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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, 2025

☐ 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

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, 2025


		Page No.
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Consolidated Balance Sheets as of March 31, 2025 and December 31, 2024	1
	Unaudited Consolidated Statements of Revenues and Expenses For the Three Months ended March 31, 2025 and 2024	3
	Unaudited Consolidated Statements of Patronage Capital and Membership Fees For the Three Months ended March 31, 2025 and 2024	4
	Unaudited Consolidated Statements of Cash Flows For the Three Months ended March 31, 2025 and 2024	5
	Notes to Unaudited Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 4.	Controls and Procedures	29
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	29
Item 1A.	Risk Factors	29
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

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, 2024, 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 our two new natural gas-fired generation facilities, our battery storage resources, the closure of coal ash ponds and any other future generation projects we may undertake;

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

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

•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 and the availability of funding under any federal loan or grant programs for which we received awards and our ability to meet the applicable loan or grant conditions and requirements;

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

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

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

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

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

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

•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 or our members, 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 (including from data centers and other large commercial and industrial loads), energy conservation and efficiency efforts and the general economy;

•general economic conditions;

•tariffs and geopolitical trade tensions;

•weather conditions and other natural phenomena;

•litigation or legal and administrative proceedings and settlements;

•unanticipated changes in interest rates or rates of inflation;

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

•early retirement of our co-owned coal units;

•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, 2025 and December 31, 2024


	(dollars in thousands)
	2025		2024
Assets
Electric plant:
In service	$	17,399,057	$	17,388,476
Right-of-use assets—finance leases	302,732		302,732
Less: Accumulated provision for depreciation	(5,775,301)		(5,701,627)
Electric plant in service, net	11,926,488		11,989,581

Nuclear fuel, at amortized cost	415,114		402,328
Construction work in progress	456,401		320,167
Total electric plant	12,798,003		12,712,076

Investments and funds:
Nuclear decommissioning trust fund	723,015		721,624
Investment in associated companies	85,407		86,720
Long-term investments	638,561		645,166


Other	39,401		38,862
Total investments and funds	1,486,384		1,492,372

Current assets:
Cash and cash equivalents	234,324		337,813
Restricted cash and short-term investments	15,200		500
Short-term investments	119,860		124,572
Receivables	232,342		246,581
Inventories, at weighted average cost	346,428		356,285
Prepayments and other current assets	88,744		44,218
Total current assets	1,036,898		1,109,969

Deferred charges and other assets:
Regulatory assets	1,106,060		1,103,633
Prepayments to Georgia Power Company	17,326		16,334
Other	50,808		43,154
Total deferred charges	1,174,194		1,163,121
Total assets	$	16,495,479	$	16,477,538

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


Oglethorpe Power Corporation Consolidated Balance Sheets (Unaudited) March 31, 2025 and December 31, 2024


	(dollars in thousands)

	2025		2024
Equity and Liabilities

Capitalization:
Patronage capital and membership fees	$	1,371,424	$	1,328,418
Long-term debt	12,137,161		12,134,194
Obligation under finance leases	33,173		33,173
Obligation under Rocky Mountain transactions	32,448		31,910
Other	5,242		5,715
Total capitalization	13,579,448		13,533,410

Current liabilities:
Long-term debt and finance leases due within one year	395,130		398,979
Short-term borrowings	189,042		145,604
Accounts payable	65,052		138,537
Accrued interest	105,455		81,425
Member power bill prepayments, current	33,125		31,258
Other current liabilities	117,952		140,611
Total current liabilities	905,756		936,414

Deferred credits and other liabilities:
Asset retirement obligations	1,285,530		1,279,121
Member power bill prepayments, non-current	50,208		54,183
Regulatory liabilities	662,088		661,592
Other	12,449		12,818
Total deferred credits and other liabilities	2,010,275		2,007,714
Total equity and liabilities	$	16,495,479	$	16,477,538

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


Oglethorpe Power Corporation Consolidated Statements of Revenues and Expenses (Unaudited) For the Three Months Ended March 31, 2025 and 2024


	(dollars in thousands)

	Three Months
	2025		2024
Operating revenues:
Sales to members	$	668,301	$	535,370
Sales to non-members	9,275		944
Total operating revenues	677,576		536,314
Operating expenses:
Fuel	242,647		167,046
Production	130,328		118,090
Depreciation and amortization	106,257		94,105
Purchased power	21,731		19,220
Accretion	14,532		17,622
Total operating expenses	515,495		416,083
Operating margin	162,081		120,231

Other income:
Investment income	8,497		17,052


Other	3,559		2,804
Total other income	12,056		19,856

Interest charges:
Interest expense	132,434		129,391
Allowance for debt funds used during construction	(3,728)		(34,107)
Amortization of debt discount and expense	2,425		2,704
Net interest charges	131,131		97,988
Net margin	$	43,006	$	42,099

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


Oglethorpe Power Corporation Consolidated Statements of Patronage Capital and Membership Fees (Unaudited) For the Three Months Ended March 31, 2025 and 2024


	(dollars in thousands)
Balance at December 31, 2023	$	1,257,917
Net margin	42,099
Balance at March 31, 2024	$	1,300,016
Balance at December 31, 2024	$	1,328,418
Net margin	43,006
Balance at March 31, 2025	$	1,371,424

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


Oglethorpe Power Corporation Consolidated Statements of Cash Flows (Unaudited) For the Three Months Ended March 31, 2025 and 2024


	(dollars in thousands)
	2025		2024
Cash flows from operating activities:
Net margin	$	43,006	$	42,099
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	147,277		131,940
Accretion cost	14,532		17,622
Amortization of deferred gains	(447)		(447)
Allowance for equity funds used during construction	(645)		(347)
Deferred outage costs	(22,938)		(11,856)
(Gain) loss on sale of investments	(1,152)		471

Regulatory deferral of costs associated with nuclear decommissioning	2,427		(8,125)
Other	(5,986)		(14,480)
Change in operating assets and liabilities:
Receivables	2,691		26,609
Inventories	9,856		7,683
Prepayments and other current assets	(20,391)		(30,569)
Accounts payable	(68,043)		(49,628)
Accrued interest	24,030		14,718
Accrued taxes	(35,541)		(33,733)
Other current liabilities	(15,319)		24,494
Rate management program billing credits applied	(34,369)		(35,646)
Other	(2,108)		17,336
Total adjustments	(6,126)		56,042
Net cash provided by operating activities	36,880		98,141
Cash flows from investing activities:
Property additions	(195,399)		(174,270)

Litigation proceeds received for capitalized spent nuclear fuel storage costs	21,684		—
Activity in nuclear decommissioning trust fund—Purchases	(272,569)		(140,865)
Activity in nuclear decommissioning trust fund—Proceeds	265,722		136,894


Activity in long-term and short-term investments—Purchases	(66,621)		(82,283)
Activity in long-term and short-term investments—Proceeds	79,430		80,672
Other	(604)		(3,512)
Net cash used in investing activities	(168,357)		(183,364)
Cash flows from financing activities:
Long-term debt proceeds	390,398		6,067
Long-term debt payments	(133,149)		(136,047)
(Decrease) increase in short-term borrowings, net	(211,026)		54,894
Other	(3,535)		(2,813)
Net cash provided by (used in) financing activities	42,688		(77,899)
Net decrease in cash, cash equivalents and restricted cash	(88,789)		(163,122)
Cash, cash equivalents and restricted cash at beginning of period	338,313		490,592
Cash, cash equivalents and restricted cash at end of period	$	249,524	$	327,470
Supplemental cash flow information:
Cash paid for—
Interest (net of amounts capitalized)	$	104,138	$	80,063
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	$	—	$	65,149
Accrued property additions at end of period	$	66,026	$	41,104

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

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, 2025 and 2024. 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.

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, 2024, as filed with the SEC. The results of operations for the three-month period ended March 31, 2025 are not necessarily indicative of results to be expected for the full year. As noted in our 2024 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 2024 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.

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, 2025 and December 31, 2024.


	Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	March 31, 2025		(Level 1)		(Level 2)		(Level 3)
	(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	234,410	$	234,410	$	—	$	—

Corporate bonds and debt	87,115		—		86,529		586
US Treasury securities	55,750		55,750		—		—
Mortgage backed securities	71,984		—		71,984		—
Domestic mutual funds	89,061		89,061		—		—
Municipal bonds	8,099		—		8,099		—
Federal agency securities	9,243		—		9,243		—
Non-US Gov't bonds & private placements	4,545		—		4,545		—
International mutual funds	153,135		—		153,135		—

Other	9,673		9,673		—		—
Long-term investments:

Corporate bonds and debt	22,432		—		22,432		—
US Treasury securities	26,358		26,358		—		—
Mortgage backed securities	21,551		—		21,551		—
Domestic mutual funds	387,612		387,612		—		—

Treasury STRIPS	134,822		—		134,822		—
Non-US Gov't bonds & private placements	2,744		—		2,744		—
International mutual funds	42,439		—		42,439		—
Other	603		603		—		—
Short-term investments: Treasury STRIPS	119,860		—		119,860		—
Natural gas swaps	59,792		—		59,792		—


	Fair Value Measurements at Reporting Date Using
			Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	December 31, 2024		(Level 1)		(Level 2)		(Level 3)
	(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	245,313	$	245,313	$	—	$	—

Corporate bonds and debt	82,316		—		82,309		7
US Treasury securities	53,806		53,806		—		—
Mortgage backed securities	70,193		—		70,193		—
Domestic mutual funds	95,175		95,175		—		—
Municipal bonds	3,375		—		3,375		—
Federal agency securities	8,487		—		8,487		—
Non-US Gov't bonds & private placements	3,319		—		3,319		—
International mutual funds	4,228		—		4,228		—
Money Market	138,553		138,553		—		—
Other	16,859		16,859		—		—
Long-term investments:

Corporate bonds and debt	20,972		—		20,972		—
US Treasury securities	25,654		25,654		—		—
Mortgage backed securities	20,232		—		20,232		—
Domestic mutual funds	394,595		394,595		—		—

Treasury STRIPS	142,199		—		142,199		—
Non-US Gov't bonds & private placements	1,805		—		1,805		—
International mutual funds	39,340		—		39,340		—
Other	369		369		—		—
Short-term investments: Treasury STRIPS	124,572		—		124,572		—
Natural gas swaps	28,624		—		28,624		—

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 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, 2025 and December 31, 2024 were as follows:


	2025				2024
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	12,645,874	$	10,958,889	$	12,643,088	$	10,666,727

The estimated fair value of long-term debt is classified as Level 2 and is estimated based on observed or quoted market prices for the same or similar issues or on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. 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, 2025 and December 31, 2024 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, 2025, 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, 2025 and December 31, 2024, the estimated fair values of our natural gas contracts were net assets of approximately $59,792,000 and $28,624,000, respectively.

At March 31, 2025 and December 31, 2024, one of our counterparties was required to post credit collateral totaling $15,200,000 and $500,000, respectively, under our natural gas swap agreements. Such posted collateral is classified as restricted cash and included in the Restricted cash and short-term investments line item within our unaudited consolidated balance sheets.

The following table reflects the notional volume of our natural gas derivatives as of March 31, 2025 that is expected to settle or mature each year:


Year			Natural Gas Swaps (MMBTUs) (in millions)
2025			21.9
2026			23.0
2027			12.7
2028			4.4
2029			3.7
2030			2.5
Total			68.2

The table below reflects the fair value of derivative instruments subject to the right of setoff and their effect on our consolidated balance sheets at March 31, 2025 and December 31, 2024. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements when a legal right of setoff exists.


	Consolidated Balance Sheet Location	Fair Value
		2025						2024
		Assets		Liabilities		Net Carrying Value Presented on the Balance Sheet		Assets		Liabilities		Net Carrying Value Presented on the Balance Sheet
Assets		(dollars in thousands)
Natural gas swaps	Other current assets	$	42,157	$	(59)	$	42,098	$	19,527	$	(1,563)	$	17,964
Natural gas swaps	Other deferred charges	22,065		(4,371)		17,694		17,566		(5,279)		12,287
Liabilities
Natural gas swaps	Other current liabilities	$	—	$	—	$	—	$	290	$	(1,917)	$	(1,627)
Natural gas swaps	Other deferred credits	—		—		—		—		—		—
Total		$	64,222	$	(4,430)	$	59,792	$	37,383	$	(8,759)	$	28,624

The following table presents the gross realized gains and (losses) on derivative instruments recognized in net margins for the three months ended March 31, 2025 and 2024.


	Statement of Revenues and Expenses Location	Three Months Ended March 31,
		2025		2024
		(dollars in thousands)
Natural gas swaps gains	Fuel	$	2,366	$	41
Natural gas swaps losses	Fuel	(1,359)		(8,452)
Total		$	1,007	$	(8,411)

The following table presents the unrealized gains on derivative instruments deferred on the balance sheet at March 31, 2025 and December 31, 2024.


	Balance Sheet Location	2025		2024
		(dollars in thousands)
Natural gas swaps	Regulatory liability	$	59,792	$	28,624
Total		$	59,792	$	28,624

(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.

The following tables summarize debt and equity securities as of March 31, 2025 and December 31, 2024.


	Gross Unrealized
	(dollars in thousands)
March 31, 2025	Cost		Gains		Losses		Fair Value
Equity	$	410,316	$	217,254	$	(5,760)	$	621,810
Debt	855,540		5,535		(11,816)		849,259
Other	10,324		401		(358)		10,367
Total	$	1,276,180	$	223,190	$	(17,934)	$	1,481,436


	Gross Unrealized
	(dollars in thousands)
December 31, 2024	Cost		Gains		Losses		Fair Value
Equity	$	259,554	$	231,815	$	(6,385)	$	484,984
Debt	864,575		3,209		(17,336)		850,448
Other	155,802		224		(96)		155,930
Total	$	1,279,931	$	235,248	$	(23,817)	$	1,491,362

The cost basis of our debt securities that were in unrealized loss positions at March 31, 2025 was $601,694,000. At March 31, 2025, $1,532,000 of the $11,816,000 of unrealized losses relates to securities that have been in unrealized loss positions for less than twelve months and $10,284,000 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, 2024 was $688,233,000. At December 31, 2024, $2,874,000 of the $17,336,000 of unrealized losses relates to securities that have been in unrealized loss positions for less than twelve months and $14,462,000 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 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.

In November 2024, the FASB issued "Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosure (Subtopic 220-40): Disaggregation of Income Statement Expenses", which requires the disaggregation of certain expenses in the notes to the financial statements, to provide enhanced transparency into the expense captions presented on the face of the income statement. The new standard is effective for us for annual reporting periods beginning after December 15, 2026 and interim periods within fiscal years beginning after December 15, 2027. Early

adoption is permitted and the new standard may be applied either prospectively or retrospectively. We are currently evaluating the impact of this standard on our consolidated financial statements.

(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 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, 2025 and December 31, 2024, 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 and 2025, our board of directors approved budgets to achieve a 1.14 and 1.10 margins for interest ratio, respectively. 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 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, 2025, we did not recognize a refund liability. As of December 31, 2024, we recognized refund liabilities totaling $55,914,000. 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, 2025 and 2024 were as follows:


	Three Months Ended March 31,
	(dollars in thousands)

	2025		2024
Capacity revenues	$	413,337	$	355,718
Energy revenues	254,964		179,652
Total	$	668,301	$	535,370

Receivables from contracts with our members at March 31, 2025 and December 31, 2024 were $185,202,000 and $177,790,000, respectively.

Sales to non-members during the three months ended March 31, 2025 and 2024 were as follows:


	Three Months Ended March 31,
	(dollars in thousands)
	2025		2024
Energy revenues	$	9,275	$	158
Capacity revenues	—		786
Total	$	9,275	$	944

Energy revenues from non-members for the three months ended March 31, 2025 and March 31, 2024 were primarily from the sale of the BC Smith Energy Facility deferring members' output into the wholesale market.

The remainder of our receivables is primarily related to transactions with Georgia Power, including from the nuclear storage litigation judgments, non-members for the sale of the BC Smith deferring members' output, affiliated companies and investment income. Our receivables from non-members at March 31, 2025 and December 31, 2024 were $47,140,000 and $68,791,000, respectively. Our Georgia Power receivables at December 31, 2024 included $39,433,000 related to spent nuclear fuel storage costs litigation. At March 31, 2025, we had fully collected all outstanding receivables from Georgia Power related to the spent nuclear fuel storage costs litigation. For additional information regarding this litigation, see Note 1g in our 2024 Form 10-K.

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.

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, 2025 and 2024 were $24,232,000 and $30,409,000, respectively. Funds collected through this program are invested and held until applied to 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, 2025, $175,811,000 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, 2025 and 2024 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 November 30, 2029 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 non-lease components for all lease agreements.


Classification	March 31, 2025		December 31, 2024
	(dollars in thousands)
Right-of-use assets—Finance leases
Right-of-use assets	$	302,732	$	302,732
Less: Accumulated provision for depreciation	(284,735)		(283,417)
Total finance lease assets	$	17,997	$	19,315
Lease liabilities—Finance leases
Obligations under finance leases	$	33,173	$	33,173
Long-term debt and finance leases due within one year	10,413		10,413
Total finance lease liabilities	$	43,586	$	43,586


Classification	March 31, 2025		December 31, 2024
	(dollars in thousands)
Right-of-use assets—Operating leases
Electric plant in service, net	$	7,211	$	7,723
Total operating lease assets	$	7,211	$	7,723
Lease liabilities—Operating leases
Capitalization—Other	$	5,242	$	5,715
Other current liabilities	1,915		1,954
Total operating lease liabilities	$	7,157	$	7,669


		Three Months Ended
Lease Cost	Classification	March 31, 2025		March 31, 2024
		(dollars in thousands)
Finance lease cost:
Amortization of leased assets	Depreciation and amortization	$	2,604	$	2,338
Interest on lease liabilities	Interest expense	1,134		1,400
Operating lease cost:	Inventory(1) & production expense	641		538
Total leased cost		$	4,379	$	4,276

(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, 2025		December 31, 2024
Lease Term and Discount Rate:
Weighted-average remaining lease term (in years)
Finance leases	4.12		4.37
Operating leases	4.82		5.01
Weighted-average discount rate:
Finance leases	11.05	%	11.05	%
Operating leases	6.34	%	6.34	%


	Three Months Ended March 31,
	2025		2024
	(dollars in thousands)
Other Information:
Cash paid for amounts included in the measurement of lease liabilities

Operating cash flows from operating leases	$	641	$	632

Right-of-use assets obtained in exchange for new operating lease liabilities	$	—	$	17

Maturity analysis of our finance and operating lease liabilities as of March 31, 2025 is as follows:


	(dollars in thousands)
Year Ending December 31,	Finance Leases		Operating Leases		Total
2025	$	14,949	$	1,725	$	16,674
2026	14,949		2,096		17,045
2027	14,949		1,819		16,768
2028	3,052		1,709		4,761
2029	3,052		263		3,315
Thereafter	4,579		723		5,302
Total lease payments	$	55,530	$	8,335	$	63,865
Less: imputed interest	(11,944)		(1,178)		(13,122)
Present value of lease liabilities	$	43,586	$	7,157	$	50,743

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, 2025 and 2024 was as follows:


	Three Months Ended March 31,
	2025		2024
	(dollars in thousands)
Lease income	$	1,284	$	1,387

(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.

(I)Restricted Cash and Short-Term 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, 2025		March 31, 2024
	(dollars in thousands)
Cash and cash equivalents	$	234,324	$	327,470

Restricted cash included in restricted cash and short-term investments	15,200		—
Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows	$	249,524	$	327,470

(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.

The following regulatory assets and liabilities are reflected on the consolidated balance sheets as of March 31, 2025 and December 31, 2024.


	(dollars in thousands)
	2025		2024
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	20,978	$	21,587
Amortization of financing leases(b)	23,413		24,699
Outage costs(c)	58,799		45,749
Asset retirement obligations—Ashpond and other(l)	262,791		268,074

Depreciation expense - Plant Vogtle(d)	32,346		32,702
Depreciation expense - Plant Wansley(e)	331,912		337,181
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f)	54,314		54,545
Interest rate options cost(g)	128,755		130,456
Deferral of effects on net margin—TA Smith Energy Facility(h)	123,354		124,840
Deferral of effects on net margin—BC Smith Energy Facility(p)	29,169		27,841
Inventory adjustments - TA Smith Energy Facility(q)	14,467		14,723
Other regulatory assets(o)	25,762		21,236
Total Regulatory Assets	$	1,106,060	$	1,103,633
Regulatory Liabilities:
Accumulated retirement costs for other obligations(i)	$	23,808	$	29,975
Deferral of effects on net margin—Hawk Road Energy Facility(h)	15,250		15,404

Major maintenance reserve(j)	99,196		99,987

Deferred debt service adder(k)	190,629		186,757
Asset retirement obligations—Nuclear(l)	97,064		102,858
Revenue deferral plan(m)	175,811		197,373
Natural gas hedges(n)	59,792		28,624
Other regulatory liabilities(o)	538		614
Total Regulatory Liabilities	$	662,088	$	661,592
Net Regulatory Assets	$	443,972	$	442,041

(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 19 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 rate making 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.

(o)The amortization periods for other regulatory assets range up to 29 years and the amortization periods of other regulatory liabilities range up to 2 years.

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

(q)Represents the write-down of inventory associated with the TA Smith acquisition. Amortization commenced on June 1, 2024 and will end no later than May 31, 2039.

(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 2026.

(L)Debt.

a)Department of Energy Loan Guarantee:

In connection with the development and construction of Vogtle Units No. 3 and No. 4, we and the Department of Energy and the Federal Financing Bank entered into a series of agreements pursuant to which we borrowed $4,633,028,000. As of March 31, 2025, we have repaid $615,072,000 of principal on the notes related to these borrowings and the aggregate Department of Energy-guaranteed borrowings outstanding, including capitalized interest, totaled $4,017,956,000. The final maturity date is February 20, 2044.

b)Rural Utilities Service Guaranteed Loans:

For the three-month period ended March 31, 2025, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $40,398,000 for long-term financing of general and environmental improvements at existing plants.

In April 2025, we received an additional $28,037,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants.

c)Green First Mortgage Bonds:

In January 2025, we issued $350,000,000 of 5.900% green first mortgage bonds, Series 2025A, to provide for long-term financing or refinancing of expenditures related to Vogtle Units No. 3 and No. 4, including refinancing principal payments on our Department of Energy-guaranteed loans that were made prior to Vogtle Unit No. 4's in-service date. In conjunction with the issuance of the bonds, we repaid $254,463,000 of outstanding commercial paper. The bonds are due to mature in February 2055 and are secured under our first mortgage indenture.

d)Pollution Control Revenue Bonds:

In February 2025, we remarketed $312,760,000 of term-rate pollution control revenue bonds that were issued on our behalf by the Development Authorities of Appling, Burke and Monroe Counties which were subject to mandatory tender at that time. This included $272,230,000 of Burke and Monroe bonds which we remarketed as five-year term-rate bonds at a rate of 3.60% through February 2030, and $40,530,000 of Series 2013A Appling bonds, which we converted to a variable weekly rate mode without external credit or liquidity support. In the weekly rate mode, bondholders may tender their bonds for purchase at any time upon at least seven days' notice, and we made an election under these bonds that obligates us to pay the purchase price of the bonds tendered for purchase that are not remarketed. Since the Series 2013A Appling bonds now contain a provision that could accelerate their payment to the current year under certain circumstances, at December 31, 2024, we reclassified these bonds from the Long-term debt line item to the Long-term debt and finance leases due within one year line item within our consolidated balance sheets.

Our obligation to pay the principal and interest on all these pollution control bonds is secured under our first mortgage indenture, and additionally, our obligation to pay the purchase price on the Series 2013A Appling bonds is also secured under our first mortgage indenture.

(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 Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement and contract management.

Georgia Power placed Unit No. 3 in service on July 31, 2023 and 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 727 megawatts of nameplate capacity, as constructed. As of March 31, 2025, our actual costs related to the new Vogtle units were approximately $8.3 billion, net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and approximately $437 million we received from Georgia Power pursuant to the cost-sharing provisions in a settlement agreement with Georgia Power. We estimate that our proportionate share of remaining additional capital costs to be incurred on the project through the end of 2025 to be $10 million to $15 million.

For additional information regarding our participation in Plant Vogtle Units No. 3 and No. 4, see Note 8 in our 2024 Form 10-K.

Plant Vogtle Unit No. 3 and No. 4 Production Tax Credits

For the three months ended March 31, 2025, we sold Georgia Power approximately $24,424,000 of nuclear production tax credits ("NPTCs"), earned by us pursuant to Section 45J of the Internal Revenue Code and recognized the amounts as credits to the Production expense line item within our consolidated statements of revenues and expenses. In 2024 and 2023, since Plant Vogtle Units No. 3 and No. 4 were placed in service, we sold Georgia Power approximately $72,600,000 and $21,700,000, respectively, of nuclear production tax credits.

(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. During the three months ended March 31, 2025, no change in cash flow estimates related to nuclear or coal ash related asset retirement obligations were recorded. We expect to receive more refined estimates from Georgia Power regarding closure costs and the timing of coal ash expenditures in the fourth quarter of 2025.

(P)Natural Gas Capacity Agreements.

We have executed precedent agreements with Southern Natural Gas Company, LLC (SONAT) that became effective in August 2024. The agreements provide for firm natural gas transportation needed to serve our new Smarr combined cycle generation facility and additional firm transportation to our BC Smith Energy Facility. In November 2024, we exercised options to increase the available amounts under the precedent agreements to provide additional natural gas supply to the new Smarr facility. The firm transportation capacity is contingent upon completion of these expansion projects by SONAT. With the exercise of the options noted above, total fixed charges over the 20-year base terms will be approximately $2,100,000,000. Our obligation to make payments begins when the pipeline expansion projects are placed into service, both of which are projected to be November 2028.

In October 2024, we entered into a preliminary binding agreement with Tennessee Gas Pipeline Company, L.L.C. to commit for natural gas capacity for the Mississippi Crossing gas pipeline. This agreement will provide capacity for both existing and future resources. The firm transportation capacity is contingent upon completion of this expansion project. Total fixed charges over the 20-year base term are currently approximately $900,000,000, although may increase to approximately $1,000,000,000 based on changes to the applicable receipt and delivery points as the terms of the agreement are finalized during the second quarter of 2025. Our obligation to make payments begins when the pipeline project is placed into service, which is projected to be November 2028.

In May 2025, we amended our binding agreement with Tennessee Gas Pipeline Company, L.L.C. for the Mississippi Crossing gas pipeline. As a result, total fixed charges for natural gas capacity under this agreement increased from approximately $900,000,000 to approximately $1,000,000,000. Our obligation to make payments begins when the pipeline project is placed into service, which is projected to be November 2028.

(Q)Reportable Segment Information. An operating segment is generally defined as a component of a business for which discrete financial information is available and whose operating results are regularly reviewed by the chief operating decision maker (“CODM”). We report our segment information in the same way that management internally organizes our business for assessing performance and making decisions regarding the allocation of resources in accordance with ASC 280, Segment Reporting. We have one reportable operating segment.

As an electric membership cooperative, our single reportable operating segment is providing wholesale electric service to our members, primarily from our diverse energy portfolio of generation assets. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. Pursuant to our contracts, we primarily provide two services, capacity and energy.

Our Chief Operating Decision Maker is identified as our President and Chief Executive Officer because our CODM has the final authority over performance assessment and resource allocation decisions. Due to our diverse energy portfolio of generation assets, our CODM regularly receives and uses discrete financial information about our single reportable segment in our CODM's performance assessment and resource allocation decisions, predominantly in the budgeting and forecasting process.

Our CODM manages our business on a consolidated basis and uses "net margin" as reported within our consolidated statements of revenues and expenses to allocate resources and assess performance. Segment net margin is determined on the same basis as net margin presented within our consolidated financial statements.

Within our reportable operating segment, there are significant expense categories regularly provided to the CODM and included in the measure of our segment’s net margin. Our reportable segment's significant expenses include fuel expense, production expense, depreciation and amortization and interest expense as reported within our consolidated statements of revenues and expenses and notes to our consolidated financial statements. Our CODM uses these identified significant segment expenses and other segment information, including capacity and energy sales to members and investment income when allocating resources accordingly and assessing performance of all our generating assets to provide environmentally responsible, safe, reliable and affordable electricity to our members.

Other segment expenses are comprised of purchased power, accretion, other income and expense, allowance for debt funds used during construction and amortization of debt discount and expense.

Fuel expense primarily includes nuclear fuel burn, coal inventory burn, natural gas purchases, natural gas transportation charges, and settlement of our natural gas derivatives.

Production expense primarily includes operation and maintenance, major maintenance outage expenses for our generating fleet of assets, and administrative and general expenses.

Depreciation and amortization expense is computed on additions when they are placed in service using the composite straight-line method and considered a significant segment expense as it is a measure of the remaining useful lives of our generating assets.

Interest expense is considered a significant segment expense as we are exposed to the risk of changes in interest rates relating to a portion of our debt.

The accounting policies of our reportable segment are the same as those described in Note 1, Summary of significant accounting policies.

The measure of our segment's assets is reported within our consolidated balance sheets as "total assets". Our segment asset line items, provided to our CODM, are consistent with those reported within our consolidated balance sheets.

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 2024 Form 10-K.

Results of Operations

For the Three Months Ended March 31, 2025 and 2024

Net Margin

Our net margin for the three-month period ended March 31, 2025 was $43.0 million, compared to $42.1 million for the same period of 2024. Through March 31, 2025, we collected approximately 78% of our targeted net margin of $55.5 million for the year ending December 31, 2025. 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 2025 targeted margins for interest ratio of 1.10. 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, 2025. 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 2024 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.

The components of member revenues for the three-month period ended March 31, 2025 and 2024 were as follows:


	Three Months Ended March 31,
	(dollars in thousands)
	2025			2024			% Change
Capacity revenues	$	413,337		$	355,718		16.2	%
Energy revenues	254,964			179,652			41.9	%
Total	$	668,301		$	535,370		24.8	%
MWh Sales to members(1)	7,417,890			6,836,560			8.5	%
Cents/kWh	9.01			7.83			15.0	%
Member energy requirements supplied(1)	67		%	66		%	1.5	%

(1) Excludes test energy megawatt-hours from Plant Vogtle Unit No. 4 supplied to members during the three-month period ended March 31, 2024. Any revenues and costs associated with test energy were capitalized.

Energy revenues from members increased for the three-month period ended March 31, 2025 compared to the same period in 2024, 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, 2025 compared to the same period in 2024, primarily due to the recovery of increased fixed operating expenses, net interest expense and depreciation expense as a result of Plant Vogtle Unit No. 4 being placed in service on April 29, 2024.

Sales to non-members. Sales to non-members during the three-month period ended March 31, 2025 and 2024 were as follows:


	Three Months Ended March 31,
	(dollars in thousands)

	2025		2024		% Change
Energy revenues	$	9,275	$	158	5,770.3	%
Capacity revenues	—		786		(100.0)	%
Total	$	9,275	$	944	882.5	%
MWh Sales to non-members	176,731		5,065		3,389.3	%
Cents/kWh	5.25		18.64		(71.8)	%

Energy revenues from non-members were primarily from the sale of the BC Smith Energy Facility's deferring members' output into the wholesale market. Energy revenues from non-members increased for the three-month period ended March 31, 2025 compared to the same period in 2024 primarily due to an increase in megawatt-hours sold to non-members.

Operating Expenses

Fuel

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


	Cost					Generation			Cents per kWh
	(dollars in thousands)					(MWh)
	Three Months Ended March 31,					Three Months Ended March 31,			Three Months Ended March 31,
Fuel Source	2025		2024		% Change	2025	2024	% Change	2025	2024	% Change
Coal	$	43,413	$	38,534	12.7%	1,197,783	982,397	21.9%	3.62	3.92	(7.6)%
Nuclear1	27,618		23,995		15.1%	3,519,441	3,048,598	15.4%	0.78	0.79	(0.3)%
Gas:
Combined Cycle	157,194		96,841		62.3%	2,969,862	2,934,390	1.2%	5.29	3.30	60.4%
Combustion Turbine	14,422		7,676		87.9%	104,270	86,518	20.5%	13.83	8.87	55.9%
	$	242,647	$	167,046	45.3%	7,791,356	7,051,903	10.5%	3.11	2.37	31.5%

(1) Excludes test energy megawatt-hours generated at Plant Vogtle Unit No. 4 during the three-month period ended March 31, 2024.

Total fuel costs increased for the three-month period ended March 31, 2025 compared to the same period in 2024 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. 4 being placed in service on April 29, 2024. The increase in average fuel cost was primarily due to higher average natural gas prices during the first quarter of 2025 as prices have increased due to supply and demand pressures. Coal-fired generation increased primarily as a result of the higher average natural gas prices, which caused generation from the coal-fired units to be relatively more economical.

Production Expenses

Production costs increased for the three-month period ended March 31, 2025 as compared to the same period of 2024 primarily as a result of $21.9 million in production costs related to Plant Vogtle Units No. 3 and No. 4, net of $24.4 million in credits recognized from the sale of nuclear production tax credits to Georgia Power. This increase was offset by $6.3 million lower fixed major maintenance outage costs associated with our combined cycle plants. 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 compared to the same period of 2023 by $24.6 million primarily as a result of higher production costs related to Plant Vogtle Unit No. 3, net of credits recognized from the sale of nuclear production tax credits to Georgia Power.

Depreciation and Amortization Expenses

Depreciation and amortization increased for the three-month period ended March 31, 2025 as compared to the same period of 2024 primarily as a result of Plant Vogtle Unit No. 4 being placed in service on April 29, 2024.

Interest Charges

Net interest charges increased for the three-month period ended March 31, 2025 as compared to the same period of 2024 as a result of lower capitalized interest expense due to Plant Vogtle Unit No. 4 being placed in service on April 29, 2024.

Financial Condition

Balance Sheet Analysis as of March 31, 2025

Assets

Cash used for property additions for the three-month period ended March 31, 2025 totaled $195.4 million. Of this amount, $40.1 million was for nuclear fuel purchases and $11.1 million was associated with construction expenditures for Vogtle Unit No. 4. The remainder was for expenditures related to normal additions and replacements to our existing generation facilities.

Long-term investments decreased $6.6 million for the three-month period ended March 31, 2025, primarily due to $25.1 million redeemed to fund expenses associated with our revenue deferral rate management plan, which was designed primarily to assist our members in managing the rate impacts associated with the new Vogtle units, and to fund major maintenance outages expenses. Offsetting these decreases was a $18.5 million increase in funds invested, including reinvestment of earnings. See

Notes F and J of Notes to Unaudited Consolidated Financial Statements for a discussion of our member rate management programs and regulatory liabilities.

Restricted cash and short-term investments increased $14.7 million for the three-month period ended March 31, 2025, primarily due to a $14.7 million increase in restricted cash posted by counterparties under our natural gas swap agreements. For additional information regarding restricted cash and short-term investments, see Note I of Notes to Unaudited Consolidated Financial Statements.

Receivables decreased $14.2 million for the three-month period ended March 31, 2025 primarily due to a $31.1 million decrease in Georgia Power receivables primarily related to spent nuclear fuel storage cost litigation receivables. Largely offsetting this decrease was a $7.4 million increase in member receivables and a $5.5 million increase in other non-member receivables.

Prepayments and other current assets increased $44.5 million during the three-month period ended March 31, 2025, primarily due to a $24.1 million increase in the fair value of our natural gas hedges and a $20.2 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 $0.9 million. This was primarily the result of reclassifying $254.5 million of commercial paper, which was classified as long-term debt at December 31, 2024 due to the refinancing of that commercial paper by the issuance of the Series 2025A green first mortgage bonds in January 2025, to short-term borrowings and $133.1 million in debt service payments. Offsetting these decreases was the issuance of $350.0 million of our Series 2025A green first mortgage bonds and $40.4 million in advances under Rural Utilities Service-guaranteed loans. See Note L of Notes to Unaudited Consolidated Financial Statements for additional information regarding long-term debt.

At March 31, 2025, short-term borrowings, which primarily provide interim financing for costs related to the Walton County acquisition, the new Smarr Combined Cycle and Talbot Unit No. 7 projects and the deferral of effects on net margin for BC Smith and the Washington County Power Plant, increased $43.4 million during the three-month period ended March 31, 2025, primarily as a result of borrowings of $46.9 million. At December 31, 2024, short-term borrowings primarily related to interim financing for Vogtle Units No. 3 and No. 4 construction costs.

Accounts payable decreased $73.5 million during the three-month period ended March 31, 2025, primarily due to applying $55.9 million in credits to our members' bills in the first quarter of 2025 for a board-approved reduction in 2024 revenue in excess of the requirement to meet the 2024 targeted net margin and a $12.7 million decrease in Georgia Power payables.

Other current liabilities decreased $22.7 million for the three-month period ended March 31, 2025, primarily as a result of a $35.5 million decrease in accrued property taxes offset by a $14.7 million increase in restricted cash posted by and due to counterparties under our natural gas swap agreements and a $9.2 million increase in operating and maintenance liabilities.

Capital Requirements and Liquidity and Sources of Capital

Other Future Power Resources

As a result of projected load growth in Georgia, we and our members have approved the development and construction of two new natural gas-fired generation resources. One of the projects is an approximately 1,425-megawatt, two-unit combined cycle generation facility to be located on land we own adjacent to the Smarr Energy Facility in Monroe County, Georgia. Our preliminary cost estimate for this facility is approximately $1.8 billion to $2.3 billion and the projected commercial operation date is 2029. We are actively refining our project cost estimates amid ongoing market volatility and anticipate finalizing them by late summer following the completion of a request for proposals (RFP) process for engineering, procurement, and construction services. The other project is an approximately 240-megawatt combustion turbine unit to be constructed at our Talbot Energy Facility. Our preliminary cost estimate for this unit is approximately $360 million and the projected commercial operation date is 2029. In connection with these additional resources, we entered into agreements to provide firm capacity on new natural gas pipeline infrastructure to meet our anticipated fuel supply needs. We and our members have also approved 75 megawatts of utility-scale battery storage resources in connection with an $81 million award under the Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) Program, and the projected commercial operation dates are in 2029 and 2030. Our cost estimate of these battery storage resources is approximately $200 million to $250 million, before the application of any grant proceeds. We and our members may also continue to consider additional generation 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 2024 Form 10-K.

In May 2024, the Environmental Protection Agency published a final rule under Clean Air Act sections 111(b) and 111(d) to limit greenhouse gas emissions from new gas turbines and existing coal plants, respectively. This final rule replaces the Affordable Clean Energy Rule, which was vacated and remanded to EPA in 2021 by the U.S. Court of Appeals for the District of Columbia. As written, the final rule would likely adversely impact a portion of our coal and natural gas-fired generating units and have a significant impact on the U.S. power sector overall. Under the new rule, gas-fired turbines that operate above a 20% capacity factor are required to meet stringent carbon dioxide emissions standards, including adding carbon capture and sequestration (CCS) by January 1, 2032, for baseload units operating above a 40% capacity factor. Exiting coal plants are required to either 1) cease operations by January 1, 2032, with no additional restrictions; 2) co-fire with 40% natural gas by January 1, 2030, and operate to January 1, 2039; or 3) reduce carbon dioxide emissions by 90% using CCS by January 1, 2032, to operate beyond January 1, 2039. However, the Trump administration has issued executive orders, among which include withdrawing from the Paris Climate Agreement and revoking any attendant carbon dioxide emissions goals and commitments, and stated its intention to rescind, revise or replace some existing environmental regulations, which would include regulations for greenhouse gas emissions from power plants. On March 12, 2025, EPA announced that it would reconsider regulations to limit greenhouse gas emissions from power plants. Additionally, EPA's final rule is being challenged in the U.S. Court of Appeals for the District of Columbia, and EPA requested on February 5, 2025, that the court withhold issuing an opinion and hold the case in abeyance for 60 days while EPA determines how it wishes to proceed. EPA's request for a 60-day abeyance was granted on February 19, 2025. On April 25, 2025, the U.S. Court of Appeals for the D.C. Circuit granted EPA's motion requesting a continuing abeyance of the litigation over the greenhouse gas rule EPA issued in 2024. EPA stated in its motion that it will issue a proposed reconsideration rule in spring 2025 and a final reconsideration rule by December 2025. Although we continue to evaluate the impact of EPA's greenhouse gas rule on our power plants, we cannot predict the outcome of any regulatory actions or the result of potential litigation challenging any of these actions.

In May 2024, the EPA published a final supplemental ELG rule, which generally increases the stringency of the wastewater discharge standards. Taken together, the ELG rule revisions are expected to increase capital and operating costs of affected units. However, because of the compliance strategy for Plant Scherer, we do not anticipate significant additional impacts related to more stringent requirements in the supplemental ELG rule. The 2024 supplemental ELG rule is being challenged in federal court and, on February 19, 2025, EPA requested a 60-day abeyance to determine how it wishes to proceed with the litigation. EPA's request for a 60-day abeyance was granted on February 28, 2025. Additionally, certain Trump administration executive orders direct EPA to develop and implement action plans that suspend, revise, or rescind certain environmental regulations. On March 12, 2025, EPA announced that it will reconsider the supplemental ELG rule. We continue to monitor EPA's actions related to ELG; however, the ultimate impact is unknown at this time and subject to the outcome of ongoing litigation and any future EPA regulatory changes.

Liquidity

At March 31, 2025, we had $1.8 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $234 million in cash and cash equivalents, and $1.5 billion available under our $1.7 billion of committed credit arrangements, the details of which are reflected in the table below:


Committed Credit Facilities
	Authorized Amount		Available March 31, 2025		Expiration Date
	(dollars in millions)
Unsecured Facilities:
Syndicated Line among 12 banks led by CFC'(1)	$	1,275	$	1,085	May 2029
CFC Line of Credit(2)	110		110		December 2028
JPMorgan Chase Line of Credit(3)	200		197		March 2027
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, 2025.

(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, 2025, $2.5 million of this facility was used for letters of credit issued to provide performance assurance to third parties.

A portion of our unrestricted available liquidity is allocated to support the $40.5 million Series 2013A Appling pollution control revenue bonds, which bear interest in a weekly variable rate mode and do not have external credit or liquidity support. The holders of these bonds may tender their bonds for purchase upon seven days' notice, and we are obligated to purchase any of these bonds which are tendered for purchase and not remarketed.

We have the flexibility to use the $1.275 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 $1.3 billion syndicated line of credit. At March 31, 2025, our $189 million outstanding commercial paper primarily was used to provide interim funding for:

•costs related to the Walton County Power Plant acquisition,

•costs related to the deferral of effects on net margin of our recently acquired facilities: BC Smith, Baconton Power Plant, two units at the Washington County Power Plant and Walton County Power Plant, and

•costs related to the new Smarr Combined Cycle and Talbot Unit No. 7 projects.

Rural Utilities Service financing is our preferred source of long-term financing for the Walton County acquisition, and for the Smarr Combined Cycle and Talbot Unit No. 7 projects. We intend to issue first mortgage bonds to provide long-term financing for certain other costs, including any costs for the Smarr Combined Cycle and Talbot Unit No. 7 projects not financed by the Rural Utilities Service, and for the deferral of effects on net margin of our recently acquired facilities.

Our unsecured committed lines of credit permit the issuance of up to $810 million in letters of credit on our behalf, of which $807 million remained available at March 31, 2025. This letter of credit issuance capacity includes $500 million under our $1.275 billion syndicated line of credit, $200 million under our JPMorgan Chase line of credit, and $110 million under our CFC line of credit. Between projected cash on hand and the credit arrangements currently in place, we believe we have sufficient liquidity to cover normal operations and our interim financing needs, including interim financing for the new natural gas resources, until long-term financing is obtained.

Three of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At March 31, 2025, the highest required minimum level was $900 million and our actual patronage capital balance was $1.4 billion. Two of these agreements contain an additional covenant that limits our unsecured indebtedness, as defined in the credit agreements, to $4 billion. At March 31, 2025, we had $189.0 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, 2025, we had five members participating in the program and a balance of $83.3 million remaining to be applied against future power bills.

Financing Activities

First Mortgage Indenture. At March 31, 2025, we had $12.6 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 2024 Form 10-K for further discussion of our first mortgage indenture.

Rural Utilities Service-Guaranteed Loans. A summary of our current Rural Utilities Service-Guaranteed Loans as of March 31, 2025 is provided in the table below:


Current Rural Utilities Service-Guaranteed Loans
	Amount Approved		Amount Advanced March 31, 2025		Amount Remaining March 31, 2025
	(dollars in millions)
General and Environmental Improvements1	$	630.3	$	464.6	$	165.7
General and Environmental Improvements2	755.2		223.7		531.5
Washington Acquisition	87.9		87.9		—
Baconton Acquisition	17.5		17.5		—
Total	$	1,490.9	$	793.7	$	697.2

(1) We are able to advance under this loan through September 30, 2026.

(1) We are able to advance under this loan through May 30, 2028.

In February 2025, we received a conditional commitment from the Rural Utilities Service for a guaranteed loan of $80.1 million for our acquisition of the Walton County Power Plant. We expect to close and advance on that loan by 2026.

When advanced, the debt will be secured ratably under our first mortgage indenture. As of March 31, 2025, we had $2.8 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 $4.0 billion was outstanding at March 31, 2025. 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, 2025, we had repaid $615.1 million under these loans. We refinanced a portion of this amount by issuing green first mortgage bonds in June 2024 and January 2025.

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 2024 Form 10-K.

Bond Financings. In January 2025, we issued $350 million of 5.90% green first mortgage bonds, Series 2025A, to provide long-term refinancing of the principal repayments of our Department of Energy-guaranteed loans that occurred before the in-service date of Vogtle Unit No. 4, and for expenditures related to the construction of Vogtle Units No. 3 and No. 4. These bonds are due to mature in February 2055 and are secured under our first mortgage indenture. With this financing, we have substantially completed our long-term funding for Vogtle Units No. 3 and No. 4.

In February 2025, we remarketed $312.8 million of term-rate pollution control revenue bonds that were issued on our behalf by the Development Authorities of Appling, Burke and Monroe Counties which were subject to mandatory tender at that time. This included $272.2 million of Burke and Monroe bonds which we remarketed as five-year term-rate bonds at a rate of 3.60% through February 2030, and $40.5 million of Series 2013A Appling bonds, which we converted to a weekly variable rate mode without external credit or liquidity support. In the weekly rate mode, bondholders may tender their bonds for purchase at any time upon at least seven days' notice, and we made an election under these bonds that obligates us to pay the purchase price of the bonds tendered for purchase that are not remarketed. Since the Series 2013A Appling bonds contain a provision that could accelerate their payment to the current year under certain circumstances, we classify these bonds as Long-term debt and finance leases due within one year line item within our consolidated balance sheets.

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 2024 Form 10-K.

Item 4. Controls and Procedures

As of March 31, 2025, 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, 2025 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

See Note H to Unaudited Consolidated Financial Statements.

Item 1A. Risk Factors

There have been no material changes to the risk factors disclosed in "Item 1A—Risk Factors" in our 2024 Form 10-K.

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

Not Applicable.

Item 3. Defaults upon Senior Securities

Not Applicable.

Item 4. Mine Safety Disclosures

Not Applicable.

Item 5. Other Information

During the fiscal quarter ended March 31, 2025, 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.

Item 6. Exhibits


Number						Description
31.1						Rule 13a-14(a)/15d-14(a) Certification, by Annalisa M. Bloodworth (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 Annalisa M. Bloodworth (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.

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 14, 2025

By:

/s/ Annalisa M. Bloodworth

Annalisa M. Bloodworth
President and Chief Executive Officer

Date:

May 14, 2025

/s/ Elizabeth B. Higgins

Elizabeth B. Higgins
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)

OGLETHORPE POWER CORP 10-Q