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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

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FORM 10-Q

Commission File No. 000-53908

(An Electric Membership Corporation)
(Exact name of registrant as specified in its charter)

        Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

        Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer o    Accelerated Filer o    Non-Accelerated Filer ý    (Do not check if a smaller reporting company)    Smaller Reporting Company o

        Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

        Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. The registrant is a membership corporation and has no authorized or outstanding equity securities.

   

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OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2015

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CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q contains "forward-looking statements." All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as the timing of various regulatory and other actions, future capital expenditures, business strategy and development, construction or operation of facilities (often, but not always, identified through the use of words or phrases such as "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "projection," "target" and "outlook") are forward-looking statements.

Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. Some of the risks, uncertainties and assumptions that may cause actual results to differ from these forward-looking statements are described under "Item 1A—RISK FACTORS" and in other sections of our annual report on Form 10-K for the fiscal year ended December 31, 2014. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this quarterly report may not occur.

Any forward-looking statement speaks only as of the date of this quarterly report, and, except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

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cost increases and schedule delays with respect to our capital improvement and construction projects, in particular, the construction of two additional nuclear units at Plant Vogtle;



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costs associated with achieving and maintaining compliance with applicable environmental laws and regulations, including those related to air emissions, water and coal combustion byproducts;



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the regulation of carbon dioxide emissions, such as the proposed Clean Power Plan or other potential legislative and regulatory responses to climate change initiatives or efforts to reduce other greenhouse gas emissions;



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legislative and regulatory compliance standards and our ability to comply with any applicable standards, including mandatory reliability standards, and potential penalties for non-compliance;



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increasing debt caused by significant capital expenditures which is weakening certain of our financial metrics;



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commercial banking and financial market conditions;



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our access to capital, the cost to access capital, and the results of our financing and refinancing efforts, including availability of funds in the capital markets;



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uncertainty as to the continued availability of funding from the Rural Utilities Service and our continued eligibility to receive advances from the U.S. Department of Energy for construction of two additional nuclear units at Plant Vogtle;



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actions by credit rating agencies;



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risks and regulatory requirements related to the ownership and construction of nuclear facilities;

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adequate funding of our nuclear decommissioning trust fund including investment performance and projected decommissioning costs;



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continued efficient operation of our generation facilities by us and third-parties;



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the availability of an adequate and economical supply of fuel, water and other materials;



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reliance on third-parties to efficiently manage, distribute and deliver generated electricity;



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acts of sabotage, wars or terrorist activities, including cyber attacks;



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litigation or legal and administrative proceedings and settlements;



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the credit quality and/or inability of various counterparties to meet their financial obligations to us, including failure to perform under agreements;



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our members' ability to perform their obligations to us;



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changes to protections granted by the Georgia Territorial Act that subject our members to increased competition;



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changes in technology available to and utilized by us, our competitors, or residential or commercial consumers in our members' service territories;



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general economic conditions;



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weather conditions and other natural phenomena;



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unanticipated variation in demand for electricity or load forecasts resulting from changes in population and business growth (and declines), consumer consumption, energy conservation efforts and the general economy;



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unanticipated changes in interest rates or rates of inflation;



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significant changes in our relationship with our employees, including the availability of qualified personnel;



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unanticipated changes in capital expenditures, operating expenses and liquidity needs;



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significant changes in critical accounting policies material to us; and



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hazards customary to the electric industry and the possibility that we may not have adequate insurance to cover losses resulting from these hazards.

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

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

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

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

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

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

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

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Oglethorpe Power Corporation
Notes to Unaudited Consolidated Financial Statements
For the Three and Nine Months ended September 30, 2015 and 2014

(A)

General.    The consolidated financial statements included in this report have been prepared by us pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the information furnished in this report reflects all adjustments (which include only normal recurring adjustments) and estimates necessary to fairly state, in all material respects, the results for the three-month and nine-month periods ended September 30, 2015 and 2014. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014, as filed with the SEC. The results of operations for the three-month and nine-month periods ended September 30, 2015 are not necessarily indicative of results to be expected for the full year. As noted in our 2014 Form 10-K, our revenues consist primarily of sales to our 38 electric distribution cooperative members and, thus, the receivables on the consolidated balance sheets are principally from our members. See "Notes to Financial Statements" in our 2014 Form 10-K.

(B)

Fair Value.    Authoritative guidance regarding fair value measurements for financial and non-financial assets and liabilities defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements.

The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows:

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Level 1.  Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded.



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Level 2.  Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs.



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Level 3.  Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs.

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As required by the guidance, assets and liabilities measured at fair value are based on one or more of the following three valuation techniques:

1.    Market approach.    The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business) and deriving fair value based on these inputs.

2.    Income approach.    The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

3.    Cost approach.    The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). This approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset or comparable utility, adjusted for obsolescence.

The tables below detail assets and liabilities measured at fair value on a recurring basis at September 30, 2015 and December 31, 2014.

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The Level 2 investments above in corporate bonds and agency mortgage and asset backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a 3-day redemption notice period.

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The following tables present the changes in Level 3 assets measured at fair value on a recurring basis during the three and nine months ended September 30, 2015 and 2014.

 

 

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We estimate the value of the interest rate options as the sum of time value and any intrinsic value minus a counterparty credit adjustment. Intrinsic value is the value of the underlying swap, which we are able to calculate based on the forward LIBOR swap rates, the fixed rate on the underlying swap, the time to expiration, the term of the underlying swap and discount rates, all of which we are able to effectively observe. Time value is the additional value of the swaption due to the fact that it is an option. We estimate the time value using an option pricing model which, in addition to the factors used to calculate intrinsic value, also takes into account option volatility, which we estimate based on option valuations we obtain from various sources. We estimate the counterparty credit adjustment by observing credit attributes, including the credit default swap spread of entities similar to the counterparty and the amount of credit support that is available for each swaption. Since the primary component of the LIBOR swaptions' value is time value, which is based on estimated option volatility derived from valuations of comparable instruments that are generally not publicly available, we have categorized these LIBOR swaptions as Level 3. We believe the estimated fair values for the LIBOR swaptions we hold are based on the most accurate information available for these types of derivative contracts. For additional information regarding our interest rate options, see Note C.

The estimated fair values of our long-term debt, including current maturities at September 30, 2015 and December 31, 2014 were as follows (in thousands):

The estimated fair value of long-term debt is classified as Level 2 and is estimated based on observed or quoted market prices for the same or similar issues or on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. We also have small amounts of long-term debt provided by National Rural Utilities Cooperative Finance Corporation (CFC) and by CoBank, ACB. The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from third party investment banking firms and a third party data provider, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of September 30, 2015 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on

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rate quotes provided by CFC. We use an interest rate quote sheet provided by CoBank for valuation of the CoBank debt, which reflects current rates for similar loans.

For cash and cash equivalents, restricted cash and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments.

(C)

Derivative Instruments.    Our risk management and compliance committee provides general oversight over all risk management and compliance activities, including but not limited to, commodity trading, investment portfolio management and interest rate risk management. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. To hedge the risk of rising interest rates on long-term debt in connection with capital expenditures, we have entered into interest rate options. We do not apply hedge accounting for any of these derivatives, but apply regulatory accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps and interest rate options are reflected as regulatory assets or liabilities, as appropriate.

We are exposed to credit risk as a result of entering into these hedging arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions.

It is possible that volatility in commodity prices and/or interest rates could cause us to have credit risk exposures with one or more counterparties. We currently have credit risk exposure to our interest rate options counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of September 30, 2015, all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.

We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge and interest rate option counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement).

Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties' credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions.

The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party's credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.

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Gas hedges.    Under our natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment.

At September 30, 2015 and December 31, 2014, the fair value of our natural gas contracts was a net liability of approximately $18,722,000 and $18,914,000, respectively.

As of September 30, 2015 and December 31, 2014, neither we nor any counterparties were required to post credit support or collateral under these natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements had been triggered on September 30, 2015 due to our credit rating being downgraded below investment grade, we would have been required to post letters of credit in the amount of $18,919,000 with our counterparties.

The following table reflects the volume activity of our natural gas derivatives as of September 30, 2015 that is expected to settle or mature each year:

Interest rate options.     We are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. In fourth quarter of 2011, we purchased LIBOR swaptions at a cost of $100,000,000 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we are incurring to finance the two additional nuclear units at Plant Vogtle. Since inception, swaptions having a notional amount of approximately $1,668,138,000 have expired without value and as of September 30, 2015 the remaining notional amount of our outstanding swaptions was approximately $511,066,000.

The LIBOR swaptions are each designed to cap our effective interest rate at a specified fixed interest rate on a specified option expiration date. This is accomplished by means of a payment of the cash settlement value our counterparties are obligated to make to us if prevailing fixed LIBOR swap rates exceed the specified fixed rate on the option expiration date. This payment would partially offset our interest costs, thereby reducing our effective interest rate. The cash settlement value would be zero if swap rates are at or below the specified fixed rate on the expiration date. The cash settlement value is calculated based on the value of an underlying swap which we have the right, but not the obligation, to enter into, which would begin on the option expiration date and extend until 2042 and under which we would pay the specified fixed rate and receive a floating LIBOR rate. The fixed rates on the unexpired swaptions we hold average 164 basis points above the corresponding LIBOR swap rates that were in effect as of September 30, 2015, and the weighted average fixed rate is 3.96%. Swaptions having notional amounts totaling $350,261,000 expired without value during the nine months ended September 30, 2015. The remaining swaptions expire quarterly through 2017.

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We paid all the premiums to purchase these LIBOR swaptions at the time we entered into these transactions. At September 30, 2015 and December 31, 2014, the fair value of these swaptions was approximately $1,502,000 and $4,371,000, respectively. To manage our credit exposure to our counterparties, we negotiated credit support provisions that require each counterparty to provide us collateral in the form of cash or securities to the extent that the value of the swaptions outstanding for that counterparty exceeds a certain threshold. The collateral thresholds can range from $0 to $10,000,000 depending on each counterparty's credit rating. As of September 30, 2015 and December 31, 2014, there were no collateral postings required by the counterparties.

We are deferring unrealized gains or losses from the change in fair value of each LIBOR swaption and related carrying and other incidental costs in accordance with our rate-making treatment. The realized deferred costs and deferred gains, if any, from the settlement of the interest rate options will be amortized and collected in rates over the life of the $2,200,000,000 of debt that we hedged with the swaptions.

The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of September 30, 2015.

The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at September 30, 2015 and December 31, 2014.

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The following table presents the gross realized gains and (losses) on derivative instruments recognized in margin for the three and nine months ended September 30, 2015 and 2014.

The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at September 30, 2015 and December 31, 2014.

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements and obligations to return cash collateral.

(D)

Investments in Debt and Equity Securities.    Investment securities we hold are classified as available-for-sale. Available-for-sale securities are carried at market value with unrealized gains and losses, net of any tax effect, added to or deducted from other comprehensive margin, except that, in accordance with our rate-making treatment, unrealized gains and losses from investment securities held in the nuclear decommissioning funds are directly added to or deducted from the regulatory asset for asset retirement obligations. Realized gains and losses on the nuclear decommissioning funds are also recorded to the regulatory asset. All realized and unrealized gains and losses are determined using the specific identification method. As of September 30, 2015,

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approximately 84% of these gross unrealized losses had been unrealized for a duration of less than one year.

The following tables summarize the activities for available-for-sale securities as of September 30, 2015 and December 31, 2014.

 

(E)

Recently Issued or Adopted Accounting Pronouncements.    In May 2014, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for the annual reporting period beginning after December 15, 2016 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). Early adoption is not permitted.

In August, the FASB issued an update to Topic 606 deferring the effective date by one year. The standard is effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. The standard also permits early adoption of the standard, but not before the original effective date of December 15, 2016.


We are currently evaluating the future impact of this standard on our consolidated financial statements.


In July 2015, the FASB issued "Inventory (Topic 330): Simplifying the Measurement of Inventory." Under the new inventory standard, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal, and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could be replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventory measured using the last-in, first-out (LIFO) or the retail inventory method. The amendments apply to all

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other inventory, which includes inventory that is measured using first-in, first out (FIFO) or average cost, the method used to measure all of our inventories. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted as of the beginning of an interim or annual reporting period. We are currently evaluating the future impact of this standard on our consolidated financial statements.


In April 2015, the FASB issued "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." The amendments in this standard require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB clarified that its guidance issued in April 2015 does not apply to line-of-credit arrangements. Accordingly, entities may continue to present related debt issuance costs as an asset and subsequently amortize the deferred debt costs ratably over the term of the line-of-credit arrangements, regardless of whether there are any outstanding borrowings on the line-of-credit arrangements. The amendments in the standard are effective for the financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. We are currently evaluating the future impact of this standard on our consolidated financial statements.

(F)

Accumulated Comprehensive Margin (Deficit).    The table below provides detail of the beginning and ending balance for each classification of other comprehensive margin (deficit) along with the amount of any reclassification adjustments included in margin for each of the periods presented in the unaudited Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit). There were no material changes in the nature, timing or amounts of expected (gain) loss reclassified to net margin from the amounts disclosed in our 2014 Form 10-K. Amounts reclassified to net margin in the table below are reflected in "Other income" on our unaudited Consolidated Statements of Revenues and Expenses.

Our effective tax rate is zero; therefore, all amounts below are presented net of tax.

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(G)

Contingencies and Regulatory Matters.

We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined.

a.    Nuclear Construction

In 2008, Georgia Power, acting for itself and as agent for us, certain subsidiaries of the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light and Sinking Fund Commissioners (collectively, the Co-owners) and Westinghouse Electric Company, LLC and Stone & Webster, Inc. (collectively, the Contractor) entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement). Pursuant to the EPC Agreement, the Contractor will design,

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engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle, Units No. 3 and No. 4. Our ownership interest and proportionate share of the cost to construct these units is 30%. Current anticipated in-service dates for Vogtle Units No. 3 and No. 4 are the second quarter 2019 and the second quarter 2020, respectively.

Under the EPC Agreement, the Co-owners and the Contractor have established both informal and formal dispute resolution procedures in order to resolve issues arising during the course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, has successfully initiated both formal and informal claims through these procedures, including ongoing claims. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and the Co-owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.

In 2012, the Co-owners and Contractor began negotiations regarding costs associated with design changes to the Westinghouse AP1000 Design Control Document ("DCD") and delays in the project schedule related to the timing of approval of the DCD and issuance of the combined construction operating licenses by the Nuclear Regulatory Commission, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the EPC Agreement. On November 1, 2012, the Co-owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Co-owners are not responsible for these costs. Also on November 1, 2012, the Contractor filed suit against the Co-owners in the U.S. District Court for the District of Columbia alleging the Co-owners are responsible for these costs. The Contractor has also asserted that it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Vogtle Units No. 3 and No. 4, respectively. On May 22, 2014, the Contractor filed an amended counterclaim to the lawsuit pending in the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission delayed module production and the impacts to the Contractor are recoverable by the Contractor under the EPC Agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the EPC Agreement. In March 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the U.S. District Court for the District of Columbia's decision, which had dismissed the Contractor's suit, ruling that proper venue is the U.S. District Court for the Southern District of Georgia. The case is pending in the U.S. District Court for the Southern District of Georgia (the Vogtle Construction Litigation). The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to us, based on our ownership interest, is approximately $280,000,000 in 2008 dollars, or $390,000,000 in 2015 dollars. The Contractor did not specify amounts relating to these new allegations in its amended counterclaim; however, the Contractor subsequently asserted estimated minimum damages related to the counterclaim attributable to us, based on our ownership interest, of approximately $75,000,000 in 2014 dollars, or $78,000,000 in 2015 dollars. In June 2015, the Contractor updated its estimated damages under the initial complaint and the amended counterclaim attributable to us, based on our ownership interest, to an aggregate of approximately $470,000,000 in 2015 dollars.

On October 27, 2015, Westinghouse and Chicago Bridge & Iron announced an agreement under which Westinghouse or one of its affiliates will acquire Stone & Webster from Chicago Bridge & Iron, subject to satisfaction of certain conditions to closing. In addition, on October 27, 2015, Westinghouse and the Co-owners entered into a Term Sheet setting forth the terms of a settlement agreement to resolve disputes between the Co-owners and the Contractor under the EPC Agreement, including the Vogtle Construction Litigation.

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In accordance with the Term Sheet: (i) the Co-owners and the Contractor will enter into mutual releases of all open claims which have been asserted, including any potential extension of such open claims, as well as future claims based on events occurring prior to the effective date of the release that potentially could have been asserted under the original terms of the EPC Agreement, including the Vogtle Construction Litigation, which will be dismissed with prejudice; (ii) the EPC Agreement will be amended to restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (iii) enhanced dispute resolution procedures will be implemented; (iv) the guaranteed substantial completion dates under the EPC Agreement will be revised to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (v) delay liquidated damages will now commence from the current estimated nuclear fuel loading dates, December 31, 2018 and December 31, 2019 for Units No. 3 and No. 4, respectively, rather than the original guaranteed substantial completion dates under the EPC Agreement; and (vi) based on our ownership interest, we will pay to the Contractor and capitalize to the project approximately $230,000,000, of which approximately $80,000,000 has been paid previously under the dispute resolution procedures of the EPC Agreement. In addition, the Co-owners and the Contractor resolved other open existing items relating to the scope of the project under the EPC Agreement, including cyber-security. Further, as part of the proposed settlement and in connection with Westinghouse's proposed acquisition of Stone & Webster: (i) the Co-owners will terminate the parent guarantee of The Shaw Group with respect to certain obligations of Stone & Webster, subject to obtaining consent of the U.S. Department of Energy under loan guarantee agreements relating to Vogtle Units No. 3 and No. 4, while the parent guarantee of Toshiba with respect to certain obligations of Westinghouse will remain in place; (ii) Westinghouse will make provisions to engage Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (iii) the Co-owners, Chicago Bridge & Iron and Shaw Group also will enter into mutual releases of any and all claims against each other arising out of the construction of Vogtle Units No. 3 and No. 4.

The settlement of the pending disputes between the Co-owners and the Contractor, including the Vogtle Construction Litigation, is subject to consummation of Westinghouse's proposed acquisition of Stone & Webster. If this proposed acquisition is not completed, the Vogtle Construction Litigation will continue and the Contractor may from time to time continue to assert that it is entitled to additional payments with respect to its allegations, any of which could be substantial.

If any or all of these costs are ultimately imposed on the Co-owners, we will capitalize the costs attributable to us. As of September 30, 2015, no material amounts have been recorded related to this claim. Future claims by the Contractor or Georgia Power, on behalf of the Co-owners, could arise throughout construction.

b.    Patronage Capital Litigation

On March 13, 2014, a lawsuit was filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when

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the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.

On August 20, 2014, a second patronage capital lawsuit was filed in the Superior Court of DeKalb County against us, Georgia Transmission, and two of our member distribution cooperatives. The case was filed by two current consumer-members of the two member distribution cooperatives named in the lawsuit. Similar to the above described litigation, this complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives; however, one notable difference is that the first case, described above, seeks to bring claims on behalf of former members while this second case seeks to bring claims on behalf of current members. The plaintiffs allege that the defendants have (i) retained patronage capital for an unreasonably long period of time; (ii) conspired with each other to deprive consumer-members of their patronage capital; and (iii) breached bylaw provisions allegedly requiring that patronage capital be retired when the financial condition of the cooperative will not be impaired. The plaintiffs seek unspecified damages and equitable relief, including an order declaring that the defendants be required to retire patronage capital "according to a regular, reasonable revolving plan." Similarly to the litigation described above, although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level where we could comply with current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiff's demands could be significant for a period of years. The plaintiffs seek to certify three plaintiffs' classes but do not seek to certify a defendants' class.

In May 2015, the Superior Court judge for both patronage capital lawsuits appointed a special master to oversee all pre-trial issues relating to these cases, including motions to dismiss that we and the other defendants filed in connection with each lawsuit. In September, the special master issued proposed orders to the judge to grant our and the other defendants' motions to dismiss both patronage capital lawsuits on all counts. These orders have been challenged by the plaintiffs and remain subject to approval by the Court. If approved, the Court's decision to grant the motions to dismiss will be subject to appeal.

We intend to defend vigorously against all claims in the above-described litigation.

c.    Environmental Matters

As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We are also subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities.

In general, these and other types of environmental requirements are becoming increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring

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modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance.

At this time, the ultimate impact of any new and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs.

Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent.

(H)

Restricted Cash and Investments.    Restricted cash and investments primarily consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted investments will be utilized for future Rural Utilities Service Federal Financing Bank debt service payments. The funds on deposit earn interest at a rate of 5% per annum. At September 30, 2015 and December 31, 2014, we had restricted cash and investments totaling $394,708,000 and $365,585,000, respectively, of which $141,620,000 and $118,390,000, respectively, were classified as long-term.

(I)

Regulatory Assets and Liabilities.    We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates under the wholesale power contracts with our members extending through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members.

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The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of September 30, 2015 and December 31, 2014.

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(J)

Member Power Bill Prepayments.    We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through July 2021, with the majority of the balance scheduled to be credited by the end of 2016.

(K)

Debt.

a)

Department of Energy Loan Guarantee:

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (the "Title XVII Loan Guarantee Program"), we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under the Note Purchase Agreement dated as of February 20, 2014 (the "Note Purchase Agreement"), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank (the "Federal Financing Bank Notes" and together with the Note Purchase Agreement, the "FFB Credit Facility Documents"). The FFB Credit Facility Documents provide for a multi-advance term loan facility (the "Facility"), under which we may make term loan borrowings through the Federal Financing Bank.


Proceeds of advances made under the Facility will be used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program ("Eligible Project Costs"). Aggregate borrowings under the Facility may not exceed $3,057,069,461 of which $335,471,604 is designated for capitalized interest.


Advances may be requested under the Facility on a quarterly basis through December 31, 2020. For the nine-month period ended September 30, 2015 we received advances under the Facility totaling $145,000,000. At September 30, 2015, aggregate borrowings totaled $1,045,723,000, including capitalized interest advanced under the loan.

b)

Rural Utilities Service Guaranteed Loans:

For the nine-month period ended September 30, 2015 we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $144,910,000 for general and environmental improvements at existing plants.


In October 2015, we received an additional $8,727,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for general and environmental improvements at existing plants.

c)

Credit Facilities:

On March 23, 2015, we entered into a 5-year $1,210,000,000 credit agreement with a syndicate of thirteen lenders, led by the National Rural Utilities Cooperative Finance Corporation as administrative agent.

(L)

Nuclear Fuel Disposal Cost Litigation.    Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants, is pursuing legal remedies against the Department of Energy for breach of contract.

On December 14, 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, as agent for the co-owners, to recover spent nuclear fuel storage costs at Hatch and Vogtle Units No. 1 and No. 2 covering the period of January 1, 2005 through December 31, 2010. Our

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ownership share of the $36,474,000 total award was $10,949,000, which was received in April 2015. The effects of the award were recorded during the first quarter of 2015 and resulted in a $7,320,000 reduction in total operating expenses, including reductions to fuel expense and production costs, as well as a $3,629,000 reduction to plant in service.

(M)

Asset Retirement Obligations.    Asset retirement obligations are legal obligations associated with the retirement of long-lived assets. These obligations represent the present value of the estimated costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities. In addition, we have retirement obligations related to ash ponds, gypsum, landfill sites and asbestos removal. Under the accounting provision for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognition of the costs related to nuclear and coal ash related decommissioning for financial statement purposes and for ratemaking purposes.

On April 17, 2015 EPA published its final coal combustion residuals (CCR) rule which regulates CCRs as non-hazardous materials under Subtitle D of the Resource Conservation and Recovery Act. The rule took effect on October 19, 2015. Based on preliminary assessments of the impact of the final CCR rule, during the second half of 2015, we revised the forecasted cash flows related to the existing asset retirement obligations, and as a result, have increased the obligations and corresponding assets in electric plant in service by approximately $22,300,000. The liabilities are estimates based on various assumptions including, but not limited to, closure and post-closure cost estimates, timing of expenditures, escalation factors, discount rates and methods for complying with the CCR rule. Additional adjustments to the asset retirement obligations are expected periodically as we continue to assess the impact of the rule on our estimates and assumptions.

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations

General

We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our members are consumer-owned distribution cooperatives providing retail electric service in Georgia on a not-for-profit basis. Our principal business is providing wholesale electric power to our members, which we provide primarily from our generation assets and, to a lesser extent, from power purchased from other suppliers. As with cooperatives generally, we operate on a not-for-profit basis.

Results of Operations

Net Margin

Our net margins for the three-month and nine-month periods ended September 30, 2015 were $15.9 and $42.1 million compared to $14.5 million and $50.9 million for the same periods of 2014. Through September 30, 2015, we collected approximately 87% of our targeted net margin of $48.4 million for the year ending December 31, 2015. For additional information regarding our net margin requirements and policy, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Summary of Cooperative Operations—Margins" of our 2014 Form 10-K.

Operating Revenues

Our operating revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members' service territories, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned, purchased or member-owned resources over which we have dispatch rights, and our members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.

Sales to Members.    We generate revenues principally from the sale of electric capacity and energy to our members. Capacity revenues are the revenues we receive for electric service whether or not our generation and purchased power resources are dispatched to produce electricity, and are designed to recover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Energy revenues are earned by selling electricity to our members, which involves generating or purchasing electricity for our members. Energy revenues recover the variable costs of our business, including fuel, purchased energy and variable operations and maintenance expense.

The components of member revenues for the three-month and nine-month periods ended September 30, 2015 and 2014 were as follows:

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The decrease in energy revenues from members for the three-month and nine-month periods ended September 30, 2015 compared to the same periods in 2014 was primarily due to a decrease in generation for member sales, a decrease in fuel costs and, to a lesser extent, a decrease in purchased power energy. Generation for member sales was somewhat lower during the respective periods as members procured a larger portion of their load requirements from other sources, primarily as a result of lower natural gas prices. Lower member demand for the comparative nine-month periods was also partially a result of milder weather experienced during the first quarter of 2015. As a result of the decrease in fuel costs, average energy revenue per kilowatt-hour from sales to members decreased 10.7% and 15.6% for the three-month and nine-month periods ended September 30, 2015 as compared to the same periods of 2014. For a discussion of fuel costs and purchased power costs, see "—Operating Expenses."

Sales to Non-members.    Our sales to non-members primarily consist of capacity and energy sales at the Smith Energy Facility. Non-member sales increased 64.8% and 40.8% for the three-month and nine-month periods ended September 30, 2015 compared to the same periods of 2014 as a result of the relatively lower average cost of power generated at Smith due to lower natural gas prices.

Operating Expenses

Operating expenses decreased 3.6% for the nine-month period ended September 30, 2015 compared to the same period of 2014 which was driven primarily by lower fuel costs.

The following table summarizes our fuel costs and megawatt-hour generation by generating source.

 

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The decrease in total fuel costs for the three-month and nine-month periods ended September 30, 2015 compared to the same periods of 2014 was primarily due to lower natural gas prices and a shift in the generation mix from the coal-fired units to the relatively more economical natural gas-fired combined cycle units. The decrease in generation at our coal-fired units was attributable in part to (i) extensive testing of environmental controls at Plant Wansley in 2014, and (ii) our members procuring a larger portion of their load requirements in 2015 from other sources, primarily as a result of lower natural gas prices. While total generation increased during these periods, the increase was primarily due to increased generation for non-member sales at Smith. In addition, the decrease in total fuel costs for the nine-month period ended September 30, 2015 compared to the same period of 2014 was due in part to a decrease in member demand as a result of more moderate weather compared to the extreme cold weather experienced during the first quarter of 2014. During the first quarter of 2015 we also recognized a $7.1 million reduction in fuel expense associated with the recovery of spent nuclear fuel storage costs from the U.S. Department of Energy. For additional information regarding this litigation, see Note L.

Production costs increased 11.6% for the nine-month period ended September 30, 2015 as compared to the same period of 2014. The increase resulted primarily from planned major maintenance work at Smith in 2015.

Purchased power costs decreased 19.2% for the nine-month period ended September 30, 2015 as compared to the same period of 2014 primarily due to a decrease in energy purchases. This decrease was largely due to decreased demand as a result of more moderate weather during the first quarter of 2015.

Interest charges

Interest expense increased slightly for the three-month and nine-month periods ended September 30, 2015 as compared to the same periods of 2014 primarily due to increased debt to finance the construction of Vogtle Units No. 3 and No. 4.

Financial Condition

Assets

Cash used for property additions for the nine-month period ended September 30, 2015 totaled $361.3 million. Of this amount, approximately $223.4 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4, $47.1 million for nuclear fuel purchases and the remaining expenditures were for environmental control systems and normal additions and replacements to existing generation facilities.

Restricted cash and investments consist primarily of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The funds, including interest earned thereon, can only be applied to debt service on Rural Utilities Service and Rural Utilities Service-guaranteed Federal Financing Bank notes. Decisions regarding when to apply the funds are guided by the interest rate environment and our anticipated liquidity needs. During the nine-month period ended September 30, 2015, deposits and interest earned on these investments totaled $170.1 million. Rural Utilities Service principal and interest payments made utilizing these funds were $140.9 million during the same period.

Equity and Liabilities

Accounts payable decreased $40.2 million for the nine-month period ended September 30, 2015 primarily as a result of a $34.2 million decrease in the payable to Georgia Power for operation and maintenance costs for our co-owned plants and capital costs associated with Vogtle Units No. 3 and

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No. 4. Also contributing to the decrease was $17.7 million in credits applied to our members' bills in the first quarter of 2015, for a board approved reduction in 2014 revenue requirements as a result of margin collections in excess of our 2014 target. Offsetting the decrease was a $10.3 million increase in accounts payable for natural gas purchases.

Short-term borrowings increased $90.1 million during the nine-month period ended September 30, 2015 to provide interim financing for Vogtle Unit No. 3 and No. 4 construction costs.

Asset retirement obligations increased $41.2 million during the nine-month period ended September 30, 2015 due to changes in cash flow estimates associated with the timing of expenditures for future coal ash pond decommissioning costs as a result of EPA final coal combustion residual (CCR) rule and to the current year's accreted value of all of our asset retirement obligations. For information regarding the impact of the final CCR rule on asset retirement obligations, see Note M.

Vogtle Units No. 3 and No. 4.

In 2008, Georgia Power, acting for itself and as agent for us, certain subsidiaries of the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light and Sinking Fund Commissioners (collectively, the Co-owners) and Westinghouse Electric Company, LLC and Stone & Webster, Inc. (collectively, the Contractor) entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement). Pursuant to the EPC Agreement, the Contractor will design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle, Units No. 3 and No. 4. Our ownership interest and proportionate share of the cost to construct these units is 30%. Current anticipated in-service dates for Vogtle Units No. 3 and No. 4 are the second quarter 2019 and the second quarter 2020, respectively.

Under the EPC Agreement, the Co-owners will pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and certain index-based adjustments, as well as adjustments for change orders and performance bonuses. The EPC Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, subject to a cap. In addition, the EPC Agreement provides for limited cost sharing by the Co-owners for increases to Contractor costs under certain conditions which have not occurred, with maximum additional capital costs under this provision attributable to us of $75 million. Each Co-owner is severally, not jointly, liable to the Contractor for its proportionate share, based on ownership interest, of all amounts owed under the EPC Agreement. As agent for the Co-owners, Georgia Power has designated Southern Nuclear Operating Company as its agent for contract management.

Certain payment obligations of Westinghouse and Stone & Webster are guaranteed by their parent companies, Toshiba Corporation and The Shaw Group, Inc., a subsidiary of Chicago Bridge & Iron Co. N.V., respectively. In the event that the credit rating of Toshiba is downgraded below investment grade, Westinghouse would be required to provide a letter of credit or other credit enhancement to the Co-owners. In the event that any Co-owner's credit rating is downgraded below investment grade, that Co-owner would be required to provide a letter of credit or other credit enhancement to the Contractor. In addition, the Co-owners may terminate the EPC Agreement at any time for their convenience, provided that the Co-owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Contractor. The Contractor may also terminate the EPC Agreement under certain circumstances, including certain suspension or delays of work by the Co-owners, action by a governmental authority to stop work permanently, certain breaches of the EPC Agreement by the Co-owners, Co-owner insolvency, and certain other events.

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The Nuclear Regulatory Commission certified the Westinghouse AP1000 Design Control Document (DCD) effective December 30, 2011. On February 10, 2012, the Nuclear Regulatory Commission issued combined construction and operating licenses for Vogtle Units No. 3 and No. 4 which allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state levels, and additional challenges may arise as construction proceeds.

The Co-owners and the Contractor have established both informal and formal dispute resolution procedures in order to resolve issues arising during the course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, has successfully initiated both formal and informal claims through these procedures, including ongoing claims. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and the Co-owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.

In 2012, the Co-owners and Contractor began negotiations regarding costs associated with design changes to the DCD and delays in the project schedule related to the timing of approval of the DCD and issuance of the combined construction and operating licenses by the Nuclear Regulatory Commission, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the EPC Agreement. On November 1, 2012, the Co-owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Co-owners are not responsible for these costs. Also on November 1, 2012, the Contractor filed suit against the Co-owners in the U.S. District Court for the District of Columbia alleging the Co-owners are responsible for these costs. The Contractor has also asserted that it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Vogtle Units No. 3 and No. 4, respectively. On May 22, 2014, the Contractor filed an amended counterclaim to the lawsuit pending in the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission delayed module production and the impacts to the Contractor are recoverable by the Contractor under the EPC Agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the EPC Agreement. In March 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the U.S. District Court for the District of Columbia's decision, which had dismissed the Contractor's suit, ruling that proper venue is the U.S. District Court for the Southern District of Georgia. The case is pending in the U.S. District Court for the Southern District of Georgia (the Vogtle Construction Litigation). The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to us, based on our ownership interest, is approximately $280 million in 2008 dollars, or $390 million in 2015 dollars. The Contractor did not specify amounts relating to these new allegations in its amended counterclaim; however, the Contractor subsequently asserted estimated minimum damages related to the counterclaim attributable to us, based on our ownership interest, of approximately $75 million in 2014 dollars, or $78 million in 2015 dollars. In June 2015, the Contractor updated its estimated damages under the initial complaint and the amended counterclaim attributable to us, based on our ownership interest, to an aggregate of approximately $470 million in 2015 dollars.

On October 27, 2015, Westinghouse and Chicago Bridge & Iron announced an agreement under which Westinghouse or one of its affiliates will acquire Stone & Webster from Chicago Bridge & Iron, subject to satisfaction of certain conditions to closing. In addition, on October 27, 2015, Westinghouse and the Co-owners entered into a Term Sheet setting forth the terms of a settlement agreement to resolve disputes between the Co-owners and the Contractor under the EPC Agreement, including the Vogtle Construction Litigation.

In accordance with the Term Sheet: (i) the Co-owners and the Contractor will enter into mutual releases of all open claims which have been asserted, including any potential extension of such open claims, as well as future claims based on events occurring prior to the effective date of the release that

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potentially could have been asserted under the original terms of the EPC Agreement, including the Vogtle Construction Litigation, which will be dismissed with prejudice; (ii) the EPC Agreement will be amended to restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (iii) enhanced dispute resolution procedures will be implemented; (iv) the guaranteed substantial completion dates under the EPC Agreement will be revised to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (v) delay liquidated damages will now commence from the current estimated nuclear fuel loading dates, December 31, 2018 and December 31, 2019 for Units No. 3 and No. 4, respectively, rather than the original guaranteed substantial completion dates under the EPC Agreement; and (vi) based on our ownership interest, we will pay to the Contractor and capitalize to the project approximately $230 million, of which approximately $80 million has been paid previously under the dispute resolution procedures of the EPC Agreement. In addition, the Co-owners and the Contractor resolved other open existing items relating to the scope of the project under the EPC Agreement, including cyber-security. Further, as part of the proposed settlement and in connection with Westinghouse's proposed acquisition of Stone & Webster: (i) the Co-owners will terminate the parent guarantee of The Shaw Group with respect to certain obligations of Stone & Webster, subject to obtaining consent of the U.S. Department of Energy under loan guarantee agreements relating to Vogtle Units No. 3 and No. 4, while the parent guarantee of Toshiba with respect to certain obligations of Westinghouse will remain in place; (ii) Westinghouse will make provisions to engage Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (iii) the Co-owners, Chicago Bridge & Iron and Shaw Group also will enter into mutual releases of any and all claims against each other arising out of the construction of Vogtle Units No. 3 and No. 4.

The settlement of the pending disputes between the Co-owners and the Contractor, including the Vogtle Construction Litigation, is subject to consummation of Westinghouse's proposed acquisition of Stone & Webster. If this proposed acquisition is not completed, the Vogtle Construction Litigation will continue and the Contractor may from time to time continue to assert that it is entitled to additional payments with respect to its allegations, any of which could be substantial.

Our previously disclosed project budget, which includes capital costs, allowance for funds used during construction and contingency amounts, is $5.0 billion, even after payments contemplated by the Term Sheet. As of September 30, 2015, our total investment in the additional Vogtle units was $2.6 billion. For information regarding the financing of Vogtle Units No. 3 and No. 4, see "—Financing Activities—Department of Energy-Guaranteed Loan" and Note K.

Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the combined licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance issues may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners, the Contractor, or both.

In addition, as construction continues, the risk remains that ongoing challenges with the Contractor's performance including additional challenges in its fabrication, assembly, delivery, and installation of the shield building and structural modules could further delay the revised forecasted completion dates and the Contractor must improve its schedule performance in order to mitigate this risk. Also, delays in the receipt of the remaining permits necessary for the operation of Vogtle Units No. 3 and No. 4 or other issues could arise and may further impact the project schedule and cost.

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Future claims by the Contractor or Georgia Power, on behalf of the Co-owners, could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the EPC Agreement, but also may be resolved through litigation.

The ultimate outcome of these matters cannot be determined at this time. See "Item 1A—RISK FACTORS" in our 2014 Form 10-K for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.

Environmental Regulations

Existing federal and state laws and regulations regarding environmental matters continue to affect operations at our facilities. Following are some substantial developments relating to environmental regulations and litigation that have occurred since the filing of our last Form 10-Q that may impact the operation of our facilities.

On October 23, 2015, the U.S. Environmental Protection Agency (EPA) final rules regarding emissions of carbon dioxide (CO₂) from certain fossil fuel-fired electric generating units published in the Federal Register. One of the rules limits emissions from new, modified and reconstructed units, while another establishes guidelines for states to develop plans to limit emissions of CO₂ from existing fossil fuel-fired electric generating units. The latter rule's goal is a nationwide 32% reduction in CO₂ emissions from 2005 levels by 2030 and thereafter, with specified interim emission rates starting in 2022 through 2029. For Georgia, this rule requires a 34% reduction in emission rates of covered sources from 2012 levels by 2030. EPA also proposed a federal plan that would be implemented should states fail to submit acceptable plans as well as model rules that states could use in developing their plans and participating in multi-state emissions trading programs. These guidelines and standards could impose future operational restrictions and substantial costs on our coal-fired units. Unlike the proposed rule, the final rule provides that nuclear generating units currently under construction, such as Vogtle Units No. 3 and No. 4, will be credited towards the required CO₂ reduction targets. We are now evaluating the rules and developing strategies for compliance. States are also in the process of determining how best to respond to the new emissions guidelines and the requirements to develop state plans that provide for the required reductions in CO₂ emissions. Georgia and all other states that develop plans will have to submit them to EPA for review and approval. We cannot determine the outcome of these new EPA rules on our operations, the outcome or effect of Georgia's state rules to implement the emissions guidelines, the outcome of EPA review and approval of state rules submitted in response to EPA's rules, or the outcome of litigation challenging the rules, in which we are participating.

Since 2005, EPA has been reviewing wastewater discharges from large steam electric power plants to determine whether new Steam Electric Power Generating Effluent Limitations Guidelines (ELG) that cover wastewater discharge standards under the Clean Water Act are needed. After proposing a rule in June 2013 that would tighten the controls on discharges from nuclear and fossil fuel-fired steam electric power plants, by revising wastewater effluent limitations guidelines and standards, EPA signed a final ELG rule on September 30, 2015. The final ELG rule focuses on four types of wastewater discharges from coal-fired power plants, like our co-owned Plants Wansley and Scherer: (i) fly ash; (ii) bottom ash; (iii) scrubber wastewater; and (iv) low volume wastewater. We are currently evaluating the requirements of the rule and the approach needed for compliance, but it is likely to include additional capital expenditures for new wastewater treatment facilities. That evaluation is being conducted in coordination with an evaluation and assessment of the coal combustion residuals rule discussed below.

On October 19, 2015, EPA's final Coal Combustion Residuals (CCR) rule, which regulates CCRs as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act, became effective. The final rule contains requirements for structural integrity assessments, groundwater monitoring, location siting, composite lining, inactive units, closure and post closure, beneficial use recycling, design and operating criteria, recordkeeping, notification, and internet posting for new and existing CCR landfills, CCR surface impoundments and lateral expansions of CCR facilities. We are

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still reviewing the effects of the CCR rule, and actions to address the requirements of the rule are expected to include, but not be limited to, significant operational changes for existing CCR storage units, extended plant outages, construction of lined landfills and groundwater monitoring facilities and additional material management (including the handling of various ash-related products) and financial assurance requirements. On September 28, 2015, Georgia Power Company, the operating agent for Plants Wansley and Scherer, announced that due to the CCR rule and the ELG Rule discussed above, it would be finalizing and releasing a closure schedule in the next six months for all of its ash ponds, including those at Wansley and Scherer. Preliminary estimates suggest that our future costs associated with compliance with the CCR and ELG rules could be approximately $240 million. More definitive cost estimates will be developed as the process of rule evaluation, compliance approach design and construction implementation of the chosen approach for compliance proceeds. The ultimate impacts associated with the CCR and ELG rules will also depend on agency interpretations of the rules' provisions and litigation brought challenging the rules.

In connection with the CCR rule, we recorded increases to existing asset retirement obligations in 2015 based on a preliminary assessment of the impact of the final CCR rule. Additional adjustments to the asset retirement obligations are expected periodically as we continue to assess the impact of the rule on the estimated costs, timing of expenditures and other assumptions. See Note M for additional information regarding asset retirement obligations.

On October 26, 2015, the EPA published a final rule lowering the National Ambient Air Quality Standard (NAAQS) for ozone, from 75 to 70 parts per billion (ppb) in the Federal Register. The rule begins a process that will result in EPA issuing final designations of attainment, nonattainment or unclassifiable for all areas within each state by October 1, 2017. Those designations likely will be based on 2014 - 2016 ambient air quality data. Several counties in the current 15-county Atlanta ozone nonattainment area for the 75 ppb standard would be designated as ozone nonattainment under the new 70 ppb standard based on air quality data from 2012 - 2014. While we do not have any generating facilities located in these counties, it is possible, although unlikely, that more controls might be required on one or more or our facilities depending on how Georgia addresses the new standard. At this time, we cannot predict the effects, if any, of the revised ozone NAAQS on our generating facilities, or future developments related to the rule, such as final area designations, Georgia's approach in dealing with any nonattainment areas or any litigation brought challenging the final rule.

On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating the Phase II Cross-State Air Pollution Rule (CSAPR) sulfur dioxide emission budgets, which apply beginning in 2017, for several states including Georgia. The emission budgets were remanded to EPA for further action which may result in an increase in the number of sulfur dioxide allowances allocated to Georgia. Given that emission control systems are in place at Plants Wansley and Scherer, we do not anticipate the need to purchase allowances to comply with CSAPR with or without any increase in the allowance budget resulting from this ruling.

A number of parties and states, including Georgia, have legally challenged a final rule published by EPA on June 12, 2015, that requires certain states to revise the provisions of their State Implementation Plans (SIPs) relating to the regulation of excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down or malfunction (SSM). In the rule, EPA has determined that 34 states, including Georgia, have SSM provisions in their SIPs that do not meet the requirements of the Clean Air Act and must be revised and submitted to EPA for approval by November 22, 2016. This new rule may result in significant additional compliance and operational costs at our power plants, and may result in future litigation alleging failure to meet emission limitations that previously did not apply to our facilities during times of SSM as long as the operator complied with certain applicable work practice standards. Because the rule has not been stayed, states are considering how to address EPA's call for revision of SIPs. We cannot predict the ultimate outcome of any state rulemakings, revisions to the Georgia SIP or litigation challenging the final SSM rule.

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On October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued a stay of a final rule published jointly by the EPA and the U.S. Army Corps of Engineers that revises the regulatory definition of waters of the U.S. for all Clean Water Act programs. The final rule would significantly expand the scope of federal jurisdiction under the Clean Water Act. Although the rule is not expected to have a substantial impact on our existing operations, it will likely increase permitting and regulatory requirements and costs associated with the siting and permitting of new facilities. The ultimate impact of the rule will depend on the outcome of further litigation challenging its issuance and cannot be determined at this time.

For further discussion regarding potential effects on our business from environmental regulations, including potential capital requirements, see "Item 1—BUSINESS—REGULATION—Environmental," "Item 1A—RISK FACTORS" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our 2014 Form 10-K.

Liquidity

At September 30, 2015, we had $1.3 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $284 million in cash and cash equivalents and over $1.0 billion of unused and available committed credit arrangements.

At September 30, 2015, we had in excess of $1.6 billion of committed credit arrangements in place and $1.1 billion available under these facilities. These four separate facilities are reflected in the table below:

As of September 30, 2015, we were using our commercial paper program to provide interim funding for 1) payments related to the construction of Vogtle Units No. 3 and No. 4 prior to receiving advances of permanent funding under the Department of Energy-guaranteed Federal Financing Bank loan, which can be requested no more frequently than quarterly and 2) the premium payments made in connection with our interest rate hedging program. Between our credit arrangements and projected cash on hand,

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we believe we have sufficient liquidity to cover our normal operations and to provide for the interim financings described above.

Under our commercial paper program, we are authorized to issue commercial paper in amounts that do not exceed the amount of our committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding. Our commercial paper program is currently sized at $1.0 billion.

Under our unsecured committed lines of credit, we have the ability to issue letters of credit totaling $760 million in the aggregate, of which $509 million remained available at September 30, 2015. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw for working capital needs. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under our committed credit facilities for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue. The majority of our outstanding letters of credit are for the purpose of providing credit enhancement on variable rate demand bonds.

Two of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At September 30, 2015, the required minimum level was $675 million and our actual patronage capital was $803 million. These agreements contain an additional covenant that limits our secured indebtedness and unsecured indebtedness, both as defined in the credit agreements, to $12.0 billion and $4.0 billion, respectively. At September 30, 2015, we had $7.6 billion of secured indebtedness and $325 million of unsecured indebtedness outstanding.

At September 30, 2015, we had $395 million on deposit in the Rural Utilities Service Cushion of Credit Account, all of which is classified as a restricted investment. See "—Balance Sheet Analysis as of September 30, 2015—Assets" for more information regarding this account.

Financing Activities

First Mortgage Indenture.    At September 30, 2015, we had $7.5 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 2014 Form 10-K for further discussion of our first mortgage indenture. We are currently planning to issue up to $250 million of taxable first mortgage bonds in the first half of 2016, and if issued, the bonds will be secured under our first mortgage indenture.

Rural Utilities Service-Guaranteed Loans.    At September 30, 2015 we had three approved Rural Utilities Service-guaranteed loans being funded through the Federal Financing Bank that are in various stages of being drawn down. These three loans totaled $561 million with $186 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As of September 30, 2015, we had $2.6 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.

Department of Energy-Guaranteed Loan.    In February 2014, we closed on a loan with the Department of Energy that will fund up to $3.057 billion of eligible project costs related to the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. This loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by the Department of Energy.

As of September 30, 2015, our total investment in Vogtle Units No. 3 and No. 4 was $2.6 billion and we have incurred $2.4 billion of debt to provide long-term financing for this investment. This long-term debt includes $1.4 billion of taxable first mortgage bonds we previously issued and $1.0 billion, including capitalized interest, under the Department of Energy loan facility. The facility may be used until no later than December 2020 to provide long-term funding for eligible project costs after they are incurred. As of September 30, 2015, we have the capacity to fund an additional $681 million under the

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facility based on the amount of eligible project costs we have incurred to date. We anticipate making draws on at least a semi-annual basis to meet our funding requirements as construction progresses. When advanced, the debt will be secured under our first mortgage indenture. For additional information regarding this loan, see Note K.

For more detailed information regarding our financing plans, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities" in our 2014 Form 10-K.

Newly Adopted or Issued Accounting Standards

For a discussion of recently issued or adopted accounting pronouncements, see Note E of Notes to Unaudited Consolidated Financial Statements.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

There have not been any material changes to market risks from those reported in "Item 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK" of our 2014 Form 10-K.

Item 4.    Controls and Procedures

As of September 30, 2015, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

There have been no changes in internal control over financial reporting or other factors that occurred during the quarter ended September 30, 2015 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1.    Legal Proceedings

The ultimate outcome of pending litigation against us cannot be predicted at this time; however, we do not anticipate that the ultimate liabilities, if any, arising from such proceedings would have a material effect on our financial condition or results of operations.

a.     Vogtle Units No. 3 and No. 4

See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Vogtle Units No. 3 and No. 4" for a discussion of litigation and a proposed settlement related to Vogtle Units No. 3 and No. 4.

b.     Patronage Capital Litigation

On March 13, 2014, a lawsuit was filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission Corporation and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.

On August 20, 2014, a second patronage capital lawsuit was filed in the Superior Court of DeKalb County against us, Georgia Transmission, and two of our member distribution cooperatives. The case was filed by two current consumer-members of the two member distribution cooperatives named in the lawsuit. Similar to the above described litigation, this complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives; however, one notable difference is that the first case, described above, seeks to bring claims on behalf of former members while this second case seeks to bring claims on behalf of current members. The plaintiffs allege that the defendants have (i) retained patronage capital for an unreasonably long period of time; (ii) conspired with each other to deprive consumer-members of their patronage capital; and (iii) breached bylaw provisions allegedly requiring that patronage capital be retired when the financial condition of the cooperative will not be impaired. The plaintiffs seek unspecified damages and equitable relief, including an order declaring that the defendants be required to retire patronage capital "according to a regular, reasonable revolving plan." Similarly to the litigation described above, although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require

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us to raise our rates to a level where we could comply with current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiff's demands could be significant for a period of years. The plaintiffs seek to certify three plaintiffs' classes but do not seek to certify a defendants' class.

In May 2015, the Superior Court judge for both patronage capital lawsuits appointed a special master to oversee all pre-trial issues relating to these cases, including motions to dismiss that we and the other defendants filed in connection with each lawsuit. In September, the special master issued proposed orders to the judge to grant our and the other defendants' motions to dismiss both patronage capital lawsuits on all counts. These orders have been challenged by the plaintiffs and remain subject to approval by the Court. If approved, the Court's decision to grant the motions to dismiss will be subject to appeal.

We intend to defend vigorously against all claims in the above-described litigation.

Item 1A.    Risk Factors

There have been no material changes from the risks disclosed in "Item 1A—RISK FACTORS" of our 2014 Form 10-K.

Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds

Not Applicable.

Item 3.    Defaults upon Senior Securities

Not Applicable.

Item 4.    Mine Safety Disclosures

Not Applicable.

Item 5.    Other Information

Not Applicable.

Item 6.    Exhibits

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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