UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

_______________________________________________________________________________

FORM 10-Q

(Mark One)

☒    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2024

OR

☐    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  ☐   No ☒ 

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  ☒    No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer ☐    Accelerated Filer ☐    Non-Accelerated Filer ☒    Smaller Reporting Company ☐    Emerging Growth Company ☐

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 ☐    No ☒

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, 2024

		Page No.
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Consolidated Balance Sheets as of March 31, 2024 and December 31, 2023	1
	Unaudited Consolidated Statements of Revenues and Expenses For the Three Months ended March 31, 2024 and 2023	3
	Unaudited Consolidated Statements of Patronage Capital and Membership Fees For the Three Months ended March 31, 2024 and 2023	4
	Unaudited Consolidated Statements of Cash Flows For the Three Months ended March 31, 2024 and 2023	5
	Notes to Unaudited Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	27
Item 4.	Controls and Procedures	27
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	28
Item 1A.	Risk Factors	28
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29
Item 3.	Defaults Upon Senior Securities	29
Item 4.	Mine Safety Disclosures	29
Item 5.	Other Information	29
Item 6.	Exhibits	30
SIGNATURES		31

i

CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING INFORMATION

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, 2023, 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, such as the closure of coal ash ponds and any future generation projects we undertake;

•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;

•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;

•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;

•actions by credit rating agencies;

•commercial banking and financial market conditions;

•the impact of load growth in our members’ service territories and any decisions regarding the development of additional generation resources to meet the additional demand;

•our participation in any federal loan or grant programs for which we qualify and are selected and our ability to meet the applicable loan or grant conditions and requirements;

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

•adequate funding of our nuclear and coal ash pond decommissioning funds including investment performance and projected decommissioning costs;

ii

•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;

•the direct or indirect effect on our business resulting from cyber or physical attacks on us, our members or third-party service providers, vendors or contractors;

•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;

•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;

•litigation or legal and administrative proceedings and settlements;

•unanticipated changes in interest rates or rates of inflation;

•early retirement of our co-owned coal units;

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

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

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

•catastrophic events such as fires, earthquakes, floods, droughts, hurricanes, explosions, pandemic health events, or similar occurrences;

•significant changes in critical accounting policies material to us; 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, 2024 and December 31, 2023

	(dollars in thousands)
	2024		2023
Assets
Electric plant:
In service	$	14,202,485	$	14,112,098
Right-of-use assets—finance leases	302,732		302,732
Less: Accumulated provision for depreciation	(5,487,672)		(5,418,738)
Electric plant in service, net	9,017,545		8,996,092
Nuclear fuel, at amortized cost	395,866		389,662
Construction work in progress	3,397,847		3,294,641
Total electric plant	12,811,258		12,680,395
Investments and funds:
Nuclear decommissioning trust fund	679,298		641,239
Investment in associated companies	83,794		82,133
Long-term investments	709,815		690,732
Other	36,088		35,585
Total investments and funds	1,508,995		1,449,689
Current assets:
Cash and cash equivalents	327,470		490,592
Short-term investments	135,341		143,931
Receivables	180,414		201,784
Inventories, at weighted average cost	329,414		337,045
Prepayments and other current assets	48,905		18,335
Total current assets	1,021,544		1,191,687
Deferred charges and other assets:
Regulatory assets	1,136,248		1,131,489
Prepayments to Georgia Power Company	14,871		13,722
Other	55,699		57,869
Total deferred charges	1,206,818		1,203,080
Total assets	$	16,548,615	$	16,524,851

    

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

1

2

Oglethorpe Power Corporation

Consolidated Balance Sheets (Unaudited)

March 31, 2024 and December 31, 2023

	(dollars in thousands)
	2024		2023
Equity and Liabilities
Capitalization:
Patronage capital and membership fees	$	1,300,016	$	1,257,917
Long-term debt	11,474,583		11,600,917
Obligation under finance leases	43,586		43,586
Obligation under Rocky Mountain transactions	30,365		29,862
Other	4,786		5,152
Total capitalization	12,853,336		12,937,434
Current liabilities:
Long-term debt and finance leases due within one year	381,602		384,426
Short-term borrowings	662,779		607,885
Accounts payable	63,328		117,272
Accrued interest	121,073		106,355
Member power bill prepayments, current	25,842		31,406
Other current liabilities	113,493		111,109
Total current liabilities	1,368,117		1,358,453
Deferred credits and other liabilities:
Asset retirement obligations	1,537,803		1,458,937
Member power bill prepayments, non-current	70,033		47,133
Regulatory liabilities	704,084		706,320
Other	15,242		16,574
Total deferred credits and other liabilities	2,327,162		2,228,964
Total equity and liabilities	$	16,548,615	$	16,524,851

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

3

Oglethorpe Power Corporation

Consolidated Statements of Revenues and Expenses (Unaudited)

For the Three Months Ended March 31, 2024 and 2023

	(dollars in thousands)
	Three Months
	2024		2023
Operating revenues:
Sales to members	$	535,370	$	387,653
Sales to non-members	944		1,800
Total operating revenues	536,314		389,453
Operating expenses:
Fuel	167,046		133,168
Production	118,090		93,467
Depreciation and amortization	94,105		72,674
Purchased power	19,220		17,630
Accretion	17,622		15,508
Total operating expenses	416,083		332,447
Operating margin	120,231		57,006
Other income:
Investment income	17,052		16,382
Other	2,804		2,925
Total other income	19,856		19,307
Interest charges:
Interest expense	129,391		123,707
Allowance for debt funds used during construction	(34,107)		(74,430)
Amortization of debt discount and expense	2,704		2,626
Net interest charges	97,988		51,903
Net margin	$	42,099	$	24,410

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

4

Oglethorpe Power Corporation

Consolidated Statements of Patronage Capital and Membership Fees (Unaudited)

For the Three Months Ended March 31, 2024 and 2023

	(dollars in thousands)
Balance at December 31, 2022	$	1,192,127
Net margin	24,410
Balance at March 31, 2023	$	1,216,537
Balance at December 31, 2023	$	1,257,917
Net margin	42,099
Balance at March 31, 2024	$	1,300,016

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

5

Oglethorpe Power Corporation

Consolidated Statements of Cash Flows (Unaudited)

For the Three Months Ended March 31, 2024 and 2023

	(dollars in thousands)
	2024		2023
Cash flows from operating activities:
Net margin	$	42,099	$	24,410
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	131,940		92,645
Accretion cost	17,622		15,508
Amortization of deferred gains	(447)		(447)
Allowance for equity funds used during construction	(347)		(149)
Deferred outage costs	(11,856)		(21,198)
Loss on sale of investments	471		1,289
Regulatory deferral of costs associated with nuclear decommissioning	(8,125)		(8,519)
Other	(14,480)		(1,043)
Change in operating assets and liabilities:
Receivables	26,609		49,887
Inventories	7,683		(17,711)
Prepayments and other current assets	(30,569)		4,027
Accounts payable	(49,628)		(116,354)
Accrued interest	14,718		(13,109)
Accrued taxes	(33,733)		(36,722)
Other current liabilities	24,494		(26,841)
Rate management program billing credits applied	(35,646)		(9,494)
Other	17,336		(989)
Total adjustments	56,042		(89,220)
Net cash provided by (used in) operating activities	98,141		(64,810)
Cash flows from investing activities:
Property additions	(174,270)		(285,233)
Activity in nuclear decommissioning trust fund—Purchases	(140,865)		(2,500)
—Proceeds	136,894		283
Decrease in restricted investments	—		74,031
Activity in long-term and short-term investments—Purchases	(82,283)		(63,505)
—Proceeds	80,672		68,226
Other	(3,512)		8,163
Net cash used in investing activities	(183,364)		(200,535)
Cash flows from financing activities:
Long-term debt proceeds	6,067		15,431
Long-term debt payments	(136,047)		(137,732)
Increase in short-term borrowings, net	54,894		157,375
Other	(2,813)		11,311
Net cash (used in) provided by financing activities	(77,899)		46,385
Net decrease in cash, cash equivalents and restricted cash	(163,122)		(218,960)
Cash, cash equivalents and restricted cash at beginning of period	490,592		625,781
Cash, cash equivalents and restricted cash at end of period	$	327,470	$	406,821
Supplemental cash flow information:
Cash paid for—
Interest (net of amounts capitalized)	$	80,063	$	61,915
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	$	65,149	$	87,509
Accrued property additions at end of period	$	41,104	$	69,557

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

6

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, our financial condition and results of operations for the three-month periods ended March 31, 2024 and 2023. 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) depreciation rates, such as determining the depreciable service lives. 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, 2023, as filed with the SEC. The results of operations for the three-month period ended March 31, 2024 are not necessarily indicative of results to be expected for the full year. As noted in our 2023 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 2023 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 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.

7

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 of comparable utility, adjusted for obsolescence.

The tables below detail assets and liabilities measured at fair value on a recurring basis at March 31, 2024 and December 31, 2023.

	Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	March 31, 2024		(Level 1)		(Level 2)		(Level 3)
	(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	259,404	$	259,404	$	—	$	—
International equity trust	141,293		—		141,293		—
Corporate bonds and debt	64,861		—		64,772		89
US Treasury securities	42,814		42,814		—		—
Mortgage backed securities	56,607		—		56,607		—
Domestic mutual funds	92,626		92,626		—		—
Municipal bonds	303		—		303		—
Federal agency securities	8,231		—		8,231		—
International mutual funds	2,449		—		2,449		—
Non-US Gov't bonds & private placements	3,708		—		3,708		—
Other	7,002		7,002		—		—
Long-term investments:
International equity trust	46,098		—		46,098		—
Corporate bonds and debt	14,949		—		14,949		—
US Treasury securities	14,783		14,783		—		—
Mortgage backed securities	17,068		—		17,068		—
Domestic mutual funds	387,897		387,897		—		—
Treasury STRIPS	226,643		—		226,643		—
Non-US Gov't bonds & private placements	1,775		—		1,775		—
Other	602		602		—		—
Short-term investments: Treasury STRIPS	135,341		—		135,341		—
Natural gas swaps	10,381		—		10,381		—

    

8

	Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	December 31, 2023		(Level 1)		(Level 2)		(Level 3)
	(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	234,979	$	234,979	$	—	$	—
International equity trust	134,911		—		134,911		—
Corporate bonds and debt	67,986		—		67,900		86
US Treasury securities	43,917		43,917		—		—
Mortgage backed securities	58,763		—		58,763		—
Domestic mutual funds	85,481		85,481		—		—
Municipal bonds	303		—		303		—
Federal agency securities	7,256		—		7,256		—
Non-US Gov't bonds & private placements	2,717		—		2,717		—
International mutual funds	2,012		—		2,012		—
Other	2,914		2,914		—		—
Long-term investments:
International equity trust	43,202		—		43,202		—
Corporate bonds and debt	14,151		—		14,151		—
US Treasury securities	17,243		17,243		—		—
Mortgage backed securities	15,024		—		15,024		—
Domestic mutual funds	378,387		378,387		—		—
Treasury STRIPS	220,765		—		220,765		—
Non-US Gov't bonds & private placements	1,568		—		1,568		—
Other	392		392		—		—
Short-term investments: Treasury STRIPS	143,931		—		143,931		—
Natural gas swaps	13,445		—		13,445		—

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

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

The estimated fair values of our long-term debt, including current maturities at March 31, 2024 and December 31, 2023 were as follows:

	2024				2023
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	11,966,572	$	10,233,768	$	12,096,552	$	10,638,749

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

9

Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. 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, 2024 and December 31, 2023 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank.

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

(C)Derivative Instruments.    We use commodity 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. Realized gains and losses on natural gas swaps are included in fuel expense within our consolidated statements of revenues and expenses and, therefore, net margins within our consolidated statement of cash flows.

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

It is possible that volatility in commodity prices could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of March 31, 2024, all of the counterparties with transaction amounts outstanding under our derivative 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 derivative 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, 2024 and December 31, 2023, the estimated fair values of our natural gas contracts were net assets of approximately $10,381,000 and $13,445,000, respectively.

At March 31, 2024 and December 31, 2023, none of our counterparties was required to post credit collateral under our natural gas swap agreements.

10

The following table reflects the notional volume of our natural gas derivatives as of March 31, 2024 that is expected to settle or mature each year:

Year	Natural Gas Swaps (MMBTUs)  (in millions)
2024	29.4
2025	25.2
2026	20.9
2027	10.3
2028	0.5
Total	86.3

The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at March 31, 2024 and December 31, 2023.

	Balance Sheet Location	Fair Value
		2024		2023
		(dollars in thousands)
Assets:
Natural gas swaps	Other deferred charges	$	23,698	$	25,459
Liabilities:
Natural gas swaps	Other current liabilities	$	12,688	$	10,370
Natural gas swaps	Other deferred credits	$	629	$	1,644

The following table presents the gross realized gains and (losses) on derivative instruments recognized in net margins for the three months ended March 31, 2024 and 2023.

	Statement of Revenues and Expenses Location	Three Months Ended March 31,
		2024		2023
		(dollars in thousands)
Natural gas swaps gains	Fuel	$	41	$	135
Natural gas swaps losses	Fuel	(8,452)		(9,397)
Total		$	(8,411)	$	(9,262)

The following table presents the unrealized gains on derivative instruments deferred on the balance sheet at March 31, 2024 and December 31, 2023.

	Balance Sheet Location	2024		2023
		(dollars in thousands)
Natural gas swaps	Regulatory liability	$	10,381	$	13,445
Total		$	10,381	$	13,445

(D)Investment 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.

11

The following tables summarize debt and equity securities as of March 31, 2024 and December 31, 2023.

	Gross Unrealized
	(dollars in thousands)
March 31, 2024	Cost		Gains		Losses		Fair Value
Equity	$	350,947	$	292,940	$	(6,033)	$	637,854
Debt	903,715		2,574		(27,229)		879,060
Other	7,549		1		(10)		7,540
Total	$	1,262,211	$	295,515	$	(33,272)	$	1,524,454

	Gross Unrealized
	(dollars in thousands)
December 31, 2023	Cost		Gains		Losses		Fair Value
Equity	$	344,669	$	246,795	$	(5,549)	$	585,915
Debt	908,316		3,938		(25,181)		887,073
Other	2,889		61		(36)		2,914
Total	$	1,255,874	$	250,794	$	(30,766)	$	1,475,902

The cost basis of our debt securities that were in unrealized loss positions at March 31, 2024 was $832,901,000. At March 31, 2024, $3,322,000 of the $27,229,000 of unrealized losses relates to securities that have been in unrealized loss positions for less than twelve months and $23,907,000 relates to securities that have been in unrealized loss positions for greater than twelve months. These unrealized losses are primarily attributable to increases in market interest rates.

The cost basis of our debt securities that were in unrealized loss positions at December 31, 2023 was $788,798,000. At December 31, 2023, $3,362,000 of the $25,181,000 of unrealized losses relates to securities that have been in unrealized loss positions for less than twelve months and $21,819,000 relates to securities that have been in unrealized loss positions for greater than twelve months. These unrealized losses are primarily attributable to increases in market interest rates.

(E)Recently Issued or Adopted Accounting Pronouncements.   In November 2023, the Financial Accounting Standards Board (FASB) issued “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” The amendments in this update are intended to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant expenses. The amendments in this update require disclosures to include significant segment expenses that are regularly provided to the chief operating decision maker (CODM), a description of other segment items by reportable segment, and any additional measures of a segment's profit or loss used by the CODM when deciding how to allocate resources. The amendments in this update are also applicable to entities with only one reportable segment. The amendments in this update also require all annual disclosures currently required by Topic 280 to be included in interim periods. The new standard is effective for us for annual reporting periods beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted and requires retrospective application to all prior periods presented in the financial statements. We are currently evaluating the future impact of this standard on our consolidated financial statements.

In December 2023, the FASB amended "Income Taxes (Topic 740): Improvements to Income Tax Disclosures”. The amendments in this update requires additional disclosures related to the rate reconciliation, income taxes paid and other amendments intended to improve effectiveness and comparability. The amendments in this update are effective for us for annual periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis. Retrospective application is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements, however, we do not anticipate the impact will be significant.

(F)Revenue Recognition.    As an electric membership cooperative, our principal 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 that extend to December 31, 2085. These contracts 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

12

coverage requirements. We also sell energy and capacity to non-members through industry standard contracts and negotiated agreements, respectively. We do not have multiple operating segments.

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

Each of our members is obligated to pay us for capacity and energy we furnish under 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. 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. As of March 31, 2024 and December 31, 2023, we did not have any significant long-term contracts with non-members.

The consideration we receive for providing capacity services is determined by our formulary rate on an annual basis. The components of the formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and income from other sources. Capacity revenues, therefore, vary to the extent these components vary. Fixed costs include items such as 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 expenses. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in accordance with the associated revenue deferral plan as the expenses are recognized. 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 generally 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 are billed and recognized in accordance with the terms of the associated 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 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. 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 2024, 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 whether a refund to our members of excess consideration is likely. If so, we reduce our capacity

13

revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our unaudited consolidated balance sheets. As of March 31, 2024, we did not recognize a refund liability. As of December 31, 2023, we recognized refund liabilities totaling $34,266,000. Based on our current agreements with non-members, we do not refund any consideration received from non-members.

Sales to members for the three months ended March 31, 2024 and 2023 were as follows:

	Three Months Ended March 31,
	(dollars in thousands)
	2024		2023
Capacity revenues	$	355,718	$	242,043
Energy revenues	179,652		145,610
Total	$	535,370	$	387,653

Receivables from contracts with our members at March 31, 2024 and December 31, 2023 were $147,851,000 and $170,901,000, respectively.

Sales to non-members during the three months ended March 31, 2024 and 2023 were as follows:

	Three Months Ended March 31,
	(dollars in thousands)
	2024		2023
Energy revenues	$	158	$	1,037
Capacity revenues	786		763
Total	$	944	$	1,800

Energy revenues from non-members for the three months ended March 31, 2024 and March 31, 2023 were primarily from the sale of the BC Smith deferring members' output into the wholesale market. For the three months ended March 31, 2024 and March 31, 2023, we also recognized capacity revenues from non-members related to the two units we acquired at the Washington County Power Plant in December 2022.

The remainder of our receivables is primarily related to transactions with Georgia Power, affiliated companies and investment income. Our receivables from non-members at March 31, 2024 and December 31, 2023 were $32,563,000 and $30,883,000, respectively.

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 and have not had a history of any write-offs from 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 ended December 2023, which allowed us to expense and recover interest costs associated with the construction of Vogtle Units No. 3 and No. 4, on a current basis, that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 elected to participate in this program on an annual basis. Under this program, the amount billed to participating members during the three months ended March 31, 2023 was $1,761,000. The cumulative amount billed since inception of the program totaled $135,693,000.

In 2018, we began an additional rate management program that allowed us to recover future expense on a current basis from our members. In general, the program allowed 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. During the first quarter of 2022, we began applying billing credits to some of our participating members within this program. In December 2022, collections from our members ended for this rate management program. Under this program, net billing credits to participating members during the three months ended March 31, 2024 and 2023 were $30,409,000 and $15,713,000, respectively. Funds collected through this program are invested and held until applied to

14

members' bills. Investments that mature and are expected to be applied to members' bills within the next twelve months are included in the Short-term investments line item within our unaudited consolidated balance sheets. In conjunction with this program, we applied regulated operations accounting to defer these revenues and related investment income on the funds collected. Amounts deferred under the program are amortized to income when applied to members' bills. The net cumulative amount billed, since inception of the program totaled $369,102,000. As of March 31, 2024, $279,467,000 is our remaining liability to be credited to our members' bills. For additional information regarding our revenue deferral plan, see Note J.

(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 various other leases of minimal value.

We classify our four 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 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, 2024 and 2023 was insignificant.

Finance Leases

Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion 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.

Operating Leases

Our railcar operating leases have terms that extend through November 30, 2028. At the end of the 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. We have additional operating leases including one for office equipment that has a term extending through October 31, 2028 and one for real property at one of our electric generating facilities that has a term extending through February 2042 with one renewal option for a 20 year term.

The exercise of renewal options for our finance and operating leases is at our sole discretion.

As all of our operating leases do not provide an implicit rate, we use an incremental borrowing rate based on the information available at the time new lease agreements are entered into or reassessed to determine the present value of lease payments.

We combine lease and nonlease components for all lease agreements.

Classification	March 31, 2024		December 31, 2023
	(dollars in thousands)
Right-of-use assets—Finance leases
Right-of-use assets	$	302,732	$	302,732
Less: Accumulated provision for depreciation	(279,465)		(278,586)
Total finance lease assets	$	23,267	$	24,146
Lease liabilities—Finance leases
Obligations under finance leases	$	43,586	$	43,586
Long-term debt and finance leases due within one year	9,351		9,351
Total finance lease liabilities	$	52,937	$	52,937

15

Classification	March 31, 2024		December 31, 2023
	(dollars in thousands)
Right-of-use assets—Operating leases
Electric plant in service, net	$	6,181	$	6,587
Total operating lease assets	$	6,181	$	6,587
Lease liabilities—Operating leases
Capitalization—Other	$	4,786	$	5,152
Other current liabilities	1,395		1,529
Total operating lease liabilities	$	6,181	$	6,681

		Three months ended
Lease Cost	Classification	March 31, 2024		March 31, 2023
		(dollars in thousands)
Finance lease cost:
Amortization of leased assets	Depreciation and amortization	$	2,338	$	2,099
Interest on lease liabilities	Interest expense	1,400		1,638
Operating lease cost:	Inventory(1) & production expense	538		329
Total leased cost		$	4,276	$	4,066

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

	March 31, 2024		December 31, 2023
Lease Term and Discount Rate:
Weighted-average remaining lease term (in years)
Finance leases	5.01		5.26
Operating leases	5.70		5.77
Weighted-average discount rate:
Finance leases	11.05	%	11.05	%
Operating leases	6.45	%	6.37	%

	Three months ended March 31,
	2024		2023
	(dollars in thousands)
Other Information:
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	632	$	409
Right-of-use assets obtained in exchange for new operating lease liabilities	$	17	$	—

16

Maturity analysis of our finance and operating lease liabilities as of March 31, 2024 is as follows:

	(dollars in thousands)
Year Ending December 31,	Finance Leases		Operating Leases		Total
2024	$	14,949	$	1,334	$	16,283
2025	14,949		1,708		16,657
2026	14,949		1,416		16,365
2027	14,949		1,139		16,088
2028	3,052		1,029		4,081
Thereafter	7,633		723		8,356
Total lease payments	$	70,481	$	7,349	$	77,830
Less: imputed interest	(17,544)		(1,168)		(18,712)
Present value of lease liabilities	$	52,937	$	6,181	$	59,118

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, 2024 and 2023 was as follows:

	Three Months Ended March 31,
	2024		2023
	(dollars in thousands)
Lease income	$	1,387	$	1,685

(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 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.

In July 2020, a group of individual plaintiffs filed a complaint, which was amended in December 2022, in the Superior Court of Fulton County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer, of which we are a co-owner, has impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a

17

medical monitoring fund, and injunctive relief. In December 2022, the Superior Court of Fulton County granted Georgia Power’s motion to transfer the case to the Superior Court of Monroe County. In May 2023, the Superior Court of Monroe County denied Georgia Power’s motion to dismiss the case for lack of subject matter jurisdiction. In July 2023, the Superior Court of Monroe County denied the remaining motions to dismiss certain claims and plaintiffs that Georgia Power filed at the outset of the case. On March 11, 2024, Georgia Power filed a motion to dismiss certain claims. On March 14, 2024, Georgia Power filed motions for summary judgment. The Superior Court of Monroe County has set a trial date of August 12, 2024 for the first of the approximately 44 plaintiffs.

Eight additional complaints, three on October 8, 2021, four on February 7, 2022, and one on January 9, 2023, were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs sought an unspecified amount of monetary damages including punitive damages. After Georgia Power removed each of these cases to the U.S. District Court for the Middle District of Georgia, the plaintiffs voluntarily dismissed their complaints without prejudice in November 2022 and February 2023. On May 12, 2023, the plaintiffs refiled their eight complaints in the Superior Court of Monroe County. Also on May 12, 2023, a new complaint was filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries. The plaintiff seeks an unspecified amount of monetary damages, including punitive damages. On May 18, 2023, Georgia Power removed all of these cases to the U.S. District Court for the Middle District of Georgia. The plaintiffs are requesting the court remand the cases back to the Superior Court of Monroe County.

The amount of any possible losses from these matters cannot be estimated at this time.

In May 2022, Florida Power & Light Company and JEA filed a complaint in the U.S. District Court for the Northern District of Georgia against us and the other co-owners of Plant Scherer alleging that their contractual responsibility for a proportionate share of certain common facility costs relating to future environmental projects at Plant Scherer should be decreased following the retirement of Scherer Unit No. 4 at the end of 2021. We and the other co-owners of Plant Scherer filed motions to dismiss Florida Power & Light and JEA's complaint and, on February 9, 2023, the court granted our motions to dismiss with leave to amend. On March 13, 2023, Florida Power & Light and JEA filed an amended complaint and on April 17, 2023, we and the other co-owners filed motions to dismiss this amended complaint. On March 26, 2024, the court granted our motions to dismiss with leave for plaintiffs to once again amend their complaint by April 11, 2024, which the plaintiffs did not do and so, on April 15, 2024, the court entered an order dismissing the action and directing the clerk to close the case. Plaintiffs have until May 15, 2024 to appeal that order.

(I)Restricted Cash and Investments.

Restricted cash consists of collateral posted by our counterparties under our natural gas swap agreements. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the unaudited consolidated balance sheets that sum to the total of the same such amounts reported in the unaudited consolidated statements of cash flows.

Classification
	Three months ended
	March 31, 2024		March 31, 2023
	(dollars in thousands)
Cash and cash equivalents	$	327,470	$	390,821
Restricted cash included in restricted cash and short-term investments	—		16,000
Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows	$	327,470	$	406,821

(J)Regulatory Assets and Liabilities.    We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery through future rates. We expect to recover such costs from our members in future revenues through rates under the wholesale power contracts we have with each of our members. The wholesale power contracts extend through December 31, 2085. 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.

18

The following regulatory assets and liabilities are reflected on the consolidated balance sheets as of March 31, 2024 and December 31, 2023.

	2024		2023
	(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	24,504	$	25,476
Amortization of financing leases(b)	27,760		28,780
Outage costs(c)	34,627		30,040
Asset retirement obligations—Ashpond and other(l)	338,752		343,523
Depreciation expense - Plant Vogtle(d)	33,770		34,125
Depreciation expense - Plant Wansley(e)	330,945		335,884
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f)	55,528		55,159
Interest rate options cost(g)	135,561		137,463
Deferral of effects on net margin—TA Smith Energy Facility(h)	129,299		130,786
Deferral of effects on net margin—BC Smith Energy Facility(p)	9,379		1,817
Other regulatory assets(o)	16,123		8,436
Total Regulatory Assets	$	1,136,248	$	1,131,489
Regulatory Liabilities:
Accumulated retirement costs for other obligations(i)	$	23,455	$	25,992
Deferral of effects on net margin—Hawk Road Energy Facility(h)	15,866		16,020
Major maintenance reserve(j)	114,484		120,547
Deferred debt service adder(k)	174,507		170,466
Asset retirement obligations—Nuclear(l)	82,606		47,217
Revenue deferral plan(m)	279,467		308,507
Natural gas hedges(n)	10,381		13,445
Other regulatory liabilities(o)	3,318		4,126
Total Regulatory Liabilities	$	704,084	$	706,320
Net Regulatory Assets	$	432,164	$	425,169

(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 20 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 60 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit.

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

(e)Represents the deferral of accelerated depreciation associated with the early retirement of Plant Wansley, which occurred on August 31, 2022. Amortization commenced upon the retirement of Plant Wansley and will end no later than December 31, 2040.

(f)Deferred charges consist of training related costs, including interest and carrying costs of such training. Amortization commences effective with the commercial operation date of each unit and is amortized to expense over the life of the units.

(g)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 commenced in August 2023 after Vogtle Unit No. 3 was placed in service.

(h)Effects on net margin for TA 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.

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

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

(k)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.

(l)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.

(m)Deferred revenues under a rate management program that allowed for additional collections over a five-year period which began in 2018. These amounts are being amortized to income and applied to member billings, per each members' election, over the subsequent five-year period.

(n)Represents the deferral of unrealized gains on natural gas contracts.

19

(o)The amortization periods for other regulatory assets range up to 30 years and the amortization periods of other regulatory liabilities range up to 24 years.

(p)Effects on net margin for the BC Smith Energy Facility that are being deferred until on or before January 2026 and will be amortized over the remaining life of the plant.

(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 December 2028, with the majority of the balance scheduled to be credited by the end of 2025.

(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).

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. 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 term loan facility (the Facility) under which we borrowed a total of $4,633,028,088. We received our final advance under the Facility in December 2022. Interest is payable quarterly in arrears and principal payments on all advances under the FFB Notes began on February 20, 2020. As of March 31, 2024, we have repaid $486,220,945 of principal on the FFB Notes and the aggregate Department of Energy-guaranteed borrowings outstanding, including capitalized interest, totaled $4,146,807,143. The final maturity date is February 20, 2044. 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 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.

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.

b)Rural Utilities Service Guaranteed Loans:

For the three-month period ended March 31, 2024, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $6,067,000 for long-term financing of general and environmental improvements at existing plants.

In April 2024, we received an additional $6,374,000 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 (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

20

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. 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.

On July 31, 2023, Georgia Power placed Unit No. 3 in service.

On February 14, 2024, Unit No. 4 achieved self-sustaining nuclear fission, commonly referred to as initial criticality, and on March 1, 2024, the generator successfully synchronized to the power grid and generated electricity for the first time. Georgia Power placed Unit No. 4 in service on April 29, 2024.

Our ownership interest and proportionate share of the cost to construct Vogtle Units No. 3 and No. 4 is 30%, representing approximately 660 megawatts. Our project budget, which includes capital costs and allowance for funds used during construction, is approximately $8.3 billion. As of March 31, 2024, our actual costs related to the new Vogtle units were approximately $8.2 billion, net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and approximately $404 million we received from Georgia Power.

For additional information regarding our participation in Plant Vogtle Units No. 3 and No. 4, see Note 8 in our 2023 Form 10-K.

Plant Vogtle Unit No. 3 and No. 4 Commercial Operations

For the three months ended March 31, 2024, we sold Georgia Power $12.1 million of nuclear production tax credits and recognized the amount as a credit to the Production expense line item within our consolidated income statements. In 2023, we sold Georgia Power $21.7 million of nuclear production tax credits. No credits were generated or sold during the three months ended March 31, 2023.

(N)Measurement of Credit Losses on Financial Instruments. The financial assets we hold that are subject to credit losses (Topic 326) are predominately accounts receivable and certain cash equivalents classified as held-to-maturity debt (e.g. commercial paper). Our receivables are generally due within thirty days or less with a significant portion related to billings to our members. See Note F for information regarding our member receivables. Commercial paper we invest in is rated as investment grade. Given our historical experience, the short duration lifetime of these financial assets and the short time horizon over which to consider expectations of future economic conditions, we have assessed that non-collection of the cost basis of these financial assets is remote and we have not recognized an allowance for credit losses.

(O)Asset Retirement Obligations. On February 14, 2024, Plant Vogtle Unit No. 4's nuclear reactor achieved self-sustaining nuclear fission, commonly referred to as initial criticality. During the first quarter of 2024, we recognized new nuclear asset retirement obligations totaling $65.1 million. During the three months ended March 31, 2024, no change in cash flow estimates related to existing coal ash related asset retirement obligations was recorded. We expect to periodically receive more refined estimates from Georgia Power regarding closure costs and the timing of expenditures.

(P)Plant Purchase Agreement. On August 22, 2023, we signed an agreement with Mackinaw Power, LLC to purchase Walton County Power, LLC, owner of the Walton County Power Plant. The Walton facility consists of three natural gas-fired combustion turbine electric generating units with a combined nominal capacity of 465 megawatts located in Walton County, Georgia. The acquisition is subject to customary closing conditions and is expected to close in 2024.

21

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.

We have a substantially similar wholesale power contract with each member that extends to December 31, 2085, and each contract will continue thereafter until terminated by three years' written notice by us or the respective member. For additional information regarding our wholesale power contracts with our members, see “Item 1–BUSINESS–OGLETHORPE POWER CORPORATION–Wholesale Power Contracts” in our 2023 Form 10-K.

Results of Operations

For the Three Months Ended March 31, 2024 and 2023

Net Margin

Our net margin for the three-month period ended March 31, 2024 was $42.1 million, compared to $24.4 million for the same period of 2023. Through March 31, 2024, we collected approximately 59% of our targeted net margin of $71.7 million for the year ending December 31, 2024. These collections are typical as our capacity revenues are generally recorded evenly throughout the year. We anticipate our board of directors will approve a budget adjustment by year end so that margins will achieve, but not exceed, the 2024 targeted margins for interest ratio of 1.14. As a result, we assessed 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, 2024. 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 2023 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, and sales to non-members.

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. These revenues are designed to recover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Energy revenues are the sales of electricity generated or purchased for our members. Energy revenues recover the variable costs of our business, including fuel, purchased energy and variable operation and maintenance expense.

22

The components of member revenues for the three-month period ended March 31, 2024 and 2023 were as follows:

	Three Months Ended March 31,
	(dollars in thousands)
	2024			2023			% Change
Capacity revenues	$	355,718		$	242,043		47.0	%
Energy revenues	179,652			145,610			23.4	%
Total	$	535,370		$	387,653		38.1	%
MWh Sales to members(1)	6,836,560			5,948,052			14.9	%
Cents/kWh	7.83			6.52			20.1	%
Member energy requirements supplied(1)	66		%	64		%	3.1	%

(1) Excludes test energy megawatt-hours from Plant Vogtle Unit No. 4 supplied to members. Any revenues and costs associated with test energy were capitalized. No test energy from Plant Vogtle Unit No. 3 was supplied to members during the three-month period ended March 31, 2023.

Energy revenues from members increased for the three-month period ended March 31, 2024 compared to the same period in 2023, primarily due to the increase in megawatt-hours sold to members and recovery of higher fuel costs. For a discussion of fuel costs, which are the primary costs recovered by energy revenues, see "—Operating Expenses." Capacity revenues from members increased for the three-month period ended March 31, 2024 compared to the same period in 2023, primarily due to the recovery of increased fixed operating expenses, net interest expense and depreciation expense as a result of Plant Vogtle Unit No. 3 being placed in service on July 31, 2023.

Sales to non-members.    Sales to non-members during the three-month period ended March 31, 2024 and 2023 were as follows:

	Three Months Ended March 31,
	(dollars in thousands)
	2024		2023		% Change
Energy revenues	$	158	$	1,037	(84.8)	%
Capacity revenues	786		763		3.0	%
Total	$	944	$	1,800	(47.6)	%
MWh Sales to non-members	5,065		39,215		(87.1)	%
Cents/kWh	18.64		4.59		306.1	%

Energy revenues from non-members were primarily from the sale of the BC Smith Energy Facility's deferring members' output into the wholesale market. Capacity revenues from non-members related to the two units we acquired at the Washington County Power Plant in December 2022. Energy revenues from non-members decreased for the three-month period ended March 31, 2024 compared to the same period in 2023 primarily due to the decrease in megawatt-hours sold to non-members as a result of a scheduled major maintenance outage at BC Smith Energy Facility during first quarter of 2024. Capacity revenues from non-members remained relatively unchanged for the comparable three-month periods.

23

Operating Expenses

Fuel

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

	Cost					Generation(1)			Cents per kWh
	(dollars in thousands)					(MWh)
	Three Months Ended March 31,					Three Months Ended March 31,			Three Months Ended March 31,
Fuel Source	2024		2023		% Change	2024	2023	% Change	2024	2023	% Change
Coal	$	38,534	$	22,788	69.1%	982,397	578,342	69.9%	3.92	3.94	(0.5)%
Nuclear	23,995		16,043		49.6%	3,048,598	2,210,269	37.9%	0.79	0.73	8.2%
Gas:
Combined Cycle	96,841		91,686		5.6%	2,934,390	3,326,422	(11.8)%	3.30	2.76	19.6%
Combustion Turbine	7,676		2,651		189.6%	86,518	77,659	11.4%	8.87	3.41	160.1%
	$	167,046	$	133,168	25.4%	7,051,903	6,192,692	13.9%	2.37	2.15	10.2%

(1) Excludes test energy megawatt-hours generated at Plant Vogtle Unit No. 4. No test energy megawatt-hours were generated at Plant Vogtle Unit No. 3 during the three-month period ended March 31, 2023.

Total fuel costs increased for the three-month period ended March 31, 2024 compared to the same period in 2023 as a result of an increase in generation for members and an increase in the average cost of fuel. The increase in generation was primarily due to Plant Vogtle Unit No. 3 being placed in service on July 31, 2023. The increase in average fuel cost was primarily due to a shift in generation to our coal-fired units from our relatively more economical combined cycle units due in part to the management of our coal inventory and planned major maintenance outages at our combined cycle units during the first quarter of 2024.

Production Expenses

Production costs increased for the three-month period ended March 31, 2024 as compared to the same period of 2023 primarily as a result of $15.7 million in production costs related to Plant Vogtle Unit No. 3, net of $12.1 million in credits recognized from the sale of nuclear production tax credits to Georgia Power. Production costs can also vary due to the number and extent of maintenance outages in a given year. Production costs also increased for the three-month period ended March 31, 2024 as compared to the same period of 2023 as a result of higher fixed major maintenance outage costs associated with our combined cycle plants.

Depreciation and Amortization Expenses

Depreciation and amortization increased for the three-month period ended March 31, 2024 as compared to the same period of 2023 primarily as a result of Plant Vogtle Unit No. 3 being placed in service on July 31, 2023.

Interest Charges

Net interest charges increased for the three-month period ended March 31, 2024 as compared to the same period of 2023 as a result of lower capitalization of interest expense due to Plant Vogtle Unit No. 3 being placed in service on July 31, 2023.

Financial Condition

Balance Sheet Analysis as of March 31, 2024

Assets

Cash used for property additions for the three-month period ended March 31, 2024 totaled $174.3 million. Of this amount, $52.5 million was associated with construction expenditures for Vogtle Unit No. 4 and $25.3 million was for nuclear fuel purchases. The remainder was for expenditures related to normal additions and replacements to our existing generation facilities.

The $38.1 million increase in the nuclear decommissioning trust fund was primarily due to the increase in the fair market value of investments due to continued appreciation in the stock market during the three-month period ended March 31, 2024.

24

Long-term investments increased $19.1 million for the three-month period ended March 31, 2024, primarily due to an additional $33.8 million of funds invested, including reinvestment of earnings, and an $8.1 million increase in fair market value largely offset by a net $31.2 million decrease due to redemptions.

Receivables decreased $21.4 million for the three-month period ended March 31, 2024 primarily due to a $20.7 million decrease in member receivables.

Prepayments and other current assets increased $30.6 million during the three-month period ended March 31, 2024 primarily due to a $32.3 million increase in prepayments related to future major maintenance outage costs at our natural gas-fired facilities.

Equity and Liabilities

Long-term debt and long-term debt and finance leases due within one year decreased $129.2 million primarily as a result of $136.0 million in debt service payments. Offsetting this decrease was $6.1 million in advances under a Rural Utilities Service-guaranteed loan. See Note L of Notes to Unaudited Consolidated Financial Statements for additional information regarding long-term debt.

Short-term borrowings, which primarily provide interim financing for Vogtle Units No. 3 and No. 4 construction costs, increased $54.9 million during the three-month period ended March 31, 2024. During this period, total short-term borrowings were $66.9 million and repayments totaled $12.0 million.

Accounts payable decreased $53.9 million during the three-month period ended March 31, 2024. The decrease was primarily due to applying $34.3 million in credits to our members' bills in the first quarter of 2024 for a board-approved reduction in 2023 revenue in excess of the requirement to meet the 2023 targeted net margin and a $15.8 million decrease in payables for natural gas purchases and related transportation.

Asset retirement obligations increased $78.9 million for the three-month period ended March 31, 2024 primarily due to recognized nuclear asset retirement obligations of $65.1 million due to Plant Vogtle Unit No. 4's nuclear reactor achievement of self-sustaining nuclear fission and $17.6 million in accretion expense.

Capital Requirements and Liquidity and Sources of Capital

Vogtle Units No. 3 and No. 4

We, Georgia Power, 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. 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.

On July 31, 2023, Georgia Power placed Unit No. 3 in service.

On February 14, 2024, Unit No. 4 achieved self-sustaining nuclear fission, commonly referred to as initial criticality, and on March 1, 2024, the generator successfully synchronized to the power grid and generated electricity for the first time. Georgia Power placed Unit No. 4 in service on April 29, 2024.

Our ownership interest and proportionate share of the cost to construct Vogtle Units No. 3 and No. 4 is 30%, representing approximately 660 megawatts. Our project budget, which includes capital costs and allowance for funds used during construction, is approximately $8.3 billion. As of March 31, 2024, our actual costs related to the new Vogtle units were approximately $8.2 billion, net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and approximately $404 million we received from Georgia Power.

See “Item 1 – BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources – Vogtle Units No. 3 and No. 4” in our annual report on Form 10-K for the fiscal year ended December 31, 2023 for additional information regarding our participation in Plant Vogtle Units No. 3 and No. 4.

Plant Purchase Agreement

On August 22, 2023, we signed an agreement with Mackinaw Power, LLC to purchase Walton County Power, LLC, owner of the Walton County Power Plant. The Walton facility consists of three natural gas-fired combustion turbine electric generating

25

units with a combined nominal capacity of 465 megawatts located in Walton County, Georgia. The acquisition is subject to customary closing conditions and is expected to close in 2024.

Grid Resilience and Innovation Partnerships (GRIP) Program

On October 18, 2023, the Georgia Environmental Finance Authority, together with application partners Oglethorpe, Georgia Transmission Corporation and Georgia System Operations Corporation, announced that they had been selected for a $250 million grant under the Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) Program. As part of the grant application, Oglethorpe applied for an aggregate of 75 megawatts of utility-scale battery storage which is estimated to utilize approximately $80 million of the total award. Receipt of any grant proceeds is subject to meeting program requirements and customary closing conditions and the ultimate projects financed with these funds may change from the initial application.

Other Future Power Resources

We and our members are currently evaluating up to approximately 1,500 megawatts of additional gas generation capacity through the construction of combined cycle and combustion turbine units. If we proceed with these projects under consideration, our estimated construction costs would be in the range of $2.0 billion to $2.5 billion. In connection with this evaluation, we are also in the process of securing additional natural gas transportation to serve these additional units. We expect these additional resources to be fully subscribed by our members by the end of the second quarter 2024. We and our members may also continue to evaluate and consider additional generation beyond these resources in the future.

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 2023 Form 10-K.

On April 25, 2024, the Environmental Protection Agency issued a final rule to regulate carbon dioxide (CO2) emissions from fossil-fueled electric generating units under section 111 of the Clean Air Act (CAA). The primary focus of EPA’s final rule is to (i) establish emission guidelines for states to set CO2 performance standards for existing coal-fired generating units and other fossil-fueled steam generating units that burn oil and natural gas under section 111 (d) of the Clean Air Act; and (ii) revise the new source performance standards for CO2 emissions from new and reconstructed stationary combustion turbines that burn natural gas and/or other fossil fuels under section 111 (b) of the CAA. We expect that the final rule is likely to have a significant impact on the power sector and we are reviewing the final rule to determine its impact on our operations. We believe that key assumptions in the rule, particularly regarding resource adequacy, availability and timing of required infrastructure and permitting, carbon capture and sequestration and the pace of technological advancements, continue to be unrealistic. The final rule has been challenged, and its ultimate impact will not be known until those legal challenges are complete. At this time, we cannot predict the outcome or potential cost of this rule, but such costs could be significant.

EPA issued three additional final rules on April 25, 2024. Respectively, the rules had the effect of (i) revising effluent limitation guidelines for wastewater streams at coal-fired power plants, (ii) revising the Mercury and Air Toxics Standards (MATS) for coal-fired power plants and (iii) establishing new requirements for legacy coal combustion residuals. The revised MATS rules are not expected to have a significant impact on our operations. We are reviewing the other two final rules and their ultimate impact on us remains subject to any legal challenges and cannot be determined at this time.

On February 7, 2024, EPA issued a final rule tightening the National Ambient Air Quality Standards (NAAQS) for fine particulate matter (PM2.5) emissions. We are in the process of reviewing the final rule and its impact on us cannot be determined at this time.

Liquidity

At March 31, 2024, we had $1.5 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $327 million in cash and cash equivalents, and $1.1 billion available under our $1.8 billion of committed credit arrangements, the details of which are reflected in the table below:

26

Committed Credit Facilities
	Authorized Amount		Available March 31, 2024			Expiration Date
	(dollars in millions)
Unsecured Facilities:
Syndicated Line among 12 banks led by CFC'(1)	$	1,210	$	543		December 2024
CFC Line of Credit(2)	110		110			December 2028
JPMorgan Chase Line of Credit	350		347		'(3)	October 2024
Secured Facilities:
CFC Term Loan(2)	250		140			December 2028

(1)This facility is dedicated to support outstanding commercial paper and the portion of this facility that was unavailable represents outstanding commercial paper at March 31, 2024. We anticipate renewing this facility in the second quarter of 2024.

(2)Any amounts drawn under the $110 million unsecured line of credit with CFC will reduce the amount that can be drawn under the $250 million secured term loan. Therefore, we reflect $140 million as the amount available under the term loan even though there are no amounts outstanding 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)At March 31, 2024,$2.5 million of this facility was used for letters of credit issued to provide performance assurance 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, issuing letters of credit and backing up commercial paper.

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. Due to this requirement, any commercial paper we issue will reduce the availability under the $1.2 billion syndicated line of credit. At March 31, 2024, our outstanding commercial paper primarily was used to provide interim funding for:

•payments related to the construction of Vogtle Units No. 3 and No. 4,

•principal payments due under our Department of Energy-guaranteed loans, which began in February 2020, and

•costs related to the Washington County and Baconton acquisitions.

We plan to refinance our commercial paper with long-term debt. We intend to issue first mortgage bonds to provide long-term financing of the construction costs for Vogtle Units No. 3 and No. 4 that have been financed on an interim basis with commercial paper, refinancing of the principal payments we are currently paying under our Department of Energy-guaranteed loans, and for certain other costs not financed through the Rural Utilities Service. Rural Utilities Service financing is our preferred source of long-term financing for the Washington County and Baconton acquisitions, and, in February 2024, we received conditional commitments for new Rural Utilities Service-guaranteed loans for these acquisitions.

Our unsecured committed lines of credit permit the issuance of up to $960 million in letters of credit on our behalf, of which $957 million remained available at March 31, 2024. This letter of credit issuance capacity includes $500 million under our $1.2 billion syndicated line of credit, $350 million under our JPMorgan Chase line of credit, and $110 million under our CFC line of credit.

Three of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At March 31, 2024, the required minimum level was $750 million and our actual patronage capital was $1.3 billion. These agreements contain an additional covenant that limits our secured indebtedness and unsecured indebtedness, both as defined in the credit agreements, to $14 billion and $4 billion, respectively. At March 31, 2024, we had $12.0 billion of secured indebtedness and $663 million of unsecured indebtedness outstanding.

Under our power bill prepayment program, members can prepay their power bills from us at a discount for an agreed number of months in advance, after which point the funds are credited against the participating members' monthly power bills. At March 31, 2024, we had six members participating in the program and a balance of $95.9 million remaining to be applied against future power bills.

27

Financing Activities

First Mortgage Indenture. At March 31, 2024, we had $12.0 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 2023 Form 10-K for further discussion of our first mortgage indenture.

Rural Utilities Service-Guaranteed Loans. At March 31, 2024, we had one approved Rural Utilities Service-guaranteed loan totaling $630.3 million to fund general and environmental improvements that had $188.4 million remaining to be advanced. When advanced, the debt will be secured ratably under our first mortgage indenture. In September 2023, we received a conditional loan commitment for a new Rural Utilities Service-guaranteed loan totaling $755.2 million that we expect to begin advancing in late 2024. In February 2024, we received two additional conditional commitments for new Rural Utilities-Service-guaranteed loans totaling $87.9 million and $17.5 million, respectively, for the Washington County and Baconton acquisitions, and we expect to begin advancing on both loans in late 2024. As of March 31, 2024, we had $2.6 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.

Department of Energy-Guaranteed Loans. We have loans from the Federal Financing Bank guaranteed by the Department of Energy that provided funding for over $4.6 billion of the cost to construct our interest in Vogtle Units No. 3 and No. 4. We have fully advanced the $4.6 billion available under the Department of Energy-guaranteed loans and $4.1 billion was outstanding at March 31, 2024. All of the debt advanced under the loan guarantee agreement is secured ratably with all other debt under our first mortgage indenture.

In accordance with the promissory notes, we began principal repayments of our Department of Energy-guaranteed loans in February 2020. As of March 31, 2024, we had repaid $486.2 million under these loans. We plan to refinance a portion of this amount by issuing first mortgage bonds before the end of 2024.

.

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 2023 Form 10-K.

Bond Financings. We plan to issue a total of approximately $750-$800 million of taxable first mortgage bonds before the end of 2024 to provide long-term financing or refinancing of expenditures related to Vogtle Units No. 3 and No. 4, including up to $350 million for the remaining long-term financing for the Vogtle units and up to $486 million to refinance principal payments on our Department of Energy-guaranteed loans that were made prior to Vogtle Unit No. 4's in-service date. We currently anticipate issuing these bonds before the end of 2024, and subject to market conditions, these bonds may be issued in more than one series.

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 been no material changes to the market risks disclosed in "Item 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK" in our 2023 Form 10-K.

Item 4.    Controls and Procedures

As of March 31, 2024, 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, 2024 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

28

PART II—OTHER INFORMATION

Item 1.    Legal Proceedings

The ultimate outcome of pending litigation against us cannot be predicted at this time; however, we do not anticipate that the ultimate liabilities, if any, arising from such proceedings would have a material effect on our financial condition or results of operations. For information about loss contingencies, including litigation related to Plant Scherer, of which we are a co-owner, that could have an effect on us, see Note H to Unaudited Consolidated Financial Statements.

Item 1A.    Risk Factors

We are subject to construction risks for additional projects under consideration for our members to meet projected load growth in Georgia.

Georgia is projected to experience a significant increase in energy demand, including large loads, over the next several years, and we and our members are considering additional generation resources to serve this growth. Loads of 900 kilowatts or more in Georgia are subject to competition at initial operation, and our members may be selected to meet some of the additional large loads in their service territories. We and our members will use the best information we have available to us to appropriately plan for our members’ anticipated power needs. We and our members are currently evaluating up to approximately 1,500 megawatts of additional gas generation capacity through the construction of combined cycle and combustion turbine units. If we proceed with these projects under consideration, our estimated construction costs would be in the range of $2.0 billion to $2.5 billion. We are also evaluating capacity commitments for new natural gas pipeline infrastructure to meet our anticipated fuel supply needs. We expect these additional resources to be fully subscribed by our members by the end of the second quarter 2024. We and our members may also continue to evaluate and consider additional generation beyond these resources in the future. If our members’ actual load growth is significantly lower than projected, costs related to any new facilities could increase the cost of electric service we provide to those members more than anticipated and could affect their ability to perform their contractual obligations to us.

Should we proceed with constructing generating facilities and securing additional natural gas pipeline capacity to serve these facilities, we will be exposed to construction risks. We will also be subject to construction risks for capital projects to comply with current or future environmental standards. Many factors could lead to cost increases and schedule delays for any of these projects, including:

•cost and availability of labor;

•challenges related to contractors or vendors;

•subcontractor performance;

•timing and issuance of necessary permits or approvals (including required certificates from regulatory agencies);

•shortages, delays, increased costs or inconsistent quality of materials and equipment;

•performance under construction agreements and contract disputes;

•the cost and availability of debt financing, including the availability of federal loan or grant programs, increased interest rates or increased funding costs as a result of construction schedule delays;

•catastrophic events, natural disasters and future pandemic health events; and

•weather conditions.

Failure to complete any construction project on schedule and on budget for any reason could increase the cost of electric service we provide to our members and, as a result, could affect their ability to perform their contractual obligations to us.

Legislative and regulatory actions intended to address climate change and to reduce greenhouse gas emissions, including carbon dioxide, may result in significant compliance costs or expenses.

Concerns regarding climate change continue to increase and the responses to those concerns by policymakers, regulators, investors, consumers and other stakeholders may affect us and our members in various ways. The costs associated with legislative or regulatory actions intended to reduce greenhouse gas emissions could be significant.

President Biden has signed a number of executive orders directing federal agencies to address climate change, environmental justice, and other environmental issues. President Biden also recommitted the United States to the Paris Climate Agreement in 2021. Also in 2021, under the Paris Climate Agreement’s format, the United States announced a nationally determined contribution for reducing economy-wide carbon dioxide emissions by 50-52% below 2005 levels by 2030. In order to meet the United States nationally determined contribution, analyses indicate that the power sector would have to reduce carbon dioxide emissions by about 80% below 2005 levels by 2030.

29

In April 2024, EPA finalized rules to replace the Affordable Clean Energy rule that limit greenhouse gas emissions from fossil-fueled electric generating units under Section 111 of the Clean Air Act in a manner consistent with the United States’ nationally determined contribution. We are reviewing the final rules to determine the impact on our existing operations and any potential future natural gas-fired resources. EPA separately announced that it would address existing natural gas-fired facilities in a future rulemaking instead of the final rule. We expect that the final rule is likely to have a significant impact on the power sector and we are reviewing the final rule to determine its impact on our operations. We believe that key assumptions in the rule, particularly regarding resource adequacy, availability and timing of required infrastructure and permitting, carbon capture and sequestration and the pace of technological advancements, continue to be unrealistic. The final rule has been challenged, and its ultimate impact will not be known until those legal challenges are complete. At this time, we cannot predict the outcome or potential cost of this rule, but such costs could be significant.

Based on these developments, and trends more generally, we expect federal and state legislative and regulatory efforts to reduce the potential impacts of climate change and limit greenhouse gas emissions, including carbon dioxide, to continue. For example, the Inflation Reduction Act of 2022 includes significant financial incentives to accelerate the U.S. transition to a lower greenhouse gas emitting economy. Congress has also recently considered proposals that would mandate significant emissions reductions or increases in clean energy generation from the power sector. Passing new climate legislation, whether in the form of a carbon tax, a clean electricity standard or another proposal, remains challenging in the near-term. The timing, cost and effect of any future laws or regulations attempting to address climate change and reduce greenhouse gas emissions are uncertain. However, such laws or regulations could impose operational restrictions on affected generating facilities and impose substantial costs on our business.

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

During the fiscal quarter ended March 31, 2024, none of our directors or “officers,” as defined in Rule 16a-1(f) under the Securities Exchange Act of 1934, adopted or terminated any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as those terms are defined in Item 408 of Regulation S-K. As noted on the cover page of this quarterly report on Form 10-Q, we are a membership corporation and have no authorized or outstanding equity securities although we do have outstanding debt securities.

30

Item 6.    Exhibits

Number	Description
3.1	Bylaws of Oglethorpe, as amended and restated, as of March 25, 2024. (Filed as Exhibit 3.2 to the Registrant's Form S-4, File No. 333-278279 and incorporated by reference herein.)
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).
101	XBRL Interactive Data File.
104	Cover Page Interactive Data File, formatted in Inline XBRL.

31

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, 2024	By:	/s/ Michael L. Smith
			Michael L. Smith President and Chief Executive Officer
Date:	May 13, 2024		/s/ Elizabeth B. Higgins
			Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)