 Construction expenses - - - 1,681 - 1,681 Payment of principal 27,250 - - - 27,250 Interest paid - non-escrow 5,093 - - - - 5,093 Total deductions 32,343 - 58,591 1,681 92,615 Balance at June 30, 2014 $ 7,297 $ 7,799 $ $ 13,713 $ 12,295 $ 2,442 $ 43,546 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments or $19 held in the revolving fund at June 30, 2014 and 2013.

112

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MAGNOLIA POWER PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS) ueom Debt Service Operating General Service Reserve Project Reserve Reserve & Operating Revenue Reserve Account Account Fund Fund Contingency Fund Fund Fund Escrow Fund Total Balance at June 30, 2013 $ 9,906 $ 34,223 $ 4,202 $ 4,926 $ 19,265 $ 6,318 $ $ 9,612 $ 269,789 $ 358,241 Additions Investment earnings 4 465 14 49 92 6 29 341 1,000 Discount on investment purchases 4 1 -15 i 2 - 22 Distribution of investment earnings (8) (466) (49) (107) (6) 636 - -

Transfer of funds for debt service payment 270,130 - - - - - (270,130)

Receipt from participants - - 54,969 54,969 Distribution of revenues 22,970 6,996 25,680 (55,605) (41)

Other 9,587 (5,399) (4,188) - - - -

Total additions 302,687 (5,399) (4,174) 6,996 25,680 (10) (269,789) 55,991 Deductions Construction expenses 920 - 920 Operating expenses - - 25,900 25,900 Payment of principal 15,605 - 15,605 Interest paid 12,100 12,100 Payment of principal and interest - escrow 270,130 - 270,130 Total deductions 297,835 - - - 920 25,900 324,655 Balance at June 30,2014 $ 14,758 $ 28,824 $ 28 $ 4,926 $ 25,341 $ 6,098 $ $ 9,602 $ $ 89,577 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $28 held in the revolving fund at June 30, 2014 and 2013.

113

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY CANYON POWER PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2014 (AMOUNTS IN THOUSANDS)

Operating Debt Service Debt Service U.S. Treasury Revenue Fund Fund Fund Reserve Fund Project Fund Direct Subsidy Total Balance at June 30, 2013 $ $ 606 $ 7,414 $ 19,721 $ 11,379 $ 1,809 $ 40,929 Additions Investment earnings 1 4 275 10 - 290 Discount on investment purchases 2 4 6 Distribution of investment earnings 282 (1) (6) (275) - -

Receipt from participants 16,033 - - - - - 16,033 Distribution of revenues (16,315) 3,487 16,475 - (3,647) -

Other - - - 1,838 1,838 Total additions 3,487 16,475 - 14 (1,809) 18,167 Deductions Construction expenses - - 7,032 - 7,032 Operating expenses 2,416 - - 2,416 Interest paid - 16,732 - - 16,732 Total deductions 2,416 16,732 - 7,032 - 26,180 Balance at June 30, 2014 $ $ 1,677 $ 7,157 $ 19,721 $ 4,361 $ - $ 32,916 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable or unrealized gain (loss) on investments, or $19 held in the revolving fund at June 30, 2014 and 2013.

114

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY APEX POWER PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2014 (AMOUNTS IN THOUSANDS)

Reserve &

Operating Debt Service Debt Service Contingency Cost of Revenue Fund Fund Fund Reserve Fund Fund Project Fund Issuance Fund Total Balance at June 30, 2013 Additions Investment earnings 1 1 2 Discount on investment purchases 3 3 Distribution of investment earnings 1 (1)- ---

Receipt from participants 27,836 - - - 27,836 Distribution of revenues (27,837) 23,509 3,327 - 1,001 - -

Bond proceeds 2014 A&B - - 5,488 - 326,032 2,352 333,872 Other - 173 - - - - - 173 Total additions - 23,682 3,327 5,488 1,001 326,036 2,352 361,886 Deductions Acquisition costs - 296,120 296,120 Operating expenses - 6,252 - - 6,252 Debt issuance costs - - - 2,294 2,294 Total deductions - 6,252 - - - 296,120 2,294 304,666 Balance at June 30, 2014 $ - $ 17,430 $ 3,327 $ 5,488 $ 1,001 $ 29,916 $ 58 $ 57,220 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable and unrealized gain (loss) on investments at June 30, 2014.

115

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY HOOVER UPRATING PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

General Reserve

• Debt Service Fund Fund Operating Fund Revenue Fund Total Balance at June 30, 2013 $ 1,440 $ 1,700 $ 1,281 $ $ 4,421 Additions Investment earnings 17 4 5 26 Distribution of investment earnings (17) (4) 21 -

Revenue from power sales 2,583 2,583 Distribution of revenue 2,250 359 (2,609) -

Total additions 2,250 359 2,609 Deductions Operating expenses 308 - 308 Payment of principal 1,755 - 1,755 Interest paid 455 _ - 455 Total deductions 2,210 - 308 - 2,518 Balance at June 30, 2014 $ 1,480 $ 1,700 $ 1,332 $ $ 4,512 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $15 held in the revolving fund at June 30, 2014 and 2013.

116

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY TIETON HYDROPOWER PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

Reserve &

Debt Service Debt Service Contingency General Reserve Revenue Fund Operating Fund Fund Reserve Fund Fund Fund Total Balance at June 30, 2013 $ - $ 609 $ 2,074 $ 5,008 $ 500 $ 24 $ 8,215 Additions Investment earnings 1 66 2 69 Distribution of investment earnings 69 (1) (66) (2) -

Receipt from participants 4,459 - - - -- 4,459 Distribution of revenues (4,528) 1,169 3,360 - - 1 Other receipts 155 - - 155 Total additions 1,324 3,360 - 4,684 Deductions Acquisition costs - 81 - 81 Operating expenses - 1,177 - - - 1,177 Payment of principal - - 790 - - 790 Interest paid - - 2,556 - - 2,556 Total deductions - 1,258 3,346 - - - 4,604 Balance at June 30, 2014 $ - $ 675 $ 2,088 $ 5,008 $ 500 $ 24 $ 8 295 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $9 held in the revolving fund at June 30, 2014 and 2013.

117

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MILFORD 1 WIND PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

General Operating Revenue Operating Debt Service Debt Service Reserve Reserve Fund Fund Fund Reserve Fund Fund Fund Total Balance at June 30, 2013 $ 8,212 $ 13,505 $ 18,874 $ 2,520 $ 3,000 $ 46,111 Additions Investment earnings 6 4 233 35 32 310 Discount on investments 7 4 11 Distribution of investment earnings 321 (13) (8) (233) (35) (32)

Receipt from participants 30,544 30,544 Distribution of revenues (30,865) 11,992 18,873 Other 643 643 Total additions 12,635 18,873 31,508 Deductions Operating expenses 12,133 12,133 Payment of principal 8,135 8,135.

Interest paid 10,581 10,581 18,716 Total deductions 12,133 30,849 Balance at June 30, 2014 $ $ 13,662 $ 18,874 $ 2,520 $ 3,000 $ 46,770 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $9 held in the revolving fund at June 30, 2014 and 2013.

118

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MILFORD 2 WIND PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

Debt Service Debt Service Revenue Fund Operating Fund Fund Reserve Fund Total Balance at June 30, 2013 $- $ 7,863 $ 8,963 $ 3,216 $ 20,042 Additions Investment earnings 7 1 43 51 Discount on investments - 8 4 - 12 Distribution of investment earnings 63 (15) (5) (43)

Receipt from participants 16,508 - - 16,508 Distribution of revenues (16,571) 3,706 12,865 -

Total additions 3,706 12,865 16,571 Deductions Operating expenses - 5,647 - 5,647 Payment of principal - 5,065 5,065 Interest paid _ - 7,696 7,696 Total deductions - 5,647 12,761 18,408 Balance at June 30, 2014 $ - $ 5,922 $ 9,067 $ 3,216 $ 18,205 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $9 held in the revolving fund at June 30, 2014 and 2013.

119

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY WINDY POINT PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

Debt Service Debt Service Revenue Fund Operating Fund Fund Reserve Fund Total Balance at June 30, 2013

$ $ 6,979 $ 29,446 $ 10,262 $ 46,687 Additions Investment earnings 1 5 26 176 208 Discount on investments 1 9 10 Distribution of investment earnings 217 (7) (34) (176)

Receipt from participants 79,488 79,488 Distribution of revenue (79,706) 38,664 41,042 Total additions 38,663 41,043 79,706 Deductions Operating expenses 38,077 38,077 Payment of principal 17,850 17,850 Interest paid 22,850 22,850 Total deductions 38,077 40,700 78,777 Balance at June 30, 2014 $ $ 7,565 $ 29,789 $ 10,262 $ 47,616 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $9 held in the revolving fund at June 30, 2014 and 2013.

120

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY LINDEN WIND ENERGY PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

Debt Service Debt Service General U.S. Treasury Revenue Fund Operating Fund Fund Reserve Fund Reserve Fund Project Fund Direct Subsidy Total Balance at June 30, 2013 $ - $ 4,403 $ 6,448 $ 2,324 $ 69 $ 583 $ 394 $ 14,221 Additions Investment earnings 2 2 23 27 Discount on investments 5 3 2 10 Distribution of investment earnings 35 (7) (5) (23) -

Revenue from power sales 17,292 - - - 17,292 Distribution of revenue (17,327) 8,022 9,305 - -

Other transfers - 793 (793)

Other receipts - - - 399 399 Total additions 8,022 10,098 2 (394) 17,728 Deductions Operating expenses - 9,836 - - 9,836 Payment of principal - - 2,460 - 2,460 Interest paid - - 7,642 - 7,642 Total deductions - 9,836 10,102 - 19,938 Balance at June 30, 2014 $ - $ 2,589 $ 6,444 $ 2,324 $ 69 $ 585 $ - $ 12,011 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $12 held in the revolving fund at June 30, 2014 and 2013.

121

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY SOUTHERN TRANSMISSION SYSTEM PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

Upgrade General Reserve Construction Fund Issue Fund Fund Operating Fund Revenue Fund Total Balance at June 30, 2013 $ 7,130 $ 82,763 $ 8,267 $ 3,619 $ - $ 101,779 Additions Investment earnings 16 703 20 3 1 743 Discount on investment purchases 1 38 8 S- 47 Distribution of investment earnings (23) (741) (3) 767 Revenue from transmission sales - 112,691 112,691 Distribution of revenue (4,030) 85,581 31,908 (113,459)

Total additions (4,036) 85,581 28 31,908 113,481 Deductions Construction expenses 91 - 91 Operating expenses - - 35,406 35,406 Payment of principal - 49,130 - - 49,130 Interest paid - 32,721 - 32,721 Debt issuance costs 215 - 215 Premium and interest on investment purchases (5] (5)

Total deductions (5) 82,066 91 35,406 117,558 Balance at June 30, 2014 $ 3,099 $ 86,278 $ 8,204 $ 121 $ $ 97,702 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $25 held in the revolving fund at June 30, 2014 and 2013.

122

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MEAD-PHOENIX PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

Debt Service Reserve &

Debt Service Reserve Operating Contingency Cost of Revenue Fund Account Account Fund Fund Issuance Fund Total Balance at June 30, 2013 $ - $ 1,473 $ 5,675 $ 185 $ 176 $ $ 7,509 Additions Investment earnings 2 196 - 8 206 Distribution of investment earnings 205 (2) (196) (7)

Transmission revenue 8,524 8,524 Distribution of revenues (9,079) 12,875 (5,675) 1,632 (124) 371 Other 350 350 Total additions 12,875 (5,6751 1,632 (123) 371 9,080 Deductions Operating expenses 1,510 - - 1,510 Construction expenses - - - 53 - 53 Principal payment - 6,505 - - 6,505 Interest and SWAP paid - 1,816 - - - 1,816 Total deductions - 8,321 1,510 53 - 9,884 Balance at June 30, 2014 $ - $ 6,027 $ $ 307 $ - $ 371 $ 6705 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $15 held in the revolving fund at June 30, 2014 and 2013.

123

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MEAD-ADELANTO PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

Debt Service Revenue Debt Service Reserve Operating Reserve & Escrow Surplus Fund Account Fund Fund Contingency Fund Fund Total

$ 16,267 Balance at June 30, 2013 $ 4,713 $ 25 $ 6,131 $ - $ 1 $ 27,137 Additions Investment earnings 16 597 225 7 846 Discount on investment earnings Distribution of investment earnings 835 (6) (597) (225) (7)

Transmission revenue 25,736 25,736 Distribution of revenues (27,771) 39,864 (16,267) 2,708 (6,089) 7,555 Other 1,200 1,200 Total additions 39,874 (16,2671 2,709 (6,089) 7,555 27,782 Deductions Principal payment 17,820 - 17,820 Interest & SWAP paid 6,427 - 6,427 Operating expenses 2,392 - 2,392 Total deductions 24,247 2,392 - 26,639 Balance at June 30, 2014 $ - $ 20,340 $ - $ 342 $ 42 $ $ 7556 $ 28,280 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $15 held in the revolving fund at June 30, 2014 and 2013.

124

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NATURAL GAS PINEDALE PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2014 (AMOUNTS IN THOUSANDS)

Debt Service General Revenue Fund Operating Fund Fund Reserve Fund Project Fund Capital Fund Total Balance at June 30, 2013 $ $ 7,905 $ 3,051 $ 38 $ 3,031 $ 10,016 $ 24,041 Additions Investment earnings 7 1 2 14 24 Discount on investment purchases 2 1 2 5 Distribution of investment earnings 1- (1)

Receipt from participants 4,471 8,826 13,297 Sales of natural gas 1,452 14,530 15,982 Distribution of revenues (5,924) 3,322 3,708 2 (1,108)

Other transfer (335) 335 Total additions 26,687 3,708 (330) (757) 29,308 Deductions Construction expenses - - 3,516 3,516 Operating expenses - 26,789 - - 26,789 Payment of principal - - 2,253 2,253 Interest paid - - 1,538 - 1,538 Total deductions - 26,789 3,791 - 3,516 34,096 Balance at June 30, 2014 $ - $ 7,803 $ 2,968 $ 38 $ 2,701 $ 5,743 $ 19,253 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $37 held in the revolving fund at June 30, 2014 and 2013.

125

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NATURAL GAS BARNETT PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2014 (AMOUNTS IN THOUSANDS)

Debt Service General Revenue Fund Operating Fund Fund Reserve Fund Project Fund Capital Fund Total Balance at June 30, 2013 $ - $ 2,182 $ 7,169 $ 22 $ 39,875 $ (5,914) $ 43,334 Additions Investment earnings 2 2 242 246 Discount on investment purchases 3 1 4 Distribution of investment earnings 4 (4)

Receipt from participants 10,529 255 10,784 Sales of natural gas 4,831 1,074 5,905 Distribution of revenues (15,364a 6,317 8,715 (439) 771 Total additions 7,648 8,716 (196) 771 16,939 Deductions Construction expenses - - 536 536 Operating expenses - 6,636 - - - - 6,636 Payment of principal - - 5,302 - - 5,302 Interest paid - - 3,619 - - - 3,619 Total deductions - 6,636 8,921 - - 536 16,093 Balance at June 30, 2014 $ - $ 3,194 $ 6,964 $ 22 $ 39,679 $ (5,679) $ 44,180 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $19 held in the revolving fund at June 30, 2014 and 2013.

126

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY PREPAID NATURAL GAS PROJECT No. 1 SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2014 (AMOUNTS IN THOUSANDS)

Revenue Fund Operating Fund Debt Service Fund Total Balance at June 30, 2013 $ $ 10,268 $ 7,173 $ 17,441 Additions 488 Investment earnings 203 691 Distribution of investment earnings 483 (483)

Receipt from gas sales 8,614 8,614 Distribution of revenues (21,683) 5,677 16,006 Commodity swap settlement 9,186 9,186 Other receipts 3,400 844 591 4,835 Total additions 6,526 16,800 23,326 Deductions A & G expenses 1,632 1,632 Payment of principal 4,065 4,065 Payment of interest 16,647 16,647 Total deductions 1,632 20,712 22,344 Balance at June 30, 2014 $ 15,162 $ 3,261 $ 18,423 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investments, or $19 held in the revolving fund at June 30, 2014 and 2013.

127

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MULTIPLE PROJECT FUND SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30,2014 (AMOUNTS IN THOUSANDS)

Debt Service Proceeds Account Account Earnings Account Total Balance at June 30, 2013 $ 39,197 $ $ - $ 39,197 Additions Investment earnings 1,441 - 1,441 Distribution of investment earnings (1,441) 1,441 Transfer for debt service payment (12,825) 12,825 Transfer fund to other projects (26,372) - - (26,372)

Total additions (39,197) 14,266 - (24,931)

Deductions Interest paid 466 - 466 Payment of principal 13,800 - 13,800 Total deductions 14,266 14,266 Balance at June 30, 2014 $ $ - $ - $

This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and has been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable.

128

- ------- Sa"Ula t SURVEY CONTACTS: Persons to contact with question about this form RESPONSE DUE DATE: Please submit by April 30th following the close of calendar year Contact Than Aung REPORT FOR: Los Angeles Department of Water & Power 11208

Title:

Associate Elect Engineer REPORTING PERIOD: 2013 Phone: (213) 367-3367 FAX: (213) 367-3367 Email: thaiag@ladwp.com Logged By/ Date:

Supervisor Pjoy Chua Logged In: Li Receipt Date (mm/dd/yyyy):

Title:

Electrical Engineer Phone: (213) 367-1750 FAX: Email: pjoy.chua@ladwp.com I Legal Name of Industry Participant Los Angeles Department of Submission Status/Date: I Re-Submitted 1 1 08/07/2014 Water & Power Current Address of Principal Business P 0 Box 51111, JFB Rm 445 2

Office Los Angeles CA 90051 0000 Preparer's Legal Name Operator 3 (if different than line I) 4 Current Address of Preparer's Office (if different than line 2)

-] Federal Li State E Transmission EL Political Subdivision Municipal 5 Respondent Type (Check One)

[] Municipal Marketing Authority D Investor-Owned Li Cooperative Retail Power Marketer (or Energy Service Provider)

L Independent Power Producer Wholesale Power Marketer or Qualifying Facility For questions or additional information about the Form EIA-861 contact the Survey Manager: Fax: (202) 287 - 1938 Email: EIA-861@eia.gov Jorge Lona-Camara Phone: (202) 586-3945 jorge.luna-camara@eia.gov Stephen Scott Phone: (202) 586-5140 Email: stephen.scott@eia.gov 02 September 2014 Page I of 21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 Regional North American Electric Reliability Council LINE NO.

TRE (formerly NPC C El SP]

Regional North American Electric Reliability Council ERCOT)

(Not applicable for power marketers) (formerly ECAR, MAIN. MAAC) [ WECC FRCCRF MRO LZ SE] RC California ISO I Southwest Power Pool 2 Name of RTO or ISO F] Electric Reliability Council of Texas I Midwest ISO

-E PJM Interconnection ISO New England New York ISO L None 3 (For EIA Use Only) Identify the North American Electric WECC Reity Council where you are physically located 4 Did Your Company Operate Generating Plants(s)?

x] Yes E No LX Generation from company owned plan t LI] Buying distribution on other electrical system Identify The Activities Your Company Was Engaged [x] Transmission rx Wholesale power marketing 5 In During The Year Buying transmission services on other Z_] Retail power marketing (Check appropriate activities) electrical system Distribution using owned/leased [j] Bundled Services (electricity plus other services electric wires such as gas, water, etc. in addition to electric service))

Summer (Megawatts) 5,862.0 Prior Year 5,782.0 6 Highest Hourly Electrical Peak System Demand Winter (Megawatts) 3,854.0 Prior Year 3,887.0 Did Your Company Operate Altemative-Fueled Vehicles X Yes 7 During the Year? LNo Does Your Company Plan to Operate Such Vehicles

[xi Yes LNo During the Coming Year?

Name: Scott Briasco If "Yes", Please Provide Additional Contact Information

Title:

Fleet Engineering Supervisor Telephone: 213 - 367 - 8406 Fax: - - Email: Scott.Briasco@ladwp.com 02 September 2014 Page 2 of 21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 SOURCE OF ENERGY MEGAW) ATTHOURS _ jDISPOSITION OF ENERGY MEGAWATTHOURS I Net Generation 23,984,015 11 Sales to Ultimate Consumers 23,321,731 2 Purchases from Electricity Suppliers 3,885,656 12 Sales For Resale 971,180 3 Exchanged Received (In) 13 Energy Furnished Without Charge 4 Exchanged Delivered (Out) 824,437 14 Energy Consumed By Respondent Without Charge 120,000 5 Exchanged Net -824,437 6 Wheeled Received (In) __ 21,169,311 7 Wheeled Delivered (Out) 20,777,478 15 Total Energy Losses (positive number) 2,150,271 I i 8 Wheeled Net 391,833 9 Transmission by Others Losses

-873,885 (Negative Number) 10 Total Sources (sum oflines 1, 2, 5, 8 & 9) 26,563,182 1 16 Total Disposition (sum of lines 11, 12, 13, 14, & 15) 26,563,182 02 September 2014 Page 3 of 21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 LINE TYPE OF OPERATING REVENUE (THOUSAND DOLLARS to the nearest 0.1)

NO.

Electrical Operating Revenue From Sales to Ultimate Customers (Schedule 4: Parts A, B, and D) 3,035,540.7 2 Revenue From Unbundled (Delivery) Customers

.0 (Schedule 4: Part C) 3 Electric Operating Revenue from Sales for Resale

$ 31,230.7 4 Electric Credits/Other Adjustments 5 Revenue from Transmission

• 1-6 Other Electric Operating Revenue Total Electric Operating Revenue (sum of lines 1, 2, 3, 4, 5 and 6) 1..

3,066,771.4 I-02 September 2014 Page 4 of 21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 State CA I Total Number of Distribution Circuits 2,273.0 2 Number of Distribution Circuits that employ voltage/VAR optimization 1,662.0 (wO) 02 September 2014 Page 5 of 21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 Who Is required to complete this schedule?

This schedule collects System Average Interruption Frequency Index (SAIFI) and System Average Interruption Duration Index (SAIDI) statistics. If your organization does not compute these indexes, answer 'no' to Question I and then skip to Schedule 4A. You do not have to complete any other part of this schedule 3B or 3C.

Should you complete Part B or Part C?

If your organization computes the SAIFI and SAIDI indexes and determines Major Event Days using the IEEE 1366-2003 or the IEEE 1366-2012 standard, answer 'YES' to Questions I and 2, and complete Part B. Then skip to Schedule 4A. (You do not complete Schedule 3, Part C.)

If your organization does not use the IEEE 1366-2003 or the IEEE 1366-2012 standard but calculates SAIDI and SAIFI indexes via other method, answer 'yes' to question I and 'no' to question 2 and complete Part C. Then go to Schedule 4A.

I Do you calculate SAIDI and SAIFR by any method? If Yes, go to Question 2. If No, go to Schedule 4, Part A. F] Yes 1] No 2 Do you calculate SAIDI and SAlFI and determine Major Event Days using the IEEE1366-2003 standard or IEEEE-20l2 standard? IfYesýcomplete Part B. If No, go to [j] Yes 7 No state CA 3a. SAIDI value including Major Event days 65.000 3b. SAIDI value excluding Major Event days 65.000 4 SAIDI value including Major Event days minus loss of supply 5a. SAIFI value including Major Event days .450 5b. SAIFI value excluding Major Event days .450

6. SAIFI value including Major Event days minus loss of supply

7. Total number of customers used in these calculations 1,596,912.0

8. What is the highest voltage that you consider part of the distribution system, as opposed to the supply system? (kV) 34.5

9. Is information about customer outages recorded automatically? K] Yes [] No Thank You for completing this part. Skip Part C and go directly to Schedule 4 Part A.

02 September 2014 Page 6 of 21

REPORT FOR: Los Angeles Department of Water & Power REPORT PERIOD ENDING:

State lOa. SAIDI value including Major Events 10b. SAIDI value excluding Major Events I Ia. SAIFI value including Major Events 1ib. SAIFI value excluding Major Events

12. Total number of customers used in these calculations

13. Do you include inactive accounts? DYes [] No

14. How do you define momentary interruptions 7 Less than I min. n Less than Smin. ] Other

15. What is the highest voltage that you consider part of the distribution system, as opposed to the supply system? kv

16. Is information about customer outages recorded automatically?

EJYes 7No 02 September 2014 Page 7 of 21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 bruteI CA RESIDENTIAL CUMMMRCIAL INDUSTRIAL TRANSPOTKATION IoIAL Balancing Authority 11208 Los Angeles Department of Water an. (a) (b) (c) (d) (e)

Revenue (thousand dollars) 1,072,772.2 1,711,581.3 239,712.7 11,474.5 3,035,540.7 Megawatthours 7,584,799 13,487,079 2,166,798 83,055 23,321,731 Number of Customers 1,287,217 85,899 8,494 2 1,381,612 Axe your rates decoupled? [j] Yes EJ No [W Yes EINo WYes [:No Yes LINo If the answer is YES, is the revenue adjustment automatic or does it require ] automatic automatic W automatic automatic a rate-making proceeding?

7l proceeding proceeding []proceeig U proceeding Cents/Kwh 14.144 12.691 11.063 13.816 13.016 state Revenue (thousand dollars)

Megawatthours Number of Customers Axe your rates decoupled?

if the answer is YES, is the revenue adjustment automatic or does it require a rate-making proceeding?

Cents/Kwh Total Revenue (thousand dollars) 1,072,772.2 1,711,581.3 239,712.7 11,474.5 3,035,540.7 Megawatthours 7,584,799 13,487,079 2,166,798 83,055 23,321,731 Number of Customers 1,287,217 85,899 8,494 2 1,381,612 02 September 2014 Page 8 of 21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 RESIDENTIAL COMMERCIAL INDUSTRIAL TRANSPORTATION TOTAL (a) (b) (c) (d) (e)

State Revenue (thousand dollars)

Megawatthours Number of Customers Cents/Kwh State Revenue (thousand dollars)

Megawatthours Number of Customers Cents/Kwh Total Revenue (thousand dollars)

Megawatthours Number of Customers 02 September 2014 Page 9 of 21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 RESIDENTIAL COMMERCIAL INDUSTRIAL TRANSPORTATION TOTAL (a) (b) (c) (d) (e)

State Revenue (thousand dollars)

Megawatthours Number of Customers Cents/Kwh State Revenue (thousand dollars)

Megawatthours Number of Customers Cents/Kwh Total Revenue (thousand dollars)

Megawatthours Number of Customers REPORT FOR: Los Angeles Department of Water & Power 11208 02 September 2014 Page 10 of 21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 RESIDENTIAL COMMERCIAL INDUSTRIAL TRANSPORTATION TOTAL (a) (b) (c) (d) (e)

State Revenue (thousand dollars)

Megawatthours Number of Customers Cents/Kwh State Revenue (thousand dollars)

Mcgawatthours Number of Customers Cents/Kwh Total Revenue (thousand dollars)

Megawatthours Number of Customers 02 September 2014 Page I11of 21

REPORT FOR: Los Angeles Department of Water & Utility Id 11208 Power REPORTING PERIOD: 2013 Mergers and/or acquisitions during the reporting month If Yes, Provide:

Date of Merger or Acquisition Company merged with or acquired Name of new parent company Address city state, ZIp New Contact Name Telephone No.

Email address 02 September 2014 Page 12 of 21!

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 State CA Balancing Authority 11208 Los Angeles Department of Water and Power RESIDENTIAL COMMERCIAL INDUSTRIAL TRANS Total (a) (b) (c) (d) (e)

I Energy Savings (MWh) 17,470 181,366 0 0 198,836 2 Peak Demand Savings (MW) 3.0 24.0 0.0 0.0 27.0 3 Energy Savings (MWh) 209,951 2,687,253 0 0 2,897,204 4 Peak Demand Savings (MW) 3.0 24.0 0.0 0.0 27.0 5 Customer Incentives 6,725 19,433 0 0 26,158 6 All other costs 6,574 17,122 0 0 23,696 7 Customer Incentives 6,726 19,433 0 0 26,159 8 All other costs 6,726 19,433 0 0 26,159 9 Weighted Average Life 12.000 15.000 Please provide website address to your energy efficiency program reports:

02 September 2014 Page 13 of 21

REPORT FOR: Los Angeles Department ofWater & Power 11208 REPORT PERIOD ENDING: 2013 (e)

Residential Commercial Industrial Transportation Total State CA Balancing Authority 11208 Los Angeles Department of Water and Power I Number of Customers Enrolled 0 4 3 0 7 2 Energy Savings (Mwh) 0 74 193 0 267 3 Potenetial Peak Demand Savings (MW) 0.0 12.3 32.2 0.0 44.5 4 Actual Peak Demand Savings (MW) 0.0 6.2 16.1 0.0 22.3 5 Customer Incentives 0 12 32 0 44 6 All other costs 0 0 0 0 0

If you have a demand side management (DMS) program for grid-interactive water heaters (as defined by DOE), how many grid interactive water heaters were added to 7 your program this year?

02 September 2014 Page 14 of21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 INSTRUCTIONS: Report the number of customers participating in dynamic pricing programs, e.g. Time-of-Use-Pricing, Real-Time-Pricing, Variable Peak Pricing, Critical Peak Pricing Programs.

State CA Balancing Authority 11208 Los Angelea Department of Water and Power Residential Commercial Industrial Transportatio Total (a) (b) (c) (d) (e)

Number of Customers enrolled in dynamic pricing programs, by customer 6,063 17,474 1,879 0 25,416 class INSTRUCTIONS: For each customer class, mark the types of dynamic pricing programs in which the customer are participating.

Residential Commercial Industrial Transportatio (a) (b) (c) (d) 2 Time-of-Use Pricing Yes [] No Yes D No [x]Yes [] No Yes[ No Real True Pricing 3 [] Yes [x] No D1 Yes F]No [IYes L] No DYes [] No 4 Variable Peak Pricing E] Yes XNo LII Yes [X]No DYes X No [Yes W No 5 Critical Peak Pricing Yes No [] Yes [x No oYes Y No []Yes [ No 6 Critical Peak Rebate Yes No 1Yes XNo 11jY- XNo ]Yea X No 02 September 2014 Page 15 of 21

REPORT FOR Los Angeles Department of Water & Po, 11208 REPORT PERIOD ENDING 2013

1. 007WIA 6, #Or D' AýV Only customers from schedule 4A and 4C need to be reported on this schedule.

AMR- data transmitted one-way, to the utility.

AMI- data transmitted in both directions, to the utility and customer State CA Balancing Authority 11208 Los Angeles Department of Water and Power Residential Commercial Industrial Transportation Total (a) (b) (c) (d) (e)

I Number of AMR Meters 269,930 52,071 4,938 77 327,016 2 Number of AMI Meters 2,964 4,381 776 51 8,172 3 Number of AMI Meters with hor ne 0 0 0 0 0 area network (HAN) gateway enabled 4 Number of non AMR!AMI Meteors 1,196,527 73,184 6,858 69 1,276,638 5 Total Number of Meters 1,469,421 129,636 12,572 197 1,611,826 (All Types), line 1+2+4 6 Energy Served Through AMI 171,358 3,898,900 931,066 71,627 5,072,951 Number of Customers able to ac*

2,964 4,381 776 51 8,172 7 daily energy usage through a webmortad or other electronic means 8 Number of customers with direct tload 0 0 0 0 0 control 02 September 2014 Page 16 of 21

REPORT FORLos Angeles Department of Water & Povi 11208 REPORT PERIOD ENDING 2013 Net Metering program allow customers to sell excess power they generate back to the electrical grid to offset consumption. Provide the information about programs by Statem balancing authority, customer class, and technology for all net metering applications.

State CA Balancing Authority 11208 Los Angeles Department of Water and Power Residential Commercial Industrial Transportation Total (a) (b) (c) (d) (e)

Installed Net Metering Capacity (MW) 51.155 46.055 97.210 Photovoltalc Number of Net Metering Customers 10,655 519 11,174 If Available, Enter the Electric Energy 1,984.835 665.185 2,650.020 Sold Back tot he Utility (Mwh)

Installed Net Metering Capacity (MW) 0.000 Wind Number of Net Metering Customers 0 If Available, Enter the Electric Energy 0.000 Sold Back tot he Utility (Mwh)

Installed Net Metering Capacity (MW) 0.000 Other Number of Net Metering Customers 0 If Available, Enter the Electric Energy 0.000 Sold Back tot he Utility (Mwh)

Installed Net Metering Capacity (MW) 51.155 46.055 0.000 0.000 97.210 Total Number of Net Metering Customers 10,655 519 0 0 11,174 If Available, Enter the Electric Energy 1,984.835 665.185 0.000 0.000 2,650.020 Sold Back tot he Utility (Mwh) 02 September 2014 Page 17 of21

REPORT FOR Los Angeles Department of Water & Pow4 REPORT PERIOD ENDING If your company owns and/or operates a distribution system, please report information on known distributed generation capacity on the system. Such capacity must be utility or customer-owned Distributed Getors NUMBER AND CAPACITY Dispersed Generators (Commercial and Industrial Grid (Commercial and Industrial Generators Not Connected/Synchronized Generators) Connected/Synchronized to the Grid)

(a) (b)

State Balancing Authority

<IMW < IMW

1. Number of generators 1. Number of generators

2. Total combined capacity (MW) 2. Total combined capacity (MW)

3. Capacity that consists of 3. Capacity that consists of backup-only units backup-only units 4 Capacity owned by 4. Capacity owned by respondent respondent

5. Nature of data reported Actual 5. Nature of data reported K Actual Estimated Z Estimated

1. Internal combustion/reciprocating 1. Internal combustion/reciprocating engines engines

2. Combustion turbine(s) 2. Combustion turbine(s)

3. Steam turbine(s) 3. Steam turbine(s)

4. Hydroelectric 4. Hydroelectric

5. Wind turbine(s) 5. Wind turbine(s) 6, Photovoltaic 6. Photovoltaic

7. Storage 7. Storage

8. Other 8. Other

9. Total 9. Total

10. Nature of data reported Actual 10. Nature of data reported Actual Estimated Estimated 02 September 2014 Page 18 of 21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 If your company owns a distribution system, please identify the names of the counties (parish, etc.) by State in which the electric wire/equipment are locatedL LINE STATE COUNTY LINE STATE COUNTY NO. (US Postal Abbreviation) (Parish, Etc.) NO. (US Postal Abbreviation) (Pansh, Etc.)

(a) (b) (a) (b)

I CA - Inyo 2 CA - Los Angeles 02 September 2014 Page 19 of 21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 SCHEDULE PART LINE NO. COLUMN NOTES (a) (b) (c) (d) (c) 02 Septembcr 2014 Page 20 of 21

REPORT FOR: Los Angeles Department of Water & Power 11208 REPORT PERIOD ENDING: 2013 Part State Error No. Error Description/Override Comment Type Override 2 B -- 305 Sales for Resale price must be between 1.0 and 100.0 cents per kWh. (schedule 2B, line 12/schedule 2C, line W 3)

Not Applicable 2 C 703 Your reported average wholesale price differs from last year's average by seventy five percent or more. W Please check resale revenue on Schedule 2C, and sales for resale on Schedule 2B.

Revenue for 2012 sales is independent of revenue 2013.

4 A CA 421 Your calculated Commercial average consumption per customer (sales/customers) differs by more than 40% W from last year's data.

Per EIA, we have combined meters under one customer to be counted as one customer.

CA 422 Your calculated Industrial average consumption per customer (sales/customers) differs by more than 40/ from W last year's data.

4 A CA 426 Your Industrial customer counts differ by more than 20 percent from last year. W Per EIA, we have combined meters under one customer to be counted as one customer.

6 D CA 6104 Number of Transportation customers on line 7 cannot be greater than number of Transportation customers on W 4A plus 4C.

Number of customer count in schedule 4A was combined 02 September 2014 Page 21 of 21