result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs.

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 March 31,June 30, 2018 and December 31, 2017.

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The Level 2 investments above in corporate bonds and debt, federal agency mortgage backed securities, and mortgage 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.

The Level 3 investments above in corporate bonds and debt consist of investments in bank loans which are not exchange traded. Although these securities may be liquid and priced daily, their inputs are not observable.

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The following table presents the changes in Level 3 assets measured at fair value on a recurring basis during the three and six months ended March 31,June 30, 2018.

None of our assets or liabilities measured at fair value on a recurring basis were categorized as Level 3 at December 31, 2017.

The estimated fair values of our long-term debt, including current maturities at March 31,June 30, 2018 and December 31, 2017 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). The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from a third party data reporting service, 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 March 31,June 30, 2018 plus an applicable spread, which reflects our borrowing rate for

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new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC.

For cash, and cash equivalents, and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account and the carrying amount of these investments approximates fair value because of the liquid nature of the deposits with the U.S. Treasury.

(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. We do not apply hedge accounting for any of these derivatives, but apply regulatory

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accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps 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 could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of March 31,June 30, 2018, 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 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.

Gas hedgeshedges.    .    Under the 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




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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 March 31,June 30, 2018 and December 31, 2017, the estimated fair value of our natural gas contracts was a net liability of approximately $6,903,000$11,382,000 and $6,328,000, respectively.

As of March 31,June 30, 2018 and December 31, 2017, neither we nor any counterparties were required to post credit support or collateral under the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on March 31,June 30, 2018 due to our credit rating being downgraded below investment grade, we would have been required to post collateral or letters of credit of $6,903,000$11,382,000 with our counterparties.




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The following table reflects the notional volume of our natural gas derivatives as of March 31,June 30, 2018 that is expected to settle or mature each year:

​	​	​	​	​	​	​	​	​
Year			Natural Gas Swaps (MMBTUs) (in millions)				Natural Gas Swaps (MMBTUs) (in millions)
​	​	​	​	​	​	​	​	​
2018			22.7				15.4
2019			20.1				21.6
2020			17.0				18.4
2021			13.7				16.8
2022			8.5				10.7
2023							0.2
​	​	​	​	​	​	​	​	​
Total			82.0				83.1
​	​	​	​	​	​	​	​	​
​			​	​
​		​	​	​
​	​	​	​	​

The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at March 31,June 30, 2018 and December 31, 2017.

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

2018

2017

2018

2017

(dollars in thousands)

(dollars in thousands)

Assets:

Natural gas swaps

Other current assets

$

308

$

412

Other current assets

$

1,228

$

412

Liabilities:

Natural gas swaps

Other current liabilities

$

836

$

1,575

Other current liabilities

$

747

$

1,575

Natural gas swaps

Other deferred credits

$

6,375

$

5,165

Other deferred credits

$

11,863

$

5,165

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​




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The following table presents the gross realized gains and (losses) on derivative instruments recognized in margin for the three and six months ended March 31,June 30, 2018 and 2017.

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Statement of Revenues and Expenses Location

Three months ended March 31,

Statement of Revenues and Expenses Location

Three months ended June 30,

Six months ended June 30,

2018

2017

2018

2017

2018

2017

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

(dollars in thousands)

(dollars in thousands)

Natural Gas Swaps

Fuel

$

1,392

$

840

Fuel

$

359

$

1,897

$

1,751

$

2,736

Natural Gas Swaps

Fuel

(748

)

(744

)

Fuel

(111

)

(73

)

(859

)

(817

)

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Total

$

644

$

96

$

248

$

1,824

$

892

$

1,919

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

The following table presents the unrealized losses on derivative instruments deferred on the balance sheet at March 31,June 30, 2018 and December 31, 2017.

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Balance Sheet Location

2018

2017

Balance Sheet Location

2018

2017

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

(dollars in thousands)

(dollars in thousands)

Natural gas swaps

Regulatory asset

$

(6,903

)

$

(6,328

)

Regulatory asset

$

(11,382

)

$

(6,328

)

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Total

$

(6,903

)

$

(6,328

)

$

(11,382

)

$

(6,328

)

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​




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(D)

Investments in Debt and Equity Securities.    Investment securities we hold are classified as available-for-sale and are carried at market value. Prior to the fourth quarter ofOctober 1, 2017, unrealized gains and losses of investment securities related to nuclear decommissioning were deferred pursuant to regulated operations accounting, while those for all other investment securities were addedrecorded to or deducted from accumulated other comprehensive (deficit) margin. During the fourth quarter of 2017, we began applying regulated operations accounting to the unrealized gains and losses tofor all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. As of March 31,June 30, 2018, approximately 65%66% of these gross unrealized losses had been unrealized for a duration of less than one year.

The following tables summarize debt and equity securities as of March 31,June 30, 2018 and December 31, 2017.

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Gross Unrealized

Gross Unrealized

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

(dollars in thousands)

(dollars in thousands)

March 31, 2018

Cost

Gains

Losses

Fair Value

June 30, 2018

Cost

Gains

Losses

Fair Value

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Equity

$

247,242

$

90,257

$

(5,296

)

$

332,203

$

248,817

$

96,340

$

(4,885

)

$

340,272

Debt

244,492

901

(5,599

)

239,794

253,860

694

(5,087

)

249,467

Other

12,912

1

—

12,913

8,645

—

—

8,645

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Total

$

504,646

$

91,159

$

(10,895

)

$

584,910

$

511,322

$

97,034

$

(9,972

)

$

598,384

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​




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​

​

​

​

​

​

​

​

​

​

​

​

​

​

Gross Unrealized

​

​

​

​

​

​

​

​

​

​

​

​

​

​

(dollars in thousands)

December 31, 2017

Cost

Gains

Losses

Fair Value

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Equity

$

246,549

$

91,954

$

(4,064

)

$

334,439

Debt

240,878

1,814

(2,262

)

240,430

Other

10,807

1

—

10,808

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Total

$

498,234

$

93,769

$

(6,326

)

$

585,677

​

​

​

​

​

​

​

​

​

​

​

​

​

​

(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. In addition, Topic 606 requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers.

We adopted the new revenue standard effective January 1, 2018, using the full retrospective method, which required us to restate each prior reporting period presented. The adoption of the new revenue standard did not change the nature, amounts or timing of revenues that we recognize within an annual reporting period and resulted in no restatement of revenues recognized for the three months ended March 31, 2017.period. The most significant impact of the new revenue standard to us relates to the potential recognition of refund liabilities related to capacity revenues in future interim reporting periods. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. For the six months ended June 30, 2018 and 2017, we recognized refund liabilities totaling $5,650,000 and $5,750,000, respectively. Adoption of the new revenue standard had no impact to cash from or used in operating, financing, or investing on our consolidated cash flowflows statements.


In March 2018, the FASB issued "Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118." In accordance with the standard, we recognized the provisional tax impacts related to the re-measurement of our deferred income tax




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assets and liabilities as of the year ended December 31, 2017. As of March 31, 2018, we have not made any additional measurement-period adjustments related to these items. Such adjustments may be necessary in future periods due to, among other things, the significant complexity of the Tax Cuts and Job Act signed into law in December 2017, and anticipated additional regulatory guidance that may be issued by the Internal Revenue Service, changes in analysis, interpretations and assumptions we made and actions we may take as a result of the Act. We are continuing to gather information to assess the application of the Act and expect to complete our analysis with the filing of our 2017 income tax returns during the fourth quarter of 2018.


In January 2016, the FASB issued "Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities." The amendments in this update address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Certain provisions within this update can be adopted early. Certain provisions within this update should be applied by means of a cumulative effect adjustment to the balance sheet of the fiscal year of adoption and certain provisions should be applied prospectively. One of the provisions in this standard requires our equity investments, except those accounted for under the equity method of accounting or those that result in consolidation of our subsidiary, to be measured at fair value with changes in fair value recognized in net income. None of the other provisions in this standard will have any impact to our consolidated financial statements. Effective December 31, 2017, we adopted regulatory accounting treatment with respect to unrealized gains and/or losses on our equity investments. Upon applying regulatory accounting treatment, unrealized gains on our equity investments will be recorded as a regulatory liability and, conversely, unrealized losses on our equity investments will be recorded as a regulatory asset, at the end of each reporting period. As of December 31, 2017, we recorded $618,000 of unrealized losses on our equity investments as a regulatory asset. On January 1, 2018, we adopted the amendments within this standard. The adoption of this standard did not have any impact to our consolidated financial statements due to our regulatory accounting treatment for unrealized gains and/or losses on our equity investments.


In February 2016, the FASB issued "Leases (Topic 842)." The new leases standard requires a dual approach for lessee accounting under which a lessee would account for leases as finance leases or operating leases. Both finance leases and operating leases will result in the lessee recognizing a




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right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the ROU asset and for operating leases the lessee would recognize a straight-line total lease expense. Quantitative and qualitative disclosures will also be required surrounding significant judgments made by management. The new lease standard does not substantially change lessor accounting. The new leases standard is effective for us on a modified retrospective approach for annual reporting periods beginning after December 15, 2018, and interim periods therein. Early adoption is permitted.


In January 2018, the FASB issued "Land Easement Practical Expedient for Transition to Topic 842" that allows an entity to not evaluate existing and expired land easements that were not previously accounted for as leases upon adoption of Topic 842. Any land easements entered into prospectively or modified after adoption should be evaluated to assess whether they meet the definition of a lease.


In July 2018, the FASB issued "Codification Improvements to Topic 842, Leases" to clarify certain narrow aspects of the guidance in Topic 842. The effective date and transition requirements in this standard are the same as the requirements in Topic 842. We are currently evaluatingassessing the future impactpotential impacts of the amendments in this standard in context of the overall adoption of the new accounting guidance for leases. In addition, we continue to monitor both the FASB's ongoing standard-setting activities that may result in the issuance of additional targeted improvements, as well as potential industry implementation issues.


In July 2018, the FASB issued "Leases (Topic 842): Targeted Improvements" to add a new transition method to the new leases standard that allows entities to not apply the new guidance in the comparative periods entities present in their financial statements in the year of adoption. The FASB also provided a practical expedient that gives lessors an option to combine non-lease and associated lease components when certain criteria are met and requires a lessor to account for the combined component in accordance with the new revenue standard if the associated non-lease components are the predominant component.

While we have not fully completed our evaluation of the new leases standard, we expect that the adoption of such standard will not have a material impact on our consolidated financial statements. Our lease portfolio consists of our 60% undivided interest in Scherer Unit No. 2, railcars leases for the transportation of coal and various nominal leases.


We account for the Scherer Unit No. 2 leases as capital leases and the railcars leases as operating leases under the current lease accounting model. At this time, we believe that the key changes in adopting the new leases standard will be how we account for our operating leases that are currently off-balance sheet. Our evaluation process includes, but is not limited to, reviewing all forms of leases, performing a completeness assessment over the lease population and analyzing the practical expedients available to us.


We will adopt the new leases standard on January 1, 2019.


In June 2016, the FASB issued "Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments." The amendments in this update replace the current incurred loss impairment methodology with a methodology that reflects expected credit losses. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2019, and interim periods therein. The amendments in this update can be adopted earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are currently evaluating the future impact of this standard on our consolidated financial statements.


In March 2018, the FASB issued "Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118." In accordance with the standard, we




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recognized the provisional tax impacts related to the re-measurement of our deferred income tax assets and liabilities as of the year ended December 31, 2017. As of June 30, 2018, we have not made any additional measurement-period adjustments related to these items. Such adjustments may be necessary in future periods due to, among other things, the significant complexity of the Tax Cuts and Job Act signed into law in December 2017, and anticipated additional regulatory guidance that may be issued by the Internal Revenue Service, changes in analysis, interpretations and assumptions we made and actions we may take as a result of the Act. We are continuing to gather information to assess the application of the Act and expect to complete our analysis with the filing of our 2017 income tax returns during the fourth quarter of 2018.

(F)

Revenue Recognition.    As an electric membership cooperative, our principle business is providing wholesale electric service to our members. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. These contracts, which extend




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through December 30, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. While not significant, we also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments.


Pursuant to our contracts, we primarily provide two services, capacity and energy. Capacity and energy revenues are recognized by us upon transfer of control of promised services to our members and non-members in an amount that reflects the consideration we expect to receive in exchange for those services. Capacity and energy are distinct and we account for them as separate performance obligations. The obligations to provide capacity and energy are satisfied over time as the customer simultaneously receives and consumes the benefit of these services. Both performance obligations are provided directly by us and not through a third party.


Each of our members is obligated to pay us for capacity and energy we furnish under its wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. Revenues from our members are derived through a cost-plus rate structure which is set forth as a formula in the rate schedule to the wholesale power contracts between us and each of our members. The formulary rate provides for the pass-through of our (i) fixed costs (net of any income from other sources) plus a targeted margin as capacity revenues and (ii) variable costs as energy revenues from our members. Power purchase and sale agreements between us and non-members obligates each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices agreed to by us in the applicable agreement. We include marginsMargins produced from non-member sales are included in the rate schedule formula toand reduce revenue requirements from our members.


The standard selling price at which we provide capacity services to our members is determined by our formulary rate on an annual basis. As a result, the consideration we receive for providing capacity services is determined annually. Over the course of a year, our member capacity revenues are relatively stable. Capacity revenues may fluctuate year to year largely due to the recovery of fixed operation and maintenance costs. The components of the formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and income from other sources. Capacity revenues, therefore, vary to the extent these components vary. Fixed costs include items such as depreciation, interest, fixed operation and maintenance expenses, administrative and general expenses. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in




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accordance with the associated revenue deferral plan. For information regarding regulatory accounting, see Note I.


Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our capacity revenues are based on the associated costs we expect to recover in a given year and are recognized and billed to our members in equal monthly installments over the course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. Non-member capacity revenues, if any, are typically billed and recognized in equal monthly installments over the term of the contract.


We have a power bill prepayment program pursuant to which our members may prepay future capacity costs and receive a discount. As this program provides us with significant financing, we adjust our capacity revenues by the amount of the discount, which is based on our avoided cost of borrowing. The discounts are credited against the participating members' power bills on a monthly




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basis. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. Application of the prepayments extends through January 2023, with the majority of the balance scheduled to be applied by the end of 2019.


We satisfy our performance obligations to deliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our members based upon the variable costs incurred to generate or purchase that energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy 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, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights, and by members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers. We do not provide all of our members' energy requirements. The standard selling price for our energy revenues from non-members is the price mutually agreed upon.


We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2018, our board has approved a targeted margins for interest ratio of 1.14 and for 2017, we achieved a margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine if a refund to our members of excess consideration is likely. If required, we reduce our capacity revenues proportionately and recognize a refund liability to our members. As of March 31, 2018 and March 31, 2017, no refund liabilities were recorded as we had assessed it not probable that there would be a material refund at the end of the year. Refund liabilities, if any, are included in other current liabilitiesaccounts payable on our consolidated balance sheets. As of June 30, 2018 and 2017, we recognized refund liabilities totaling $5,650,000 and $5,750,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from non-members.





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Sales to members were as follows:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

2018

2017

Three Months Ended June 30,

Six Months Ended June 30,

(dollars in thousands)

(dollars in thousands)

2018

2017

2018

2017

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

(dollars in thousands)

Capacity

$

240,481

$

237,432

Energy

132,920

116,712

Capacity revenues

$

231,571

$

229,946

$

472,052

$

467,377

Energy revenues

134,240

131,377

267,160

248,090

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Total

$

373,401

$

354,144

$

365,811

$

361,323

$

739,212

$

715,467

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Sales to non-members during the three and six months ended March 31,June 30, 2018 and March 31,June 30, 2017 were insignificant. There were no capacity sales to non-members during the three months ended March 31, 2018 and March 31, 2017.


We bill our members for capacity and energy on a monthly basis. Based on the payment terms of the wholesale power contracts and power purchase and sale agreements, we receive payment during the following month in which capacity and energy revenues are billed. Estimated energy charges are billed to members based on the amount of energy supplied during the month and are adjusted when actual costs are available, generally the following month. As payment is due to us within one month of billing, we do not provide significant financing to our customers.





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The opening and closing balances of receivables from contracts with our customers are as follows:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

March 31, 2018

March 31, 2017

December 31, 2017

December 31, 2016

(dollars in thousands)

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

(dollars in thousands)

June 30, 2018

June 30, 2017

December 31, 2017

December 31, 2016

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Receivables from members

$

117,625

$

126,150

$

126,211

$

136,552

$

144,865

$

132,703

$

126,211

$

136,552

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Electric capacity and energy revenues are recognized by us without any obligation for returns, warranties or taxes collected. As our members are jointly and severally obligated to pay all expenses associated with owning and operating our power supply business and we perform an on-going assessment of the credit worthiness of non-members, we have not recorded an allowance for doubtful accounts associated with our receivables from members or non-members.


For the three and six months ended March 31,June 30, 2018 and March 31,June 30, 2017, no impairment losses were recognized on any receivables that arose from contracts with our customers.

(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.


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 may also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide.


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




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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 potential 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.





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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 Investments.    Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit earn interest at a rate of 5% per annum. At March 31,June 30, 2018 and December 31, 2017, we had restricted investments totaling $853,080,000$805,100,000 and $882,909,000, respectively, of which $613,588,000$585,111,000 and $653,585,000, respectively, were classified as long-term. The funds on deposit with the Rural Utilities Service in the Cushion of Credit Account are held by the U.S. Treasury, acting through the Federal Financing Bank.

(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 we have with each of our members extending through December 31, 2050.members. 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 March 31,June 30, 2018 and December 31, 2017.

​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
			2018			2017				2018			2017
			(dollars in thousands)							(dollars in thousands)
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Regulatory Assets:
Premium and loss on reacquired debt(a)		$	51,313		$	52,989			$	49,647		$	52,989
Amortization on capital leases(b)			34,114			33,846				34,382			33,846
Outage costs(c)			42,590			40,525				34,715			40,525
Asset retirement obligations—Ashpond and other(k)			76,938			68,289				85,449			68,289
Depreciation expense(d)			42,311			42,667				41,955			42,667
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(e)			49,465			48,702				50,188			48,702
Interest rate options cost(f)			113,297			112,102				114,515			112,102
Deferral of effects on net margin—Smith Energy Facility(g)			164,969			166,454				163,482			166,454
Other regulatory assets(l)			19,911			19,510				23,278			19,510
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Total Regulatory Assets		$	594,908		$	585,084			$	597,611		$	585,084
Regulatory Liabilities:
Accumulated retirement costs for other obligations(h)		$	15,048		$	12,813			$	16,112		$	12,813
Deferral of effects on net margin—Hawk Road Energy Facility(g)			19,400			19,553				19,247			19,553
Major maintenance reserve(i)			49,628			47,087				50,084			47,087
Amortization on capital leases(b)			19,330			20,055				18,605			20,055
Deferred debt service adder(j)			98,075			95,695				100,447			95,695
Asset retirement obligations—Nuclear(k)			40,590			53,571				40,334			53,571
Other regulatory liabilities(l)			4,315			2,875				8,854			2,875
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Total Regulatory Liabilities		$	246,386		$	251,649			$	253,683		$	251,649
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
Net Regulatory Assets		$	348,522		$	333,435			$	343,928		$	333,435
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
​
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​

^(a)

Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 26 years.



^(b)

Represents the difference between expense recognized for rate-making purposes and financial statement purposes related to capital lease payments and the aggregate of the amortization of the asset and interest on the obligation.



^(c)

Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 48 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit.



^(d)

Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant.



^(e)

Deferred charges related to Vogtle Units No. 3 and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units.



^(f)

Deferral of premiums paid to purchase interest rate options purchased to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No.3 and No.4 construction.No.4. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project.



^(g)

Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant.



^(h)

Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets.



⁽ⁱ⁾

Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred.



^(j)

Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants.



^(k)

Represents difference in timing of recognition of the costs of decommissioning and ashpond remediation for financial statement purposes and for ratemaking purposes.



^(l)

The amortization periods for other regulatory assets range up to 32 years and the amortization periods of other regulatory liabilities range up to 9 years.




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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 January 2023, with the majority of the balance scheduled to be credited by the end of 2019.

(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 (as amended, the Loan Guarantee Agreement) 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 FFB 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 long-term loan borrowings through the Federal Financing Bank.


Proceeds of advances received under the Facility are 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. Aggregate borrowings under the Facility may not exceed $3,057,069,461, of which $335,471,604 is designated for capitalized interest.


Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event the Department of Energy is required to make any payments to the Federal Financing Bank under the guarantee. Our payment obligations to the Federal Financing Bank under the FFB Notes and reimbursement obligations to the Department of Energy under its guarantee, but not our covenants to the Department of Energy under the Loan Guarantee Agreement, are secured equally and ratably with all of our other notes and obligations issued under our first mortgage indenture. The final maturity date for each advance is February 20, 2044. Interest is payable quarterly in arrears and principal payments will begin on February 20, 2020. Under both FFB Notes, the interest rates during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%.


At March 31,June 30, 2018, aggregate Department of Energy-guaranteed borrowings totaled $1,749,979,000,$1,764,658,000, including capitalized interest.


Pursuant to the amended terms of the Loan Guarantee Agreement, we are restricted from receivingno further advances untilare permitted pending satisfaction of certain conditions, are met, including Department of Energy approval of the Bechtel Agreement (as defined in Note L) and the Department of Energy and we enter into an amendment to the Loan Guarantee Agreement and a Co-owner vote to incorporate provisions relating to the Bechtel Agreement and other replacement agreements. While not assured, we expect to satisfy these conditionscontinue construction (discussed in June 2018.Note L). When these conditions are satisfied, advances may be requested under the Facility on a quarterly basis through December 31, 2020.


In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, including certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of




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updated project-related information, our continued ownership of our interest in Vogtle Units No. 3 and No. 4 free and clear of any liens except those permitted under the Loan Guarantee




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Agreement, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act, as amended, and certification from the Department of Energy's consulting engineer that proceeds of the advance are used to reimburse eligible project costs.


Under the Loan Guarantee Agreement, we are subject to customary borrower affirmative and negative covenants and events of default. In addition, we are subject to project-related reporting requirements and other project-specific covenants and events of default.


Under the Loan Guarantee Agreement, upon the occurrence of an "Alternate Amortization Event," the Department of Energy may require us to prepay the outstanding principal amount of all guaranteed borrowings over a period of five years, with level principal amortization. These events include (i) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (ii) termination of the Services Agreement as defined in Note L or rejection of the Services Agreement in bankruptcy if Georgia Power does not maintain access to certain related intellectual property rights, (iii) a decision by us not to continue construction of Vogtle Units No. 3 and No. 4, (iv) loss of or failure to receive necessary regulatory approvals under certain circumstances, (v) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (vi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (vii) change of control of Oglethorpe and (viii) certain events of loss or condemnation.


If we receive proceeds from an event of condemnation relating to Vogtle Units No. 3 and No. 4, such proceeds must be applied to immediately prepay outstanding borrowings under the Facility. We may also voluntarily prepay outstanding borrowings under the Facility. Under the FFB Credit Facility Documents, any prepayment will be subject to a make-whole premium or discount, as applicable.


On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to $1,620,000,000$1,619,679,706 of additional guaranteed funding under the Loan Guarantee Agreement. This conditional commitment expires on JuneSeptember 30, 2018, subject to any extension approved by the Department of Energy. We do not anticipate closing on the new loan before September 30, 2018 and anticipate seeking an extension from the Department of Energy. Final approval and issuance of this additional loan guarantee by the Department of Energy cannot be assured and is subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions.conditions, including a vote of the Co-owners to continue construction.

b)

Rural Utilities Service Guaranteed Loans:

For the three-monthsix-month period ended March 31,June 30, 2018, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $2,636,000$236,200,000 for long-term financing of general and environmental improvements at existing plants.


In AprilJuly 2018, we received an additional $233,564,000$33,021,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants.


These advances are secured under our first mortgage indenture.

c)

Pollution Control Revenue Bonds:

On December 28, 2017, the Development Authority of Burke County (Georgia) issued, on our behalf, $399,785,000 (Series 2017C, D, E, F Burke) in aggregate principal amount of tax-exempt pollution control revenue bonds to refinance costs associated with certain of our pollution control facilities. The bonds were directly purchased by two banks and the proceeds defeased our




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obligations under $399,785,000 of pollution control revenue bonds issued in 2008 that were callable




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on or after January 1, 2018. Those 2008 bonds were fully redeemed on their call date. Each series of the 2017 bonds bore interest at an indexed variable rate until February 1, 2018 when we converted the bonds into fixed interest rate modes. We converted the (i) $200,000,000 Series 2017C and Series 2017D bonds to a fixed rate of 4.125% per annum to maturity with an optional call at par on February 1, 2028, (ii) $100,000,000 Series 2017E bonds to a fixed term rate of 3.25% per annum to the mandatory tender date of February 3, 2025 and (iii) $99,785,000 Series 2017F bonds to a fixed term rate of 3.00% per annum to the mandatory tender date of February 1, 2023. The Series 2017C, D, E, F bonds are scheduled to mature in 2041 through 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture.

(L)

Vogtle Units No. 3 and No. 4 Construction Project.    We, Georgia Power, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our ownership interest and proportionate share of the cost to construct these units is 30%. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services.


In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, Westinghouse agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle.


Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed-pricefixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. In connection with the bankruptcy filing, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with Westinghouse and WECTEC Staffing Services LLC to provide for a continuation of work at Vogtle Units No. 3 and No. 4. The Interim Assessment Agreement expired in July 2017 upon the effective date of the Services Agreement.


Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technologicaltechnical support and staff augmentation on a time and materials cost basis. The Services Agreement will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days' written notice.


In October 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, wherebypursuant to which Bechtel will serveserves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets.




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Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement.

The Co-owners




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may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including, certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events. Pursuant to the Loan Guarantee Agreementloan guarantee agreement between us and the Department of Energy, we are required to obtain the Department of Energy's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
loan guarantee agreement.

In November 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 (as amended, the Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. Pursuant to the Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent;rates; or (iv) an increase in the construction budget contained in Georgia Power's seventeenth Vogtle construction monitoring (VCM) report of more than $1,000,000,000 or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Joint Ownership Agreements, the required approval of holders of ownership interests in Vogtle Units No. 3 and No. 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.


On December 21, 2017, the Georgia Public Service Commission took a series of actions related to the construction of Vogtle Units No. 3 and No. 4 and issued its related order on January 11, 2018. Among other actions, the Public Service Commission (i) accepted Georgia Power's recommendation thatto continue construction of Vogtle Units No. 3 and No. 4, be completed, with Southern Nuclear Operating Company, Inc. serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Public Service Commission reservereserved the right to reconsider the decision to continue construction. Parties have filed two petitions with the Fulton County Superior Court appealing the Georgia Public Service Commission's January 11, 2018 order. Georgia Power has stated that it believes these appeals have no merit; however, an adverse outcome in either appeal could have a material impact on our financial condition and results of operations.

Georgia Power has advised us that it recently became aware that the estimated future Vogtle project costs were projected to exceed the corresponding budgeted amounts. Upon discovery of these variances, the Co-owners requested Southern Nuclear perform a full cost analysis and reforecast of the cost to complete the project and engaged a third party to independently assess this analysis, forecast, and existing project controls for identifying budget variances. The capital costs estimated to complete construction are expected to increase by approximately $1.5 billion (our 30% share estimated at approximately $450 million). The increases are primarily due to




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changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, craft labor incentives, as well as the related levels of project management, oversight and support, including field supervision and engineering support, required to complete the project. We, and the other Co-owners, are evaluating these increased capital costs along with a project-level contingency in a preliminary amount of approximately $800 million (our 30% share estimated at $240 million). We are also evaluating whether an additional Oglethorpe contingency is warranted as is consistent with our conservative budgeting practices. Further, improvements to the project control environment have been implemented and additional improvements will continue to be evaluated.

We expect Vogtle Units No. 3 and No. 4are currently in the process of evaluating the estimated increases to the project budget. The impact of these additional project costs on our budget will be placedsubstantially mitigated by approximately $500 million of contingency included in service by November 2021 and November 2022, respectively. Our projectour existing budget. We are in the process of preparing a revised budget for the additional Vogtle units is $7.0 billion, which includesthat would include capital costs, allowance for funds used during construction, our allocation of the project-level contingency as well as a potential, separate Oglethorpe contingency. If construction on the project continues, we anticipate that our project budget may increase from $7.0 billion to a range of $7.25 billion to $7.5 billion. A revised project budget will affect the timing and amount of the projected capital expenditures related to the Vogtle project previously disclosed, although the timing of such expenditures remains uncertain.

Georgia Power has stated that it does not intend to seek rate recovery for its proportionate share of the additional capital costs in its nineteenth VCM report to be filed with the Georgia Public Service Commission. As a contingency amount. result of Georgia Power's decision not to seek rate recovery of its allocation of these costs and the increased construction budget, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction. The Co-owners are expected to conduct these votes in the third quarter of 2018, and each of Georgia Power, Oglethorpe and MEAG will have to affirmatively vote to continue construction. If the Co-owners vote to move forward, they will also approve a revised project budget.

As of March 31,June 30, 2018, our total investment in the additional Vogtle units was approximately $3,160,067,000.
$3,396,731,000. In the event that fewer than 90% of the Co-owners determine to continue construction, we and the other Co-owners will assess options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval.

The scheduled in-service dates of November 2021 and November 2022 for Vogtle Units No. 3 and No. 4, respectively, are not expected to change in connection with these budget revisions. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $30 million per month based on our ownership interests and allowance for funds used during construction of approximately $12.5 million per month per unit.

Subsequent to Westinghouse's bankruptcy filing, a number of subcontractors to Westinghouse alleged non-payment by Westinghouse for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken actions to remove liens on the site filed by these subcontractors through the posting of surety




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bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against Westinghouse and the Co-owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and payment of other Westinghouse pre-petition accounts payable have been paid or accrued as of March 31,June 30, 2018.

We have a $3,057,069,461 federal loan guarantee from the Department of Energy, under which we have borrowed $1,764,658,000 as of June 30, 2018. Pursuant to the terms of the loan guarantee




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agreement, no further advances are permitted pending satisfaction of certain conditions. On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to $1,619,679,706 of additional guaranteed funding under the loan guarantee agreement. This conditional commitment expires on September 30, 2018, subject to any extension approved by the Department of Energy. We do not anticipate closing on the new loan before September 30, 2018 and anticipate seeking an extension from the Department of Energy. Final approval and issuance of the additional loan guarantee by the Department of Energy cannot be assured and is subject to an amendment and restatement of the loan guarantee agreement and satisfaction of other conditions, including the Co-owners vote to continue construction. For additional information regarding conditions for future advances, potential repayment over a five-year period, covenants and events of default under the loan guarantee agreement with the Department of Energy, see Note K.

We have also financed an additional $1,387,000,000 of the capital costs of the Vogtle units through capital market debt issuances. We anticipate financing any project costs not financed with Department of Energy in the capital markets. The timing and availability of funds under the Department of Energy loan guarantee will guide our decisions as to the timing of any capital markets offerings.

As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors, and vendors, labor productivity, and availability, and/or cost escalation; procurement, fabrication, delivery, assembly andand/or installation, including any required engineering changes, of plant systems, structures and components, or other issues could further impact the projected schedule and cost. Monthly construction production targets required to maintain the current project schedule increase significantly later in 2018 through 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be deployed. Aspects of the Westinghouse AP1000 design are based on new technologies and commercialthat are just beginning initial operation ofin the global nuclear industry at this design has yet to be tested.
scale.

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 level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating 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 matters, including the timely resolution of inspections, tests, analyses, and acceptance criteria and the related approvals by the Nuclear Regulatory Commission, may arise, 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 ultimate outcome of these matters cannot be determined at this time.




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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

For the ThreeSix Months Ended March 31,June 30, 2018 and 2017

Net Margin

Our net margins for the three-month periodand six-month periods ended March 31,June 30, 2018 were $27.4$17.3 million and $44.7 million compared to $21.5$15.7 million and $37.1 million for the same periodperiods of 2017. Through March 31,June 30, 2018, we collectedrecognized approximately 53%86% of our targeted net margin of $52.1$51.6 million for the year ending December 31, 2018. These collections are typical as our capacity revenues are generally recorded evenly throughout the year and our management budgets conservatively.year. We have assessed our annual revenue requirements as of March 31, 2018 and concluded that recording a refund liability is not required based on our current projections. Historically,anticipate our board of directors approveswill approve a budget adjustment by theyear end of the year so that margins will achieve, but not exceed, the 2018 targeted 1.14 margins for interest ratio which is 1.14of 1.14. Pursuant to our adoption of Revenue from Contracts with Customers (Topic 606), we assessed the annual revenue requirement needed to meet the targeted margins for interest ratio and recorded a refund liability of $5.7 million during the second quarter of 2018. In addition, the 2017 revenues for the three-month and six-month periods have been adjusted to reflect a $5.8 million refund liability as of June 30, 2017. 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" in our 2017 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, andelectricity. These revenues 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 sellingthe sales of electricity to our members, which involves generatinggenerated or purchasing electricitypurchased for our members. Energy revenues recover the variable costs of our business, including fuel, purchased energy and variable operation and maintenance expense.




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The components of member revenues for the three-month and six-month periods ended March 31,June 30, 2018 and 2017 were as follows:

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			Three Months Ended March 31,						2018 vs. 2017 % Change				Three Months Ended June 30,						2018 vs. 2017 % Change			Six Months Ended June 30,						2018 vs. 2017 % Change
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			(dollars in thousands)										(dollars in thousands)									(dollars in thousands)
			2018			2017							2018			2017						2018			2017
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Capacity revenues		$	240,481		$	237,432			1.3%			$	231,571		$	229,946			0.7%		$	472,052		$	467,377			1.0%
Energy revenues			132,920			116,712			13.9%				134,240			131,377			2.2%			267,160			248,090			7.7%
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Total		$	373,401		$	354,144			5.4%			$	365,811		$	361,323			1.2%		$	739,212		$	715,467			3.3%
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MWh Sales to members			5,100,326			5,324,823			(4.2%)				5,926,738			5,925,578			0.0%			11,027,064			11,250,401			(2.0%)
Cents/kWh			7.32			6.65			10.1%				6.17			6.10			1.2%			6.70			6.36			5.4%
Member energy requirements supplied			54	%		64	%		(15.6%)				62	%		64	%		(3.1%)			58	%		64	%		(9.1%)
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Energy revenues from members increased for the three-monththree and six-month period ended March 31,June 30, 2018 compared to the same period inJune 30, 2017 primarily due to the recovery of fuel costs. For a discussion of fuel costs, which are the primary components of energy revenues, see "—Operating Expenses."




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Operating Expenses

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

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			Cost									Generation									Cents per kWh										Cost									Generation									Cents per kWh
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			(dollars in thousands)									(MWh)																			(dollars in thousands)									(MWh)
			Three Months Ended March 31,						2018 vs.			Three Months Ended March 31,						2018 vs.			Three Months Ended March 31,						2018 vs.				Three Months Ended June 30,						2018 vs.			Three Months Ended June 30,						2018 vs.			Three Months Ended June 30,						2018 vs.
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Fuel Source			2018			2017			2017 % Change			2018			2017			2017 % Change			2018			2017			2017 % Change				2018			2017			2017 % Change			2018			2017			2017 % Change			2018			2017			2017 % Change
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Coal		$	18,201		$	19,629			(7.3%)			590,052			661,135			(10.8%)			3.08			2.97			3.9%			$	31,361		$	31,313			0.2%			1,048,979			1,094,066			(4.1%)			2.99			2.86			4.5%
Nuclear			20,823			20,542			1.4%			2,484,443			2,277,498			9.1%			0.84			0.90			(7.1%)				21,660			22,747			(4.8%)			2,597,891			2,536,188			2.4%			0.83			0.90			(7.0%)
Gas:
Combined Cycle			72,317			61,747			17.1%			2,121,146			2,480,997			(14.5%)			3.41			2.49			37.0%				57,012			52,433			8.7%			2,168,551			2,177,166			(0.4%)			2.63			2.41			9.2%
Combustion Turbine			9,106			1,996			356.2%			55,786			42,806			30.3%			16.32			4.66			250.1%				12,111			12,231			(1.0%)			298,698			294,414			1.5%			4.05			4.15			(2.4%)
​	​	​	​	​		​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​		​	​	​	​	​
		$	120,447		$	103,914			15.9%			5,251,427			5,462,436			(3.9%)			2.29			1.90			20.6%			$	122,144		$	118,724			2.9%			6,114,119			6,101,834			0.2%			2.00			1.95			2.7%
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​
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Cost

Generation

Cents per kWh

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(dollars in thousands)

(MWh)

Six Months Ended June 30,

2018 vs.

Six Months Ended June 30,

2018 vs.

Six Months Ended June 30,

2018 vs.

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Fuel Source

2018

2017

2017 % Change

2018

2017

2017 % Change

2018

2017

2017 % Change

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Coal

$

49,561

$

50,943

(2.7%)

1,639,031

1,755,201

(6.6%)

3.02

2.90

4.2%

Nuclear

42,483

43,289

(1.9%)

5,082,334

4,813,686

5.6%

0.84

0.90

(7.0%)

Gas:

Combined Cycle

129,331

114,160

13.3%

4,289,697

4,658,163

(7.9%)

3.01

2.45

23.0%

Combustion Turbine

21,216

14,246

48.9%

354,484

337,220

5.1%

5.99

4.22

41.7%

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$

242,591

$

222,638

9.0%

11,365,546

11,564,270

(1.7%)

2.13

1.93

10.9%

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Total fuel costs increased for the three-month periodand six-month periods ended March 31,June 30, 2018 compared to the same periodperiods of 2017 primarily due to increased natural gas transportation costs associated with a new pipeline, which was placed into service in August 2017. The six-month period increase was also impacted by higher natural gas prices, particularly during January 2018 when extreme cold weather affected the supply and transportation of natural gas. In addition to the natural gas consumed being more expensive, the higher cost contributed to a shift in generation to oil and coal-fired units. An unplanned outage at one of our coal-fired units also contributed to the shift in generation to relatively more expensive units. Total generation for first quarter 2018 decreased largely due to plant outages, which in part resulted in members procuring a larger portionunits at the beginning of their energy requirements from other sources as compared to first quarter 2017.




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Financial Condition

Balance Sheet Analysis as of March 31,June 30, 2018

Assets

Cash used for property additions for the three-monthsix-month period ended March 31,June 30, 2018 totaled $285.4$561.0 million. Of this amount, $218.3$451.6 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4, $48.7 million related to environmental control projects at our coal-fired plants and $23.8$33.7 million was for nuclear fuel purchases. The remainder was for expenditures related to normal additions and replacements to our existing generation facilities.




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Restricted investments consist 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 our 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.

Receivables decreased $29.0 million for the three-month period ended March 31, 2018 primarily due to receipt of working capital advanced to contractors in connection with the Vogtle Units No. 3 and No. 4 construction project. In addition, a decline in member sales contributed to the decrease in receivables for the period.

Equity and Liabilities

Long-term debt decreased $353.8$147.9 million and long-termduring the six-month period ended June 30, 2018 primarily as a result of the classification of amounts with maturities due within one year to current, offset by $236.2 million of advances on existing Rural Utilities Service loans.

Long-term debt and capital leases due within one year increased $329.6$337.6 million primarily due to $350 million of first mortgage bonds maturing in March 2019 that were classified as current debt during the three-month period ended March 31, 2018.period.

Short-term borrowings, which primarily provide interim financing for Vogtle Units No. 3 and No. 4 construction costs, increased $68.2$247.4 million during the three-monthsix-month period ended March 31,June 30, 2018.

Accounts payable decreased $55.9 million during the three-month period ended March 31, 2018. Payables to Georgia Power for capital costs associated with the Vogtle Units No. 3 and No. 4 and for operation and maintenance costs for our co-owned plants decreased $22.7 million as compared to December 31, 2017. Also contributing to the decrease was $29.1 million in credits, applied to our members' bills in the first quarter of 2018, for a board-approved reduction in 2017 revenue requirements as a result of margin collections in excess of our 2017 target.

Capital Requirements and Liquidity and Sources of Capital

Vogtle Units No. 3 and No. 4

We, Georgia Power, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our ownership interest and proportionate share of the cost to construct these units is 30%. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services.

In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, Westinghouse agreed to design, engineer, procure, construct and test




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two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle.

Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. In connection with the bankruptcy filing, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with Westinghouse and WECTEC Staffing Services LLC to provide for a continuation of work at Vogtle Units No. 3 and No. 4. The Interim Assessment Agreement expired in July 2017 upon the effective date of the Services Agreement.

Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technologicaltechnical support and staff augmentation on a time and materials cost basis. The Services Agreement will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days' written notice.




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In October 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, wherebypursuant to which Bechtel will serveserves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including, certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events. Pursuant to the loan guarantee agreement between us and the Department of Energy, we are required to obtain the Department of Energy's approval of the Bechtel Agreement prior to obtaining any further advances under the loan guarantee agreement.

In November 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 (as amended, the Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. Pursuant to the Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent;rates; or (iv) an increase in the construction budget contained in Georgia Power's seventeenth Vogtle construction monitoring (VCM) report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Joint Ownership Agreements, the required approval of holders of ownership interests in Vogtle Units No. 3 and No. 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.




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On December 21, 2017, the Georgia Public Service Commission took a series of actions related to the construction of Vogtle Units No. 3 and No. 4 and issued its related order on January 11, 2018. Among other actions, the Public Service Commission (i) accepted Georgia Power's recommendation thatto continue construction of Vogtle Units No. 3 and No. 4, be completed, with Southern Nuclear Operating Company, Inc. serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Public Service Commission reservereserved the right to reconsider the decision to continue construction. Parties have filed two petitions with the Fulton County Superior Court appealing the Georgia Public Service Commission's January 11, 2018 order. Georgia Power has stated that it believes these appeals have no merit; however, an adverse outcome in either appeal could have a material impact on our financial condition and results of operations.

Georgia Power has advised us that it recently became aware that the estimated future Vogtle project costs were projected to exceed the corresponding budgeted amounts. Upon discovery of these variances, the Co-owners requested Southern Nuclear perform a full cost analysis and reforecast of the cost to complete the project and engaged a third party to independently assess this analysis, forecast,




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and existing project controls for identifying budget variances. The capital costs estimated to complete construction are expected to increase by approximately $1.5 billion (our 30% share estimated at approximately $450 million). The increases are primarily due to changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, craft labor incentives, as well as the related levels of project management, oversight and support, including field supervision and engineering support, required to complete the project. We, expect Vogtle Units No. 3 and No. 4the other Co-owners, are evaluating these increased capital costs along with a project-level contingency in a preliminary amount of approximately $800 million (our 30% share estimated at $240 million). We are also evaluating whether an additional Oglethorpe contingency is warranted as is consistent with our conservative budgeting practices. Further, improvements to the project control environment have been implemented and additional improvements will continue to be placedevaluated.

We are currently in servicethe process of evaluating the estimated increases to the project budget. The impact of these additional project costs on our budget will be substantially mitigated by November 2021 and November 2022, respectively. Our projectapproximately $500 million of contingency included in our existing budget. We are in the process of preparing a revised budget for the additional Vogtle units is $7.0 billion, which includesthat would include capital costs, allowance for funds used during construction, our allocation of the project-level contingency as well as a potential, separate Oglethorpe contingency. If construction on the project continues, we anticipate that our project budget may increase from $7.0 billion to a range of $7.25 to $7.5 billion. A revised project budget will affect the timing and amount of the projected capital expenditures related to the Vogtle project disclosed in our Form 10-K, although the timing of such expenditures remains uncertain.

Georgia Power has stated that it does not intend to seek rate recovery for its proportionate share of the additional capital costs in its nineteenth VCM report to be filed with the Georgia Public Service Commission. As a contingency amount. result of Georgia Power's decision not to seek rate recovery of its allocation of these costs and the increased construction budget, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction. The Co-owners are expected to conduct these votes in the third quarter of 2018, and each of Georgia Power, Oglethorpe and MEAG will have to affirmatively vote to continue construction. If the Co-owners vote to move forward, they will also approve a revised project budget.

As of March 31,June 30, 2018, our total investment in the additional Vogtle units was $3.2approximately $3.4 billion. In the event that fewer than 90% of the Co-owners determine to continue construction, we and the other Co-owners will assess options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval.

The scheduled in-service dates of November 2021 and November 2022 for Vogtle Units No. 3 and No. 4, respectively, are not expected to change in connection with these budget revisions. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $30 million per month based on our ownership interests and allowance for funds used during construction of approximately $12.5 million per month per unit.

Subsequent to Westinghouse's bankruptcy filing, a number of subcontractors to Westinghouse alleged non-payment by Westinghouse for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken actions to remove liens on the site filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against Westinghouse and the Co-owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and payment of other Westinghouse pre-petition accounts payable have been paid or accrued as of March 31,June 30, 2018.




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We have a $3.1 billion federal loan guarantee from the Department of Energy, under which we have borrowed $1.75$1.8 billion as of March 31,June 30, 2018. Pursuant to the terms of the loan guarantee agreement, no further advances are permitted pending satisfaction of certain conditions, including approval of the Bechtel Agreement and an amendment to the loan guarantee agreement to incorporate provisions relating to the Bechtel Agreement and other replacement agreements. We expect to satisfy these conditions in June 2018.conditions. On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to $1.6 billion of additional guaranteed funding under the loan guarantee agreement. This conditional commitment expires on JuneSeptember 30, 2018, subject to any extension approved by the Department of Energy. We do not anticipate closing on the new loan before September 30, 2018 and anticipate seeking an extension from the Department of Energy. Final approval and issuance of the additional loan guarantee by the Department of Energy cannot be assured and is subject to an amendment and restatement of the loan guarantee agreement and satisfaction of certain other conditions.conditions, including the Co-owners vote to continue construction. For additional information regarding conditions for future advances, potential repayment over a five-year period, covenants and events of default under the loan guarantee agreement with the Department of Energy, see Note K of Notes to Unaudited Consolidated Financial Statements.

We have also financed an additional $1.4 billion of the capital costs of the Vogtle units through capital market debt issuances. We anticipate financing any project costs not financed with Department of Energy in the capital markets. The timing and availability of funds under the Department of Energy loan guarantee will guide our decisions as to the timing of any capital markets offerings. For additional information regarding the financing of Vogtle Units No. 3 and No. 4, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS"Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Financing Activities—Department of Energy-Guaranteed Loan" and "Capital Requirements—Capital Expenditures."

Under the Bipartisan Budget Act of 2018, we qualify for nuclear production tax credits related to Vogtle Units No. 3 and No. 4. We expect to receive these tax credits in accordance with our 30% ownership interest in the Vogtle Units and are analyzing various options to monetize these credits with a third party. We estimate that the nominal value of our allocation of production tax credits will be approximately $660 million and will be earned for eight years post commercial operation.




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As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors, and vendors, labor productivity, and availability, and/or cost escalation; procurement, fabrication, delivery, assembly andand/or installation, including any required engineering changes, of plant systems, structures and components, or other issues could further impact the projected schedule and cost. Monthly construction production targets required to maintain the current project schedule increase significantly later in 2018 through 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be deployed. Aspects of the Westinghouse AP1000 design are based on new technologies and commercialthat are just beginning initial operation ofin the global nuclear industry at this design has yet to be tested.scale.

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 level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating 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 matters, including the timely resolution of inspections, tests, analyses, and acceptance criteria and the related approvals by the Nuclear Regulatory Commission, may arise, 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 ultimate outcome of these matters cannot be determined at this time.

See "RISK FACTORS" in our 2017 Form 10-K"Risk Factors" for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.




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Environmental Regulations

Federal and state laws and regulations regarding environmental matters affect operations at our facilities.facilities and are subject to change over time.

On July 30, 2018, the Environmental Protection Agency published the first of two final rules in the Federal Register that revised a portion of its 2015 coal combustion residual rule. The revisions provide relief from several mandatory closure requirements and provide significant flexibility for facility owners to implement the coal combustion residuals disposal and management requirements.

For a 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 2017 Form 10-K.

Liquidity

At March 31,June 30, 2018, we had $1.35$1.44 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $249$525 million in cash and cash equivalents and $1.1 billion$920 million of unused and available committed credit arrangements.




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At March 31,June 30, 2018, we had $1.61 billion of committed credit arrangements in place, the details of which are reflected in the table below:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Committed Credit Facilities

Committed Credit Facilities

Committed Credit Facilities

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Authorized Amount

Available March 31, 2018

Expiration Date

Authorized Amount

Available June 30, 2018

Expiration Date

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

(dollars in millions)

(dollars in millions)

Unsecured Facilities:

Syndicated Line of Credit led by CFC

$

1,210

$

815

(1)

March 2020

$

1,210

$

636

(1)

March 2020

CFC Line of Credit(2)

110

110

December 2018

110

110

December 2018

JPMorgan Chase Line of Credit

150

34

(3)

October 2018

150

34

(3)

October 2018

Secured Facilities:

CFC Term Loan(2)

140

(2)

140

(2)

December 2018

140

140

December 2018

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Total

$

1,610

$

1,099

$

1,610

$

920

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

⁽¹⁾

Of the portion of this facility that was unavailable at March 31,June 30, 2018, $259$438 million was dedicated to support outstanding commercial paper and $136 million was related to letters of credit issued to support variable rate demand bonds.



⁽²⁾

Under the secured term loan with CFC, we can borrow up to $250 million. However, any amounts drawn under the $110 million unsecured line of credit with CFC will reduce the amount that can be drawn under the term loan. Therefore, we reflect $140 million as the amount authorized and available under the term loan even though no amounts have been borrowed under that facility. Any amounts borrowed under the $250 million term loan would be secured under our first mortgage indenture, with a maturity no later than December 31, 2043.



⁽³⁾

Of the portion of this facility that was unavailable at March 31,June 30, 2018, $114 million related to letters of credit issued to support variable rate demand bonds and $2 million related to letters of credit issued to post collateral to third parties.

Currently, we are primarily using our commercial paper program to provide interim funding for payments related to the construction of Vogtle Units No. 3 and No. 4 prior to receiving advances of long-term funding under the Department of Energy-guaranteed Federal Financing Bank loan.loan or issuing debt in the capital markets. At June 30, 2018, $429 million of our commercial paper outstanding was related to the Vogtle construction. See Note K of Notes to Unaudited Consolidated Financial Statements and "—Department of Energy-Guaranteed Loan" below for a discussion of our ability to




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request further loan advances from the Department of Energy pending satisfaction of certain conditions relating to the Vogtle project, including an amendment to the loan guarantee agreement.project.

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.

We expect to renew our $150 million line of credit with JPMorgan Chase Bank prior to its expiration in October 2018 for a term of three years.

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 March 31,June 30, 2018. 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 March 31,June 30, 2018, the required minimum level was $675 million and our actual patronage capital was $938$956 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 March 31,June 30, 2018, we had $8.2$8.5 billion of secured indebtedness and $259$438 million of unsecured indebtedness outstanding.




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At March 31,June 30, 2018, we had $853$805 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 March 31,June 30, 2018—Assets" for more information regarding this account.

Financing Activities

First Mortgage Indenture.    At March 31,June 30, 2018, we had $8.2$8.4 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 2017 Form 10-K for further discussion of our first mortgage indenture.

Rural Utilities Service-Guaranteed Loans.    At March 31,June 30, 2018, we had two approved Rural Utilities Service-guaranteed loans being funded through the Federal Financing Bank that are in various stages of being drawn down. These two loans totaled $678 million with $248$215 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As of March 31,June 30, 2018, we had $2.4$2.6 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.

Department of Energy-Guaranteed Loan.    In 2014, we entered into a loan guarantee agreement with the Department of Energy that we expect willto fund up to $3.1 billion of the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. The loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by the Department of Energy. At March 31,June 30, 2018, we had borrowed $1.7$1.8 billion, including capitalized interest, under this loan and we had the capacity to fund an additional $1.3$1.1 billion under the facility based on the amount of eligible project costs already incurred.

Our last advance under this loan was in December 2016. Following the bankruptcy of Westinghouse in March 2017, the loan guarantee agreement was amended to restrict further advances pending the satisfaction of certain conditions, including the Department of Energy's approval of the Bechtel Agreement and a further amendment to the loan guarantee agreement to




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incorporate provisions related to the Bechtel Agreement and other replacement agreements. While not assured, we expect to satisfy these conditions in June 2018 and to request an advance in the third quarter of 2018.

In September 2017, the Department of Energy issued a conditional commitment to us for $1.6 billion of additional guaranteed funding under the loan guarantee agreement. This additional funding is subject to an amendment and restatement of the loan guarantee agreement, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of certain other conditions. FinalDue to the new estimate-to-complete forecast provided by Georgia Power and Southern Nuclear, a resumption of funding under the original loan and approval and issuance of the additional loan guarantee cannot be assured. are now also subject to the Co-owners vote to continue the Vogtle construction.

The conditional commitment expires on JuneSeptember 30, 2018, subject to any extension approved by the Department of Energy. WhileWe do not assured, we expect to closeanticipate closing on this facility in June 2018.the new loan before September 30, 2018, and anticipate seeking an extension from the Department of Energy. If closed, our aggregate Department of Energy loan financing for the Vogtle expansion project will increase to nearly $4.7 billion. Final approval and issuance of the additional loan guarantee cannot be assured.

All of the debt advanced under the loan guarantee agreement is secured ratably with all other debt under our first mortgage indenture. For additional information regarding this loan, see Note K of Notes to Unaudited Consolidated Financial Statements.

At March 31,June 30, 2018, we had funded in the aggregate approximately $3.1$3.2 billion of our Vogtle project cost. In addition to the Department of Energy funding, we have issued $1.4 billion of first mortgage bonds to finance a portion of the Vogtle expansion that will not be funded by the Department of Energy.expansion. We expect to finance theany Vogtle project costs not covered by the Department of Energy-guaranteed loans with additional capital market financings.




Table In light of Contentsthe continued delay in obtaining funds from the Department of Energy, we may undertake a capital markets financing later in 2018.

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 2017 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 2017 Form 10-K.

Item 4.    Controls and Procedures


As of March 31,June 30, 2018, 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 March 31,June 30, 2018 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


There have been no material changes to the legal proceedings disclosed in "Item 3—LEGAL PROCEEDINGS" in our 2017 Form 10-K.

Item 1A.    Risk Factors


Except as described below, there have been no material change to these risk factors from those previously disclosed in the Form 10-K.

Our participation in the development and construction of Vogtle Units No. 3 and No. 4 could have a material impact on our financial condition and results of operations.

We are participating in the construction of two additional nuclear units at Plant Vogtle and have committed significant capital expenditures to this endeavor. The construction of large, complex generating plants involves significant financial risk. We rely on Georgia Power and Southern Nuclear as our agents for the oversight of the construction of the additional units at Plant Vogtle and do not exercise direct control over the construction process.

Our current project budget for the Vogtle Units, which includes capital costs, allowance for funds used during construction and a contingency amount is $7.0 billion and the scheduled commercial operation dates are November 2021 for Unit No. 3 and November 2022 for Unit No. 4. Georgia Power has advised us that it recently became aware that the estimated future Vogtle project costs were projected to exceed the corresponding budgeted amounts. Upon discovery of these variances, the Co-owners requested Southern Nuclear perform a full cost analysis and reforecast of the cost to complete the project and engaged a third party to independently assess this analysis, forecast, and existing project controls for identifying budget variances. The capital costs estimated to complete construction are expected to increase by approximately $1.5 billion (our 30% share estimated at approximately $450 million). The increases are primarily due to changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, craft labor incentives, as well as the related levels of project management, oversight and support, including field supervision and engineering support, required to complete the project. We, and the other Co-owners, are evaluating these increased capital costs along with a project-level contingency in a preliminary amount of approximately $800 million (our 30% share estimated at $240 million). We are also evaluating whether an additional Oglethorpe contingency is warranted as is consistent with our conservative budgeting practices. Further, improvements to the project control environment have been implemented and additional improvements will continue to be evaluated.

We are currently in the process of evaluating the estimated increases to the project budget. The impact of these additional project costs on our budget will be substantially mitigated by approximately $500 million of contingency included in our existing budget. We are in the process of preparing a revised budget that would include capital costs, allowance for funds used during construction, our allocation of the project-level contingency as well as a potential, separate Oglethorpe contingency. If construction on the project continues, we anticipate that our project budget may increase from $7.0 billion to a range of $7.25 to $7.5 billion. A revised project budget will affect the timing and amount of the projected capital expenditures related to the Vogtle project disclosed in our Form 10-K, although the timing of such expenditures remains uncertain. Any budget increase would likely increase our capital expenditures through 2022 and lead to a corresponding increase in our long-term debt outstanding at completion of the Vogtle units from the previously disclosed amount of approximately $11.5 billion. These increases in capital expenditures and in our long-term debt will continue to constrain our equity ratio and will affect certain of our financial metrics. Increased debt and the related impacts on our financial metrics could negatively impact our credit ratings. Any downgrade in our




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credit ratings would increase our borrowing costs and decrease our access to the credit and capital markets.

We and the other Co-owners are responsible for all construction costs based on our ownership percentages. Factors that could lead to further cost increases and schedule delays or even the inability to complete this project include:

•

performance by Georgia Power as agent for the Co-owners and performance by Southern Nuclear as construction manager;



•

performance by Bechtel under the Bechtel Agreement as well as subcontractor and supplier performance, including compliance with the design specifications approved and quality standards set forth by the Nuclear Regulatory Commission;



•

changes in labor costs and productivity;



•

performance by Westinghouse under the Services Agreement;



•

loss of access to intellectual property rights necessary to construct or operate the project;



•

shortages and/or inconsistent quality of equipment, materials and labor;



•

increases in our cost of debt financing as a result of changes in market interest rates or as a result of construction schedule delays;



•

unforeseen engineering or design problems;



•

erosion of public and policymaker support;



•

liens on the project;



•

contract disputes;



•

permits, approvals and other regulatory matters;



•

unanticipated increases in the costs of materials;



•

changes in project design or scope;



•

impacts of new and existing laws and regulations, including environmental laws and regulations;



•

adverse weather conditions; and



•

work stoppages.

In November 2017, the Co-owners entered into an amendment to their Joint Ownership Agreements for Vogtle Units No. 3 and No. 4 to provide for, among other conditions, additional Co-owner approval requirements. Pursuant to the Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates; or (iv) an increase in the construction budget contained in Georgia Power's seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year.

Georgia Power has stated that it does not intend to seek rate recovery for its proportionate share of the additional capital costs in its nineteenth VCM report to be filed with the Georgia Public Service Commission. As a result of Georgia Power's decision not to seek rate recovery of its allocation of these costs and the increased construction budget, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction. The Co-owners are expected to




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conduct these votes in the third quarter of 2018, and each of Georgia Power, Oglethorpe and MEAG will have to affirmatively vote to continue construction. If the Co-owners vote to move forward, they will also approve a revised project budget.

As of June 30, 2018, our total investment in the additional Vogtle units was approximately $3.4 billion. In the event that fewer than 90% of the Co-owners determine to continue construction, we and the other Co-owners will assess options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval.

The scheduled in-service dates of November 2021 and November 2022 for Vogtle Units No. 3 and No. 4, respectively, are not expected to change in connection with these budget revisions. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $30 million per month based on our ownership interests and allowance for funds used during construction of approximately $12.5 million per month per unit.

As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors, and vendors, labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly and/or installation, including any required engineering changes, of plant systems, structures and components, or other issues could further impact the projected schedule and cost. Monthly construction production targets required to maintain the current project schedule increase significantly later in 2018 through 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be deployed. Aspects of the Westinghouse AP1000 design are based on new technologies that are just beginning initial operation in the global nuclear industry at this scale.

There have been no material changestechnical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating 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 matters, including the timely resolution of inspections, tests, analyses, and acceptance criteria and the related approvals by the Nuclear Regulatory Commission, may arise, 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 long-term project cost will also be impacted by our ability to finance the capital costs at competitive interest rates. We have a $3.1 billion federal loan guarantee from the risk factors disclosedDepartment of Energy, under which we have borrowed $1.8 billion as of June 30, 2018. Pursuant to the terms of the loan guarantee agreement, no further advances are permitted pending satisfaction of certain conditions. On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to $1.6 billion of additional guaranteed funding under the loan guarantee agreement. This conditional commitment expires on September 30, 2018, subject to any extension approved by the Department of Energy. We do not anticipate closing on the new loan before September 30, 2018 and anticipate seeking an extension from the Department of Energy. Final approval and issuance of the additional loan guarantee by the Department of Energy cannot be assured and is subject to an amendment and restatement of the loan guarantee agreement and satisfaction of other conditions, including the Co-owners vote to continue construction.

We anticipate financing any project costs not financed with Department of Energy in "Item 1A—RISK FACTORS" inthe capital markets. The timing and availability of funds under the Department of Energy loan guarantee will




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guide our 2017 Form 10-K.decisions as to the timing of any capital markets offerings. Prolonged inability to access funding pursuant to the Department of Energy loan guarantee agreement may constrain our liquidity and lead us to finance certain expenditures through alternative resources, likely at a higher interest rate.

The ultimate outcome of these matters cannot be determined at this time; however, these risks could continue to impact the in-service dates and cost of the additional units at Plant Vogtle which would increase the cost of electric service we provide to our members and, as a result, could affect their ability to perform their contractual obligations to us.

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.




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Item 6.    Exhibits


Number			Description
	10.131.1		Third Amendment to Plant Hal Wansley Operating Agreement, dated as of April 15, 2018, by and among Georgia Power Company, Oglethorpe and City of Dalton.
	31.1		Rule 13a-14(a)/15d-14(a) Certification, by Michael L. Smith (Principal Executive Officer).
	31.2		Rule 13a-14(a)/15d-14(a) Certification, by Elizabeth B. Higgins (Principal Financial Officer).
	32.1		Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Michael L. Smith (Principal Executive Officer).
	32.2		Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Elizabeth B. Higgins (Principal Financial Officer).
	99.1		Member Financial and Statistical Information (for calendar years 2015-2017).
	101		XBRL Interactive Data File.




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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.

				Oglethorpe Power Corporation (An Electric Membership Corporation)
Date: MayAugust 10, 2018		By:		/s/ Michael L. Smith
				Michael L. Smith President and Chief Executive Officer
Date: MayAugust 10, 2018				/s/ Elizabeth B. Higgins
				Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)