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

FORM 10-Q

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2019
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                                    to

Commission File No. 333-192954

(An Electric Membership Corporation)

(Exact name of registrant as specified in its charter)

Georgia (State or other jurisdiction of incorporation or organization)	58-1211925 (I.R.S. employer identification no.)
2100 East Exchange Place Tucker, Georgia (Address of principal executive offices)	30084-5336 (Zip Code)
Registrant's telephone number, including area code	(770) 270-7600

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

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

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer o    Accelerated Filer o    Non-Accelerated Filer ý    Smaller Reporting Company o    Emerging Growth Company o

        If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

        Securities registered pursuant to Section 12(b) of the Act:

Title of each class:	Trading Symbol(s)	Name of each exchange on which registered:
None	N/A	N/A

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

OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2019

		Page No.
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Consolidated Balance Sheets as of March 31, 2019 and December 31, 2018	1
	Unaudited Consolidated Statements of Revenues and Expenses For the Three Months ended March 31, 2019 and 2018	3
	Unaudited Consolidated Statements of Patronage Capital and Membership Fees For the Three Months ended March 31, 2019 and 2018	4
	Unaudited Consolidated Statements of Cash Flows For the Three Months ended March 31, 2019 and 2018	5
	Notes to Unaudited Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 4.	Controls and Procedures	30
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 3.	Defaults Upon Senior Securities	31
Item 4.	Mine Safety Disclosures	31
Item 5.	Other Information	31
Item 6.	Exhibits	32
SIGNATURES		33

i

CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING STATEMENTS

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

Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. Some of the risks, uncertainties and assumptions that may cause actual results to differ from these forward-looking statements are described under "Item 1A—RISK FACTORS" and in other sections of our annual report on Form 10-K for the fiscal year ended December 31, 2018 and in this quarterly report on Form 10-Q. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this quarterly report may not occur.

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

•

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

•

a decision by Georgia Power Company to cancel the additional Vogtle units or a decision by more than 10% of the co-owners of the additional Vogtle units not to proceed with the construction of the additional Vogtle units upon the occurrence of certain material adverse events;

•

decisions made by the Georgia Public Service Commission in the regulatory process related to the two additional units at Plant Vogtle;

•

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

•

our continued ability to receive advances under the U.S. Department of Energy loan guarantee agreement for construction of two additional nuclear units at Plant Vogtle;

•

the occurrence of certain events that give the Department of Energy the option to require that we repay all amounts outstanding under the loan guarantee agreement with the Department of Energy over a five-year period and the Department of Energy's decision to require such repayment;

•

the continued availability of funding from the Rural Utilities Service;

•

increasing debt caused by significant capital expenditures;

•

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

ii

•

actions by credit rating agencies;

•

commercial banking and financial market conditions;

•

the impact of regulatory or legislative responses to climate change initiatives or efforts to reduce greenhouse gas emissions, including carbon dioxide;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

changes in technology available to and utilized by us, our competitors, or residential or commercial consumers in our members' service territories, including from the development and deployment of distributed generation and energy storage technologies;

•

the inability of counterparties to meet their obligations to us, including failure to perform under agreements;

•

litigation or legal and administrative proceedings and settlements;

•

our members' ability to perform their obligations to us;

•

our members' ability to offer their residential, commercial and industrial customers competitive rates;

•

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

•

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

•

general economic conditions;

•

weather conditions and other natural phenomena;

•

unanticipated changes in interest rates or rates of inflation;

•

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

•

significant changes in critical accounting policies material to us;

•

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

•

other factors discussed elsewhere in this quarterly report and in other reports we file with the SEC.

iii

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Oglethorpe Power Corporation
Consolidated Balance Sheets (Unaudited)
March 31, 2019 and December 31, 2018

		(dollars in thousands)
	2019			2018
Assets
Electric plant:
In service	$	9,028,219		$	8,981,238
Right-of-use assets—finance leases		302,732			302,732
Less: Accumulated provision for depreciation		(4,720,700	)		(4,544,405	)
		4,610,251			4,739,565
Nuclear fuel, at amortized cost		368,325			358,358
Construction work in progress		4,119,600			3,866,042
Total electric plant		9,098,176			8,963,965
Investments and funds:
Nuclear decommissioning trust fund		462,043			420,818
Investment in associated companies		75,621			77,037
Long-term investments		178,186			164,125
Restricted investments		511,211			503,158
Other		24,260			24,259
Total investments and funds		1,251,321			1,189,397
Current assets:
Cash and cash equivalents		341,398			752,618
Restricted short-term investments		150,000			150,000
Receivables		163,605			153,647
Inventories, at average cost		268,291			259,087
Prepayments and other current assets		13,070			8,098
Total current assets		936,364			1,323,450
Deferred charges:
Regulatory assets		780,077			655,063
Prepayments to Georgia Power		36,517			29,459
Other		18,566			21,934
Total deferred charges		835,160			706,456
Total assets	$	12,121,021		$	12,183,268

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

1

Oglethorpe Power Corporation
Consolidated Balance Sheets (Unaudited)
March 31, 2019 and December 31, 2018

		(dollars in thousands)
	2019		2018
Equity and Liabilities
Capitalization:
Patronage capital and membership fees	$	985,882	$	962,286
Long-term debt		8,879,245		8,727,148
Obligation under finance leases		81,730		81,730
Other		24,546		21,428
Total capitalization		9,971,403		9,792,592
Current liabilities:
Long-term debt and finance leases due within one year		221,317		522,289
Short-term borrowings		98,151		—
Accounts payable		143,580		206,577
Accrued interest		89,405		60,971
Member power bill prepayments, current		169,638		224,957
Other current liabilities		37,686		49,465
Total current liabilities		759,777		1,064,259
Deferred credits and other liabilities:
Asset retirement obligations		1,028,851		1,017,563
Member power bill prepayments, non-current		68,525		54,750
Regulatory liabilities		260,052		218,998
Other		32,413		35,106
Total deferred credits and other liabilities		1,389,841		1,326,417
Total equity and liabilities	$	12,121,021	$	12,183,268

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

2

Oglethorpe Power Corporation
Consolidated Statements of Revenues and Expenses (Unaudited)
For the Three Months Ended March 31, 2019 and 2018

		(dollars in thousands)
	Three Months
	2019			2018
Operating revenues:
Sales to Members	$	356,470		$	373,401
Sales to non-Members		130			245
Total operating revenues		356,600			373,646
Operating expenses:
Fuel		98,992			120,447
Production		103,320			101,272
Depreciation and amortization		62,303			56,788
Purchased power		16,065			15,888
Accretion		9,888			9,320
Total operating expenses		290,568			303,715
Operating margin		66,032			69,931
Other income:
Investment income		16,735			13,964
Other		1,829			1,974
Total other income		18,564			15,938
Interest charges:
Interest expense		101,448			90,571
Allowance for debt funds used during construction		(43,426	)		(35,100	)
Amortization of debt discount and expense		2,978			2,998
Net interest charges		61,000			58,469
Net margin	$	23,596		$	27,400

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

3

Oglethorpe Power Corporation
Consolidated Statements of Patronage Capital and Membership Fees (Unaudited)
For the Three Months Ended March 31, 2019 and 2018

		(dollars in thousands)
	Patronage Capital and Membership Fees
Balance at December 31, 2017	$	911,087
Components of comprehensive margin:
Net margin		27,400
Balance at March 31, 2018	$	938,487
Balance at December 31, 2018	$	962,286
Components of comprehensive margin:
Net margin		23,596
Balance at March 31, 2019	$	985,882

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

4

Oglethorpe Power Corporation
Consolidated Statements of Cash Flows (Unaudited)
For the Three Months Ended March 31, 2019 and 2018

		(dollars in thousands)
	2019			2018
Cash flows from operating activities:
Net margin	$	23,596		$	27,400
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel		93,497			91,608
Accretion cost		9,888			9,320
Amortization of deferred gains		(447	)		(447	)
Allowance for equity funds used during construction		(254	)		(209	)
Deferred outage costs		(20,803	)		(11,331	)
(Gain) loss on sale of investments		(791	)		1,290
Regulatory deferral of costs associated with nuclear decommissioning		(6,728	)		(6,835	)
Other		2,155			(1,394	)
Change in operating assets and liabilities:
Receivables		(9,938	)		30,958
Inventories		(9,204	)		(5,406	)
Prepayments and other current assets		(4,794	)		1,646
Accounts payable		(57,900	)		(55,431	)
Accrued interest		28,434			(1,058	)
Accrued taxes		12,156			(10,338	)
Other current liabilities		(26,280	)		(4,126	)
Member power bill prepayments		(41,544	)		8,661
Other		11,806			—
Total adjustments		(20,747	)		46,908
Net cash provided by operating activities		2,849			74,308
Cash flows from investing activities:
Property additions		(321,093	)		(285,374	)
Activity in nuclear decommissioning trust fund—Purchases		(80,733	)		(122,330	)
—Proceeds		78,628			120,409
(Increase) decrease in restricted investments		(8,053	)		29,829
Activity in other long-term investments—Purchases		(44,990	)		(43,844	)
—Proceeds		39,553			38,063
Other		(5,618	)		8,167
Net cash used in investing activities		(342,306	)		(255,080	)
Cash flows from financing activities:
Long-term debt proceeds		632,940			2,636
Long-term debt payments		(350,254	)		(39,350	)
(Decrease) increase in short-term borrowings, net		(338,476	)		68,171
Other		(15,973	)		730
Net cash (used in) provided by financing activities		(71,763	)		32,187
Net decrease in cash and cash equivalents		(411,220	)		(148,585	)
Cash and cash equivalents at beginning of period		752,618			397,695
Cash and cash equivalents at end of period	$	341,398		$	249,110
Supplemental cash flow information:
Cash paid for—
Interest (net of amounts capitalized)	$	29,222		$	55,772
Supplemental disclosure of non-cash investing and financing activities:
Accrued property additions at end of period	$	115,332		$	133,318
Interest paid-in-kind	$	15,710		$	14,393

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

5

Oglethorpe Power Corporation
Notes to Unaudited Consolidated Financial Statements

(A)

General.    The consolidated financial statements included in this report have been prepared by us pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the information furnished in this report reflects all adjustments (which include only normal recurring adjustments) and estimates necessary to fairly state, in all material respects, the results for the three-month periods ended March 31, 2019 and 2018. Examples of estimates used include items related to (i) our asset retirement obligations, such as closure and post-closure cost estimates, timing of expenditures, escalation factors and discount rates, and (ii) revenue recognition, such as determining the nature and timing of satisfaction of performance obligations, determining the standalone selling price of performance obligations and variable consideration. Actual results may differ from those estimates. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. Certain prior year amounts have been reclassified to conform with current year presentation.

These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018, as filed with the SEC. The results of operations for the three-month period ended March 31, 2019 are not necessarily indicative of results to be expected for the full year. As noted in our 2018 Form 10-K, our revenues consist primarily of sales to our 38 electric distribution cooperative members and, thus, the receivables on the consolidated balance sheets are principally from our members. See "Notes to Consolidated Financial Statements" in our 2018 Form 10-K.

(B)

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

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

•

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

•

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

•

Level 3.  Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that

6

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, 2019 and December 31, 2018.

	Fair Value Measurements at Reporting Date Using
		March 31, 2019		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	154,952	$	154,952	$	—	$	—
International equity trust		86,813		—		86,813		—
Corporate bonds and debt		57,108		—		56,297		811
US Treasury securities		51,850		51,850		—		—
Mortgage backed securities		51,222		—		51,222		—
Domestic mutual funds		50,292		50,292		—		—
Municipal bonds		425		—		425		—
Federal agency securities		3,942		—		3,942		—
Non-US Gov't bonds & private placements		1,425		—		1,425		—
Other		4,014		4,014		—		—
Long-term investments:
International equity trust		20,885		—		20,885		—
Corporate bonds and debt		11,658		—		11,152		506
US Treasury securities		14,277		14,277		—		—
Mortgage backed securities		11,791		—		11,791		—
Domestic mutual funds		94,326		94,326		—		—
Federal agency securities		934		—		934		—
Treasury STRIPS		23,677		—		23,677		—
Other		638		638		—		—
Natural gas swaps		8,867		—		8,867		—

7

	Fair Value Measurements at Reporting Date Using
		December 31, 2018		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	136,196	$	136,196	$	—	$	—
International equity trust		76,852		—		76,852		—
Corporate bonds and debt		51,356		—		48,853		2,503
US Treasury securities		47,712		47,712		—		—
Mortgage backed securities		56,004		—		56,004		—
Domestic mutual funds		43,359		43,359		—		—
Municipal bonds		278		—		278		—
Federal agency securities		6,066		—		6,066		—
Non-US Gov't bonds & private placements		964		—		964		—
Other		2,031		2,031		—		—
Long-term investments:								—
International equity trust		17,382		—		17,382
Corporate bonds and debt		12,571		—		11,366		1,205
US Treasury securities		12,062		12,062		—		—
Mortgage backed securities		11,517		—		11,517		—
Domestic mutual funds		94,494		94,494		—		—
Federal agency securities		941		—		941		—
Treasury STRIPS		14,113		—		14,113		—
Other		1,045		1,045		—		—
Natural gas swaps		13,154		—		13,154		—

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 exchanged traded. Although these securities may be liquid and priced daily, their inputs are not observable.

8

The following table presents the changes in Level 3 assets measured at fair value on a recurring basis during the three months ended March 31, 2019.

	Three Months Ended March 31, 2019
		Corporate bonds and debt
		(dollars in thousands)
Balance at December 31, 2018	$	3,708
Total gains or losses (realized/unrealized):
Changes in net assets		(2,391	)
Balance at March 31, 2019	$	1,317

The estimated fair values of our long-term debt, including current maturities at March 31, 2019 and December 31, 2018 were as follows (in thousands):

		2019				2018
		Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	9,209,076	$	10,003,168	$	9,347,307	$	9,837,254

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, 2019 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on 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.    We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. Our risk management and compliance committee provides general oversight over all derivative activities. We do not apply hedge accounting to derivative transactions, but instead apply regulated operations 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

9

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, 2019, 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.

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 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, 2019 and December 31, 2018, the estimated fair value of our natural gas contracts was a net liability of approximately $8,867,000 and $13,154,000, respectively.

As of March 31, 2019 and December 31, 2018, 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, 2019 due to our credit rating being downgraded below investment grade, we would have been required to post collateral or letters of credit of $8,867,000 with our counterparties.

10

The following table reflects the notional volume of our natural gas derivatives as of March 31, 2019 that is expected to settle or mature each year:

Year	Natural Gas Swaps (MMBTUs) (in millions)
2019	21.2
2020	22.1
2021	21.4
2022	12.7
2023	9.7
2024	1.4
Total	88.5

The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at March 31, 2019 and December 31, 2018.

	Balance Sheet Location		Fair Value
			2019		2018
			(dollars in thousands)
Assets:
Natural gas swaps	Other current assets	$	406	$	226
Liabilities:
Natural gas swaps	Other current liabilities	$	1,250	$	2,066
Natural gas swaps	Other deferred credits	$	8,023	$	11,314

The following table presents the gross realized gains and (losses) on derivative instruments recognized in margin for the three months ended March 31, 2019 and 2018.

	Statement of Revenues and Expenses Location		Three months ended March 31,
			2019			2018
			(dollars in thousands)
Natural Gas Swaps	Fuel	$	213		$	1,392
Natural Gas Swaps	Fuel		(673	)		(748	)
Total		$	(460	)	$	644

The following table presents the unrealized losses on derivative instruments deferred on the balance sheet at March 31, 2019 and December 31, 2018.

	Balance Sheet Location		2019		2018
			(dollars in thousands)
Natural gas swaps	Regulatory asset	$	8,867	$	13,154
Total		$	8,867	$	13,154

11

(D)

Investments in Debt and Equity Securities.    Investment securities we hold are recorded at fair value in the accompanying consolidated balance sheets. We apply regulated operations accounting to the unrealized gains and losses of all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. At March 31, 2019, investments with a fair value of $52,196,000 were in an unrealized loss position for greater than one year and represented approximately 79% of our gross unrealized losses, while investments with a fair value of $77,860,000 were in an unrealized loss position for less than one year. At December 31, 2018, investments with a fair value of $49,975,000 were in an unrealized loss position for greater than one year and represented approximately 59% of our gross unrealized losses, while investments with a fair value of $148,638,000 were in an unrealized loss position for less than one year.

The following tables summarize debt and equity securities as of March 31, 2019 and December 31, 2018.

		Gross Unrealized
		(dollars in thousands)
March 31, 2019		Cost		Gains		Losses			Fair Value
Equity	$	253,840	$	103,643	$	(6,518	)	$	350,965
Debt		282,170		4,155		(1,715	)		284,610
Other		4,654		—		—			4,654
Total	$	540,664	$	107,798	$	(8,233	)	$	640,229

		Gross Unrealized
		(dollars in thousands)
December 31, 2018		Cost		Gains		Losses			Fair Value
Equity	$	251,226	$	64,954	$	(9,105	)	$	307,075
Debt		278,030		1,718		(4,955	)		274,793
Other		3,075		—		—			3,075
Total	$	532,331	$	66,672	$	(14,060	)	$	584,943

(E)

Recently Issued or Adopted Accounting Pronouncements.    In February 2016, the FASB issued "Leases (Topic 842)." The new leases standard requires a dual approach for lessee accounting under which a lessee will account for leases as finance leases or operating leases. Both finance leases and operating leases will result in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee will recognize interest expense and amortization of the ROU asset and for operating leases the lessee will 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. We adopted the new standard effective January 1, 2019. For additional information, see Note G.

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

12

In August 2018, the FASB issued "Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement." This standard eliminates, adds and modifies certain disclosure requirements for fair value measurements as part of the FASB's disclosure framework project. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels and the valuation processes for Level 3 fair value measurements. However, public business entities will be required to disclose the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. An entity is permitted to early adopt any removed or modified disclosures upon issuance of this update and delay adoption of the additional disclosures until their effective date.

As the standard relates only to disclosures, we do not expect the adoption of this standard to have a material impact on our consolidated financial statements. We are currently evaluating the standard and whether we will early adopt the standard.

(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 to December 31, 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 under its wholesale power contract to pay us for capacity and energy we furnish under the 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 obligate each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices mutually agreed upon. Margins produced from non-member sales are included in our rate schedule formula and 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

13

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 fixed operation and maintenance expenses, administrative and general expenses, depreciation and interest. Year to year, capacity revenue fluctuations are generally due to the recovery of fixed operation and maintenance costs. 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 accordance with the associated revenue deferral plan. For information regarding regulatory accounting, see Note J.


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. For additional information regarding our member prepayment program, see Note K.


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 2019, our board has approved a targeted 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 and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. Based on our assessment, we did not recognize a refund liability at March 31, 2019 or March 31, 2018 as there was not an expected refund at the end of the respective years. Based on our current agreements with non-members, we do not refund any consideration received from non-members.

14

Sales to members for the three months ended March 31, 2019 and 2018 were as follows:

	Three Months Ended March 31,
		(dollars in thousands)
		2019		2018
Capacity revenues	$	245,986	$	240,481
Energy revenues		110,484		132,920
Total	$	356,470	$	373,401

Sales to non-members during the three months ended March 31, 2019 and 2018 were insignificant.


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.


We have a rate management program that allows us to expense and recover interest costs on a current basis that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual basis. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under this program, amounts billed to participating members during the three months ended March 31, 2019 were $5,563,000. Participating members were billed $12,229,000 under this program in 2018. The cumulative amount billed since inception of the program totaled $71,879,000.


In 2018, we began an additional rate management program that allows us to recover future expense on a current basis. Our members made a one-time election to participate in this program which, in general, allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. Under this program, amounts billed to participating members during the three months ended March 31, 2019 were $11,690,000. Participating members were billed $15,435,000 under this program in 2018. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income. Amounts deferred under the program will be amortized to income when applied to members' bills.

(G)

Leases.    As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have a small number of various leases of nominal value.

On January 1, 2019, we adopted the new leases standard using the optional transition method to apply the new lease guidance as of January 1, 2019, rather than as of the earliest period presented. In addition, we elected the package of practical expedients permitted under the transition guidance within the new leases standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements. Adoption of the new leases standard resulted in recognition of right-of-use assets and offsetting lease liabilities totaling approximately $6,983,000. The adoption of this standard did not materially impact our consolidated financial statements.


We classify our Scherer Unit No. 2 leases as finance leases and our railcar leases as operating leases. We have made an accounting policy election not to recognize right-of-use assets and lease

15

liabilities that arise from short-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the lease term. Lease expense recognized for our short-term leases during the three months ended March 31, 2019 and March 31, 2018 was insignificant.


Three of our finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the lease, we can elect to:


•

Renew the leases for a period of not less than one year and not more than five years at fair market value,

•

Purchase the undivided interest at fair market value, or

•

Redeliver the undivided interest to the lessors

For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Finance lease amortization is recorded in depreciation and amortization expense.


At the end of our railcar operating leases, we can renew at terms mutually agreeable by us and the lessors, purchase the assets or return the assets to the lessors.


The exercise of lease renewal options is at our sole discretion.


As most of our leases do not provide an implicit rate, we used our incremental borrowing rate based on the information available on January 1, 2019, the date of adoption of the new leases standard, in determining the present value of lease payments.


For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components.

	Classification		March 31, 2019		December 31, 2018
			(dollars in thousands)
Right-of-Use Assets
Finance	Right-of-use assets—finance leases(1)	$	49,181	$	50,499
Operating	Electric plant in service		5,714		—
Total leased assets		$	54,895	$	50,499
Liabilities
Current:
Finance	Long term debt and finance leases due within one year	$	5,462	$	5,462
Operating	Other current liabilities		3,533		—
Noncurrent:
Finance	Obligation under finance leases		81,730		81,730
Operating	Capitalization—Other		2,751		—
Total lease liabilities		$	93,476	$	87,192

⁽¹⁾

Finance lease right-of-use assets are recorded net of accumulated depreciation of $253,551,000 and $252,233,000 as of March 31, 2019 and December 31, 2018, respectively.

16

			Three months ended
Lease Cost	Classification		March 31, 2019		March 31, 2018
			(dollars in thousands)
Finance lease cost:
Amortization of leased assets	Depreciation and amortization	$	1,189	$	1,050
Interest on lease liabilities	Interest expense		2,372		2,511
Operating lease cost	Inventory(1) & production expense		883		1,230
Total leased cost		$	4,444	$	4,791

⁽¹⁾

The majority of our operating lease costs relates to our railcar leases and such costs are added to the cost of our fossil inventories and are recognized in fuel expense as the inventories are consumed.

	March 31, 2019		December 31, 2018
Lease Term and Discount Rate:
Weighted-average remaining lease term (in years)
Finance leases	9.57		9.82
Operating leases	4.89		N/A
Weighted-average discount rate
Finance leases	11.05	%	11.05	%
Operating leases	5.06	%	N/A

		Three months ended
		March 31, 2019		March 31, 2018
		(dollars in thousands)
Other Information:
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	772	$	—
Right-of-use assets obtained in exchange for new operating lease liabilities	$	6,983	$	—

Maturity analysis of our finance and operating lease liabilities as of March 31, 2019 is as follows:

		(in thousands)
Year Ending December 31,		Finance Leases			Operating Leases			Total
2019	$	14,949		$	2,958		$	17,907
2020		14,949			1,413			16,362
2021		14,949			798			15,747
2022		14,949			608			15,557
2023		14,949			386			15,335
Thereafter		70,483			1,156			71,639
Total lease payments		145,228			7,319			152,547
Less: imputed interest		(58,036	)		(1,035	)		(59,071	)
Present value of lease liabilities	$	87,192		$	6,284		$	93,476

17

As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases.

Lease income recognized during the three months ended March 31, 2019 and March 31, 2018 was as follows:

	Three months ended March 31,
		2019		2018
		(dollars in thousands)
Lease income	$	1,518	$	1,473

(H)

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.

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

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 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.

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.

(I)

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

18

currently earn interest at a rate of 5% per annum. Beginning October 1, 2020, deposits will earn interest at 4% per annum and beginning October 1, 2021, the rates will be set at the 1-year floating treasury rate. The program no longer allows additional funds to be deposited into the account. At March 31, 2019 and December 31, 2018, we had restricted investments totaling $661,211,000 and $653,158,000, respectively, of which $511,211,000 and $503,158,000, 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.

(J)

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

The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of March 31, 2019 and December 31, 2018.

		2019		2018
		(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	44,737	$	46,315
Amortization of financing leases(b)		35,047		34,918
Outage costs(c)		48,430		36,352
Asset retirement obligations—Ashpond and other(k)		265,062		137,835
Asset retirement obligations—Nuclear(k)		0		7,031
Depreciation expense(d)		40,888		41,244
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(e)		52,020		51,549
Interest rate options cost(f)		118,193		116,960
Deferral of effects on net margin—Smith Energy Facility(g)		159,023		160,509
Other regulatory assets(m)		16,677		22,350
Total Regulatory Assets	$	780,077	$	655,063
Regulatory Liabilities:
Accumulated retirement costs for other obligations(h)	$	14,344	$	13,873
Deferral of effects on net margin—Hawk Road Energy Facility(g)		18,947		19,101
Major maintenance reserve(i)		40,377		45,547
Amortization of financing leases(b)		16,431		17,156
Deferred debt service adder(j)		107,527		105,192
Asset retirement obligations—Nuclear(k)		32,448		0
Revenue deferral plan(l)		27,596		15,670
Other regulatory liabilities(m)		2,382		2,459
Total Regulatory Liabilities	$	260,052	$	218,998
Net Regulatory Assets	$	520,025	$	436,065

^(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 25 years.

^(b)

Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to finance 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

19

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 consist of training related costs, including interest and 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 used to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No. 3 and No. 4. Amortization will commence in February 2020 and continue 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 the difference in the timing of recognition of decommissioning costs for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for decommissioning.

^(l)

Deferred revenues under a rate management program that allows for additional collections over a five-year period beginning in 2018. These amounts will be amortized to income and applied to member billings over the subsequent five-year period.

^(m)

The amortization periods for other regulatory assets range up to 31 years and the amortization periods of other regulatory liabilities range up to 8 years.

(K)

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 2024, with the majority of the balance scheduled to be credited by the end of 2019.

(L)

Debt.

a)

Department of Energy Loan Guarantee:

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under a Note Purchase Agreement, dated as of February 20, 2014 (the Original 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 in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Documents). Following the bankruptcy of Westinghouse in 2017 (as described in Note M), we and the Department of Energy amended the loan guarantee agreement to restrict further advances pending the satisfaction of certain conditions, including an amendment to the loan guarantee agreement.

In September 2017, the Department of Energy issued a conditional commitment to us to guarantee an additional $1,619,679,706 of funding from the Federal Financing Bank. On March 7, 2019, we

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entered into an amendment and waiver of the loan guarantee agreement under which we received an advance of $585,000,000. On March 22, 2019, we and the Department of Energy entered into an Amended and Restated Loan Guarantee Agreement (as amended, the Loan Guarantee Agreement) which increased the aggregate amount guaranteed by the Department of Energy to $4,676,749,167 and permits us to draw the remaining amount under the Original FFB Notes. We also entered into a Note Purchase Agreement dated as of March 22, 2019 (the Additional Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and a future advance promissory note, dated March 22, 2019, made by us to the Federal Financing Bank in the amount of $1,619,679,706 (the Additional FFB Note and together with the Additional Note Purchase Agreement, the Additional FFB Documents).

Together, the Original FFB Documents and Additional FFB 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 made 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 (Eligible Project Costs). Borrowings under the Original FFB Notes may not exceed $3,057,069,461, of which $335,471,604 is designated for capitalized interest. Borrowings under the Additional FFB Note may not exceed (i) $1,619,679,706 or (ii) an amount that, when aggregated with borrowings under the Original FFB Notes, equals 70% of Eligible Project Costs less the $1,104,000,000 guarantee payment we received from Toshiba Corporation in December 2017. Total borrowings under the Facility will not exceed $4,676,749,167.

At March 31, 2019, aggregate Department of Energy-guaranteed borrowings, including capitalized interest totaled $2,395,433,000. We have no amounts outstanding under the Additional FFB Note.

Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event it is required to make any payments to the Federal Financing Bank under its 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 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 on all advances under the FFB Notes will begin on February 20, 2020. Interest rates on borrowings 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%.

Advances under the Original FFB Notes may be requested on a quarterly basis through December 31, 2020. Advances under the Additional FFB Note may be requested on a quarterly basis through November 30, 2023, one year beyond the current anticipated commercial operation date of Vogtle Unit No. 4.

Future advances under the Facility are subject to satisfaction of customary conditions, as well as (i) certification of compliance with the requirements of the Title XVII loan guarantee program, (ii) accuracy of project-related representations and warranties, (iii) delivery of updated project-related information, (iv) no Project Adverse Event (as described in Note M) having occurred or, if a Project Adverse Event has occurred, that Co-owners (as described in Note M) representing at least 90% of the ownership interests have voted to continue construction, have not deferred construction and we have provided the Department of Energy with certain additional information, (v) certification regarding Georgia Power's compliance with certain obligations relating to the Cargo Preference Act, as amended, (vi) evidence of compliance with the applicable wage requirements of the Davis-Bacon Act, as amended, (vii) certification from the Department of

21

Energy's consulting engineer that proceeds of the advance are used to reimburse Eligible Project Costs and (viii) if either the Services Agreement or the Bechtel Agreement (each, as described in Note M) are terminated, or rejected in bankruptcy proceedings, the Department of Energy has approved the replacement agreement.

We may voluntarily prepay outstanding borrowings under the Facility. Under the FFB Documents, any prepayment will be subject to a make-whole premium or discount, as applicable. Any amounts prepaid may not be re-borrowed.

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.

If certain events occur, referred to as an "Alternate Amortization Event," at the Department of Energy's option the Federal Financing Bank's commitment to make further advances under the Facility will terminate and we will be required to repay the outstanding principal amount of all borrowings under the Facility over a period of five years, with level principal amortization. These events include (i) abandonment of the Vogtle Units No. 3 and No. 4 project, including a decision by Georgia Power to cancel the project, (ii) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (iii) termination of the Services Agreement or rejection of the Services Agreement in bankruptcy, if Georgia Power does not maintain access to certain related intellectual property rights, (iv) termination of the Services Agreement by Westinghouse or termination of the Bechtel Agreement by Bechtel Power Corporation, (v) delivery of certain notices by the Co-owners to the Department of Energy of their intent to cancel construction of Vogtle Units No. 3 and No. 4 coupled with termination by the Co-owners of the Services Agreement or the Bechtel Agreement, (vi) failure of the Co-owners to enter into a replacement contract with respect to the Services Agreement or the Bechtel Agreement following the Co-owners' termination of such agreement with the intent to replace it, (vii) the Department of Energy's takeover of construction of Vogtle Units No. 3 and No. 4 under certain conditions, (viii) the occurrence of any Project Adverse Event that results in a cancellation of the Vogtle Units No. 3 and No. 4 project or the cessation or deferral of construction beyond the periods permitted under the Loan Guarantee Amendment, (ix) loss of or failure to receive necessary regulatory approvals under certain circumstances, (x) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (xi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (xii) change of control of Oglethorpe and (xiii) 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.

b)

Rural Utilities Service Guaranteed Loans:

For the three-month period ended March 31, 2019, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $47,940,000 for long-term financing of general and environmental improvements at existing plants.

In April 2019, we received an additional $25,046,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants.

(M)

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

22

agreements, governs our participation in two additional nuclear units under construction 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. As of March 31, 2019, our total investment in the additional Vogtle units was approximately $4,113,511,000.

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 price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. 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 technical support and staff augmentation on a time and materials cost basis. The Services Agreement provides that it 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, pursuant to which Bechtel serves 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.

In April 2019, Georgia Power and Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the total estimated project capital cost forecast for Vogtle Units No. 3 and No. 4. Accordingly, we did not change our $7.5 billion project budget, which includes capital costs, allowance for funds used during construction, our allocation of the project-level contingency and a separate Oglethorpe-level contingency. There was also no change to the in-service dates of November 2021 for Unit No. 3 and November 2022 for Unit No. 4 previously approved by the Georgia Public Service Commission following the validation process. The schedule being utilized to manage construction at the Vogtle site was adjusted following the validation process and will continue to target in-service dates in

23

advance of November 2021 and November 2022 in order to maintain margin to the approved in-service dates.

As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor and/or related cost escalation; procurement, fabrication, delivery, assembly and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures or components, any of which may require additional labor and/or materials; or other issues could arise and further impact the projected schedule and estimated cost. Monthly construction production targets established as part of a strategy to maintain margin to the approved in-service dates will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be retained and deployed.

The Co-owners' joint ownership agreements, as amended, provide that 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, the Bechtel Agreement or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Vogtle Units No. 3 and No. 4 (or associated financing costs) or the Georgia Public Service Commission 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, excluding any additional amounts paid by Georgia Power on behalf of the other Co-owners pursuant to the Joint Ownership Agreement provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Public Service Commission for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates or (iv) an incremental extension of one year or more over the most recently approved schedule (each, a Project Adverse Event).

The ultimate outcome of these matters cannot be determined at this time. See Note 8 in Item 8 Notes to Audited Consolidated Financial Statements in our 2018 Form 10-K for additional information about Vogtle Units No. 3 and No. 4.

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 Three Months Ended March 31, 2019 and 2018

Net Margin

Our net margins for the three-month period ended March 31, 2019 were $23.6 million compared to $27.4 million for the same period of 2018. Through March 31, 2019, we collected approximately 43% of our targeted net margin of $54.7 million for the year ending December 31, 2019. These collections are typical as our capacity revenues are generally recorded evenly throughout the year. We anticipate our

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board of directors will approve a budget adjustment by year end so that margins will achieve, but not exceed, the 2019 targeted margins for interest ratio of 1.14. As a result, and pursuant to Revenue from Contracts with Customers (Topic 606), we assess our projected margin and annual revenue requirement to meet the targeted margins for interest ratio to determine if a refund liability should be recognized. As a result of this assessment, we did not recognize a refund liability as of March 31, 2019 or March 31, 2018. 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 2018 Form 10-K.

Operating Revenues

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

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

The components of member revenues for the three-month periods ended March 31, 2019 and 2018 were as follows:

		Three Months Ended March 31,					2019 vs. 2018 % Change
		(dollars in thousands)
		2019			2018
Capacity revenues	$	245,986		$	240,481		2.3	%
Energy revenues		110,484			132,920		(16.9	%)
Total	$	356,470		$	373,401		(4.5	%)
MWh Sales to members		4,698,135			5,100,326		(7.9	%)
Cents/kWh		7.59			7.32		3.6	%
Member energy requirements supplied		52	%		54	%	(3.7	%)

Energy revenues from members decreased for the three-month period ended March 31, 2019 compared to the same period in 2018 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.

		Cost				Generation			Cents per kWh
		(dollars in thousands)				(MWh)
		Three Months Ended March 31,			2019 vs.	Three Months Ended March 31,		2019 vs.	Three Months Ended March 31,		2019 vs.
Fuel Source		2019		2018	2018 % Change	2019	2018	2018 % Change	2019	2018	2018 % Change
Coal	$	21,057	$	18,201	15.7%	664,070	590,052	12.5%	3.17	3.08	2.8%
Nuclear		17,146		20,823	(17.7%)	2,148,033	2,484,443	(13.5%)	0.80	0.84	(4.8%)
Gas:
Combined Cycle		59,031		72,317	(18.4%)	2,000,294	2,121,146	(5.7%)	2.95	3.41	(13.4%)
Combustion Turbine		1,758		9,106	(80.7%)	36,472	55,786	(34.6%)	4.82	16.32	(70.5%)
	$	98,992	$	120,447	(17.8%)	4,848,869	5,251,427	(7.7%)	2.04	2.29	(11.0%)

Total fuel costs decreased for the three-month period ended March 31, 2019 compared to the same period in 2018 as a result of lower natural gas prices, lower generation and less usage of oil as a fuel source at combustion turbine facilities. During the first quarter of 2018, colder than normal weather resulted in higher natural gas prices and generation from relatively less economical units. Total generation for the first quarter of 2019 decreased compared to the same period in 2018 due to milder weather and scheduled plant outages.

Financial Condition

Balance Sheet Analysis as of March 31, 2019

Assets

Cash and cash equivalents decreased $411.2 million, primarily due to $350 million of first mortgage bonds which matured and were paid during the period.

Cash used for property additions for the three-month period ended March 31, 2019 totaled $321.1 million. Of this amount, $251.5 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4 and $27.1 million was for nuclear fuel purchases. The remainder was for expenditures related to normal additions and replacements to our existing generation facilities.

The $41.2 million increase in the decommissioning fund was primarily due to an increase in unrealized investment gains.

Regulatory assets increased $125.0 million primarily as a result of the deferral of costs associated with asset retirement obligations for coal combustion residuals.

Equity and Liabilities

Long-term debt increased $152.1 million as a result of $585 million advanced under the Department of Energy-guaranteed loan on March 15, 2019, which was utilized to repay a like amount of outstanding commercial paper. At December 31, 2018, the outstanding commercial paper balance of $436.6 million was classified as long-term debt.

Long-term debt and finance and operating leases due within one year decreased $297.4 million primarily due to $350 million of first mortgage bonds which matured in March 2019 and were paid when due.

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Short-term borrowings, which primarily provide interim financing for Vogtle Units No. 3 and No. 4 construction costs, increased $98.2 million during the three-month period ended March 31, 2019. At December 31, 2018, all short-term borrowings were classified as long-term debt.

Accounts payable decreased $63.0 million during the three-month period ended March 31, 2019. The decrease was largely due to the application of $30.9 million in credits to our members' bills in the first quarter of 2019, for a board-approved reduction in 2018 revenue requirements as a result of margins in excess of our 2018 target. In addition, property tax payments resulted in a $26.0 million decrease in the related payables.

Capital Requirements and Liquidity and Sources of Capital

Vogtle Units No. 3 and No. 4

We, Georgia Power Company, the Municipal Electric Authority of Georgia (MEAG), 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 under construction 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. As of March 31, 2019, our total investment in the additional Vogtle units was approximately $4.1 billion.

In April 2019, Georgia Power and Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the total estimated project capital cost forecast for Vogtle Units No. 3 and No. 4. Accordingly, we did not change our $7.5 billion project budget, which includes capital costs, allowance for funds used during construction, our allocation of the project-level contingency and a separate Oglethorpe-level contingency. There was also no change to the in-service dates of November 2021 for Unit No. 3 and November 2022 for Unit No. 4 previously approved by the Georgia Public Service Commission following the validation process. The schedule being utilized to manage construction at the Vogtle site was adjusted following the validation process and will continue to target in-service dates in advance of November 2021 and November 2022 in order to maintain margin to the approved in-service dates.

As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor and/or related cost escalation; procurement, fabrication, delivery, assembly and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures or components, any of which may require additional labor and/or materials; or other issues could arise and further impact the projected schedule and estimated cost. Monthly construction production targets established as part of a strategy to maintain margin to the approved in-service dates will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be retained and deployed.

The ultimate outcome of these matters cannot be determined at this time.

For additional information regarding Vogtle Units No. 3 and No. 4, see "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4" in our 2018 Form 10-K. For information regarding our financing of the additional Vogtle units, see "Financing

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Activities—Department of Energy-Guaranteed Loans" and Note L to Notes to Unaudited Consolidated Financial Statements. See "Item 1A—RISK FACTORS" in our 2018 Form 10-K for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.

Environmental Regulations

Federal and state laws and regulations regarding environmental matters affect operations at our facilities. 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 2018 Form 10-K.

Liquidity

At March 31, 2019, we had $1.6 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $341 million in cash and cash equivalents and $1.3 billion of unused and available committed credit arrangements.

At March 31, 2019, we had $1.6 billion of committed credit arrangements in place and $1.3 billion available under these facilities, the details of which are reflected in the table below:

Committed Credit Facilities
		Authorized Amount		Available March 31, 2019		Expiration Date
		(dollars in millions)
Unsecured Facilities:
Syndicated Line of Credit led by CFC	$	1,210	$	976	(1)	March 2020
CFC Line of Credit(2)		110		110		December 2023
JPMorgan Chase Line of Credit		150		34	(3)	October 2021
Secured Facilities:
CFC Term Loan(2)		140		140	(2)	December 2023

⁽¹⁾

Of the portion of this facility that was unavailable at March 31, 2019, $98 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, 2019, $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.

We have the flexibility to use the $1.2 billion syndicated line of credit for several purposes, including borrowing for general corporate purposes, to support up to $1.0 billion of commercial paper and to issue letters of credit to third parties. We generally issue commercial paper to provide interim financing of our expenses related to the construction of Vogtle Units No. 3 and No. 4 which we repay with the proceeds from long-term funding sources. Beginning in March 2019, we are again utilizing our loan guaranteed by the Department of Energy as our preferred source of long-term financing of eligible costs for Vogtle Units No. 3 and No. 4. See Note L of Notes to Unaudited Consolidated Financial Statements for additional information regarding the Department of Energy-guaranteed loan.

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

Under our unsecured committed lines of credit, we have the ability to issue letters of credit totaling $760 million in the aggregate, of which $509 million remained available at March 31, 2019. 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.

Three of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At March 31, 2019, the required minimum level was $750 million and our actual patronage capital was $986 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, 2019, we had $9.2 billion of secured indebtedness and $98.2 million of unsecured indebtedness outstanding.

At March 31, 2019, we had $661.2 million on deposit in the Rural Utilities Service Cushion of Credit Account, all of which is classified as a restricted investment. See Note I of Notes to Unaudited Consolidated Financial Statements for additional information regarding this account.

Financing Activities

First Mortgage Indenture.    At March 31, 2019, we had $9.2 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 2018 Form 10-K for further discussion of our first mortgage indenture.

Rural Utilities Service-Guaranteed Loans.    At March 31, 2019, we had one approved Rural Utilities Service-guaranteed loan being funded through the Federal Financing Bank totaling $448 million that has $88 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As of March 31, 2019, we had $2.6 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.

Department of Energy-Guaranteed Loans.    In 2014, we entered into a loan guarantee agreement with the Department of Energy to 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.

On March 15, 2019, we received an advance of $585 million. In conjunction with this advance, we repaid a like amount of outstanding commercial paper. On March 22, 2019, we and the Department of Energy executed an amended and restated loan guarantee agreement which increased the aggregate amount of the loan to $4.7 billion and permits us to draw the approximately $670 million remaining under the original $3.1 billion loan. At March 31, 2019, aggregate Department of Energy-guaranteed borrowings under the original loan totaled $2.4 billion, including capitalized interest. We have no amounts outstanding under the additional loan. We expect to fully draw the principal amount under the original loan by the end of 2019 and to begin drawing down the additional loan funds in 2020.

With the additional loan, Department of Energy guaranteed-loans are expected to fund nearly $4.7 billion of the cost to construct the new Vogtle units. Combined, the $4.7 billion of funding

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guaranteed by the Department of Energy and the $1.9 billion of debt we have raised in the capital markets represent long-term financing for more than 85% of our $7.5 billion project budget. All of the debt advanced under the loan guarantee agreement is secured ratably with all other debt under our first mortgage indenture.

For more information regarding the loan guarantee agreement, see Note L of Notes to Unaudited Consolidated Financial Statements. 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 2018 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" in our 2018 Form 10-K.

Item 4.    Controls and Procedures

As of March 31, 2019, 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, 2019 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 2018 Form 10-K.

Item 1A.    Risk Factors

There have been no material changes from the risk factors disclosed in "Item 1A—RISK FACTORS" in our 2018 Form 10-K.

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

Not Applicable.

Item 3.    Defaults upon Senior Securities

Not Applicable.

Item 4.    Mine Safety Disclosures

Not Applicable.

Item 5.    Other Information

Not Applicable.

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Item 6.    Exhibits

Number		Description
	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 2016-2018).
	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: May 13, 2019	By:	/s/ Michael L. Smith
		Michael L. Smith President and Chief Executive Officer
Date: May 13, 2019		/s/ Elizabeth B. Higgins
		Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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