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 ~~September 30, 2022~~March 31, 2023

☐ 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.

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OGLETHORPE POWER CORPORATION

INDEX TO QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED ~~SEPTEMBER 30, 2022~~MARCH 31, 2023


		Page No.
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Consolidated Balance Sheets as of ~~September~~ ~~30, 2022~~March 31, 2023 and December 31, ~~2021~~2022	1
	Unaudited Consolidated Statements of Revenues and Expenses For the Three ~~and~~ ~~Nine~~ Months ended ~~September~~Ma rch ~~30, 2022~~3 1 , 202 3 and ~~2021~~202 2	3
	Unaudited Consolidated Statements of Patronage Capital and Membership Fees For the Three ~~and~~ ~~Nine~~Months ended ~~September~~March ~~30, 2022~~3 1 , 202 3 and ~~2021~~202 2	4
	Unaudited Consolidated Statements of Cash Flows For the ~~Nine~~Three Months ended ~~September~~March ~~30, 2022~~3 1 , 202 3 and ~~2021~~202 2	5
	Notes to Unaudited Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2726
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3835
Item 4.	Controls and Procedures	3835
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	3836
Item 1A.	Risk Factors	3836
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3836
Item 3.	Defaults Upon Senior Securities	3836
Item 4.	Mine Safety Disclosures	3836
Item 5.	Other Information	3836
Item 6.	Exhibits	4037
SIGNATURES		4138

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CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING ~~STATEMENTS~~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, ~~2021~~2022 and in this quarterly report on Form 10-Q. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this quarterly report may not occur.

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

•cost increases and schedule delays with respect to our capital improvement and construction projects, such as, the construction of two additional nuclear units at Plant Vogtle and closure of coal ash ponds;

•the resolution of any disputes between two or more of the Vogtle co-owners, including the current litigation regarding certain cost-mitigation provisions under the ownership participation agreement;

•the duration and severity of subsequent waves of the coronavirus ("COVID-19") pandemic and resulting economic disruption and its impact on our business, financial condition, operations, construction projects, including the additional units at Plant Vogtle, and our members and their service territories;

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

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

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

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

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

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

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

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

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•the continued availability of funding from the Rural Utilities Service;

•increasing debt caused by significant capital expenditures;

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

•actions by credit rating agencies;

•commercial banking and financial market conditions;

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

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

•early retirement of our co-owned coal facilities;

•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;

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

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

•future variants of the current coronavirus ("COVID-19") and any resulting economic disruption and its impact on our business, financial condition, operations, construction projects, including the additional units at Plant Vogtle, and our members and their service territories;

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

•our members' ability to perform their obligations to us;

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

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

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

•general economic conditions;

•weather conditions and other natural phenomena;

•litigation or legal and administrative proceedings and settlements;

•unanticipated changes in interest rates or rates of inflation;

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

•significant changes in critical accounting policies material to us;

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

~~iii~~

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

iii

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

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements


Oglethorpe Power Corporation Consolidated Balance Sheets (Unaudited) ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022


		(dollars in thousands)					(dollars in thousands)
		2022		2021			2023		2022
Assets	Assets					Assets
Electric plant:	Electric plant:					Electric plant:
In service	In service	$	9,114,953	$	9,865,660	In service	$	9,389,367	$	9,266,627
Right-of-use assets—finance leases	Right-of-use assets—finance leases	302,732		302,732		Right-of-use assets—finance leases	302,732		302,732
Less: Accumulated provision for depreciation	Less: Accumulated provision for depreciation	(5,076,478)		(5,565,724)		Less: Accumulated provision for depreciation	(5,230,497)		(5,183,589)
Electric plant in service, net	Electric plant in service, net	4,341,207		4,602,668		Electric plant in service, net	4,461,602		4,385,770

Nuclear fuel, at amortized cost	Nuclear fuel, at amortized cost	382,933		375,267		Nuclear fuel, at amortized cost	392,621		388,303
Construction work in progress	Construction work in progress	7,457,488		6,779,392		Construction work in progress	7,885,910		7,716,035
Total electric plant	Total electric plant	12,181,628		11,757,327		Total electric plant	12,740,133		12,490,108

Investments and funds:	Investments and funds:					Investments and funds:
Nuclear decommissioning trust fund	Nuclear decommissioning trust fund	503,452		659,910		Nuclear decommissioning trust fund	574,121		540,716
Investment in associated companies	Investment in associated companies	76,096		75,826		Investment in associated companies	77,750		78,937
Long-term investments	Long-term investments	630,411		711,379		Long-term investments	666,010		669,479
Restricted investments		—		73,702

Other	Other	33,330		31,991		Other	33,032		32,561
Total investments and funds	Total investments and funds	1,243,289		1,552,808		Total investments and funds	1,350,913		1,321,693

Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	572,828		579,350		Cash and cash equivalents	390,821		595,381
Restricted cash and short-term investments	Restricted cash and short-term investments	141,226		248,150		Restricted cash and short-term investments	16,000		104,431
Short-term investments	Short-term investments	52,061		—		Short-term investments	76,064		61,702
Receivables	Receivables	235,656		159,538		Receivables	163,909		220,015
Inventories, at average cost	Inventories, at average cost	270,994		260,526		Inventories, at average cost	315,715		297,951
Prepayments and other current assets	Prepayments and other current assets	99,719		60,486		Prepayments and other current assets	16,064		51,409
Total current assets	Total current assets	1,372,484		1,308,050		Total current assets	978,573		1,330,889

Deferred charges and other assets:	Deferred charges and other assets:					Deferred charges and other assets:
Regulatory assets	Regulatory assets	1,314,464		1,008,790		Regulatory assets	1,214,977		1,212,305
Prepayments to Georgia Power Company	Prepayments to Georgia Power Company	19,371		27,124		Prepayments to Georgia Power Company	13,441		20,873
Other	Other	136,192		52,927		Other	81,153		113,502
Total deferred charges	Total deferred charges	1,470,027		1,088,841		Total deferred charges	1,309,571		1,346,680
Total assets	Total assets	$	16,267,428	$	15,707,026	Total assets	$	16,379,190	$	16,489,370

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

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Oglethorpe Power Corporation Consolidated Balance Sheets (Unaudited) ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022


		(dollars in thousands)					(dollars in thousands)

		2022		2021			2023		2022
Equity and Liabilities	Equity and Liabilities					Equity and Liabilities

Capitalization:	Capitalization:					Capitalization:
Patronage capital and membership fees	Patronage capital and membership fees	$	1,202,667	$	1,130,423	Patronage capital and membership fees	$	1,216,537	$	1,192,127
Long-term debt	Long-term debt	11,005,830		10,529,449		Long-term debt	11,392,980		11,512,513
Obligation under finance leases	Obligation under finance leases	57,249		61,335		Obligation under finance leases	52,937		52,937
Obligation under Rocky Mountain transactions						Obligation under Rocky Mountain transactions	28,416		27,945
Other	Other	28,449		27,701		Other	1,961		2,256
Total capitalization	Total capitalization	12,294,195		11,748,908		Total capitalization	12,692,831		12,787,778

Current liabilities:	Current liabilities:					Current liabilities:
Long-term debt and finance leases due within one year	Long-term debt and finance leases due within one year	243,585		281,238		Long-term debt and finance leases due within one year	320,331		322,102
Short-term borrowings	Short-term borrowings	924,661		1,095,971		Short-term borrowings	813,025		655,650
Accounts payable	Accounts payable	192,644		182,164		Accounts payable	82,251		203,705
Accrued interest	Accrued interest	89,845		96,410		Accrued interest	92,343		105,452
Member power bill prepayments, current	Member power bill prepayments, current	46,635		26,102		Member power bill prepayments, current	49,154		54,443
Other current liabilities	Other current liabilities	144,422		36,123		Other current liabilities	92,073		153,941
Total current liabilities	Total current liabilities	1,641,792		1,718,008		Total current liabilities	1,449,177		1,495,293

Deferred credits and other liabilities:	Deferred credits and other liabilities:					Deferred credits and other liabilities:
Asset retirement obligations	Asset retirement obligations	1,388,708		1,287,143		Asset retirement obligations	1,444,558		1,343,743
Member power bill prepayments, non-current	Member power bill prepayments, non-current	46,621		80,001		Member power bill prepayments, non-current	58,177		53,877
Regulatory liabilities	Regulatory liabilities	873,549		849,449		Regulatory liabilities	718,276		792,190
Other	Other	22,563		23,517		Other	16,171		16,489
Total deferred credits and other liabilities	Total deferred credits and other liabilities	2,331,441		2,240,110		Total deferred credits and other liabilities	2,237,182		2,206,299
Total equity and liabilities	Total equity and liabilities	$	16,267,428	$	15,707,026	Total equity and liabilities	$	16,379,190	$	16,489,370

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

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Oglethorpe Power Corporation Consolidated Statements of Revenues and Expenses (Unaudited) For the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2023 and 2022 ~~and 2021~~


		(dollars in thousands)								(dollars in thousands)

		Three Months				Nine Months					Three Months
		2022		2021		2022		2021					2023		2022
Operating revenues:	Operating revenues:											Operating revenues:
Sales to members	Sales to members	$	627,130	$	437,240	$	1,523,361	$	1,171,433			Sales to members	$	387,653	$	417,449
Sales to non-members	Sales to non-members	77,135		23,582		134,474		23,847				Sales to non-members	1,800		2,993
Total operating revenues	Total operating revenues	704,265		460,822		1,657,835		1,195,280				Total operating revenues	389,453		420,442
Operating expenses:	Operating expenses:											Operating expenses:
Fuel	Fuel	419,218		214,681		847,823		436,277				Fuel	133,168		165,484
Production	Production	114,167		99,321		323,334		298,171				Production	93,467		95,780
Depreciation and amortization	Depreciation and amortization	70,926		69,758		212,682		204,654				Depreciation and amortization	72,674		70,926
Purchased power	Purchased power	21,383		16,920		55,919		50,706				Purchased power	17,630		16,875
Accretion	Accretion	14,018		14,117		41,410		41,839				Accretion	15,508		13,532
Total operating expenses	Total operating expenses	639,712		414,797		1,481,168		1,031,647				Total operating expenses	332,447		362,597
Operating margin	Operating margin	64,553		46,025		176,667		163,633				Operating margin	57,006		57,845

Other income:	Other income:											Other income:
Investment income	Investment income	15,090		12,299		39,762		36,389				Investment income	16,382		11,847

Other	Other	3,385		2,516		9,510		4,964				Other	2,925		3,030
Total other income	Total other income	18,475		14,815		49,272		41,353				Total other income	19,307		14,877

Interest charges:	Interest charges:											Interest charges:
Interest expense	Interest expense	117,018		105,201		333,282		312,927				Interest expense	123,707		104,669
Allowance for debt funds used during construction	Allowance for debt funds used during construction	(69,031)		(56,179)		(188,301)		(164,628)				Allowance for debt funds used during construction	(74,430)		(56,773)
Amortization of debt discount and expense	Amortization of debt discount and expense	2,944		2,911		8,714		8,677				Amortization of debt discount and expense	2,626		2,846
Net interest charges	Net interest charges	50,931		51,933		153,695		156,976				Net interest charges	51,903		50,742
Net margin	Net margin	$	32,097	$	8,907	$	72,244	$	48,010			Net margin	$	24,410	$	21,980

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

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Oglethorpe Power Corporation Consolidated Statements of Patronage Capital and Membership Fees (Unaudited) For the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2023 and 2022 ~~and 2021~~


	(dollars in thousands)
~~Balance at December 31, 2020~~	$	~~1,072,642~~
~~Net margin~~	~~25,958~~
~~Balance at March 31, 2021~~	$	~~1,098,600~~
~~Net margin~~	~~13,145~~
~~Balance at June 30, 2021~~	$	~~1,111,745~~
~~Net margin~~	~~8,907~~
~~Balance at September 30, 2021~~	$	~~1,120,652~~
Balance at December 31, 2021	$	1,130,423
Net margin	21,980
Balance at March 31, 2022	$	1,152,403
~~Net margin~~	~~18,167~~



Balance at ~~June 30,~~December 31, 2022	$	~~1,170,570~~1,192,127
Net margin	~~32,097~~24,410




Balance at ~~September 30, 2022~~March 31, 2023	$	~~1,202,667~~1,216,537

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

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Oglethorpe Power Corporation Consolidated Statements of Cash Flows (Unaudited) For the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2023 and 2022 ~~and 2021~~


		(dollars in thousands)					(dollars in thousands)
		2022		2021			2023		2022
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net margin	Net margin	$	72,244	$	48,010	Net margin	$	24,410	$	21,980
Adjustments to reconcile net margin to net cash provided by operating activities:	Adjustments to reconcile net margin to net cash provided by operating activities:					Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	Depreciation and amortization, including nuclear fuel	333,245		297,976		Depreciation and amortization, including nuclear fuel	66,365		92,211
Accretion cost	Accretion cost	41,410		41,839		Accretion cost	15,508		13,532
Amortization of deferred gains	Amortization of deferred gains	(1,341)		(1,341)		Amortization of deferred gains	(447)		(447)
Allowance for equity funds used during construction	Allowance for equity funds used during construction	(460)		(267)		Allowance for equity funds used during construction	(149)		(135)
Deferred outage costs	Deferred outage costs	(26,712)		(27,163)		Deferred outage costs	(21,198)		(22,228)
Loss (gain) on sale of investments		21,077		(11,665)
Loss on sale of investments						Loss on sale of investments	1,289		8,271

Regulatory deferral of costs associated with nuclear decommissioning	Regulatory deferral of costs associated with nuclear decommissioning	(45,229)		(15,592)		Regulatory deferral of costs associated with nuclear decommissioning	(8,519)		(14,694)
Other	Other	2,352		(639)		Other	(863)		974
Change in operating assets and liabilities:	Change in operating assets and liabilities:					Change in operating assets and liabilities:
Receivables	Receivables	(84,191)		(51,283)		Receivables	49,887		(8,620)
Inventories	Inventories	(10,312)		46,686		Inventories	(17,711)		(715)
Prepayments and other current assets	Prepayments and other current assets	8,859		(6,199)		Prepayments and other current assets	4,027		5,954
Accounts payable	Accounts payable	29,464		(4,487)		Accounts payable	(116,354)		(78,836)
Accrued interest	Accrued interest	(6,565)		5,842		Accrued interest	(13,109)		(18,662)
Accrued taxes	Accrued taxes	51,394		6,788		Accrued taxes	(36,722)		16,180
Other current liabilities	Other current liabilities	47,369		522		Other current liabilities	(26,841)		29,836
Member power bill prepayments	Member power bill prepayments	(12,847)		(31,482)		Member power bill prepayments	(989)		(7,988)
Rate management program collections, net	Rate management program collections, net	16,904		117,600		Rate management program collections, net	(9,494)		11,017
Total adjustments	Total adjustments	364,417		367,135		Total adjustments	(115,320)		25,650
Net cash provided by operating activities		436,661		415,145
Net cash (used in) provided by operating activities						Net cash (used in) provided by operating activities	(90,910)		47,630
Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Property additions	Property additions	(872,551)		(891,162)		Property additions	(259,123)		(280,364)
Plant acquisition		—		(233,156)

Activity in nuclear decommissioning trust fund—Purchases	Activity in nuclear decommissioning trust fund—Purchases	(201,721)		(556,879)		Activity in nuclear decommissioning trust fund—Purchases	(2,500)		(195,038)
—Proceeds	—Proceeds	196,136		550,956		—Proceeds	283		192,858

Decrease in restricted investments	Decrease in restricted investments	246,427		167,607		Decrease in restricted investments	74,031		123,232
Activity in other long-term investments—Purchases	Activity in other long-term investments—Purchases	(144,843)		(340,877)		Activity in other long-term investments—Purchases	(63,505)		(111,490)
—Proceeds	—Proceeds	103,024		184,083		—Proceeds	68,226		94,279
Other	Other	5,569		8,139		Other	8,153		(3,718)
Net cash used in investing activities	Net cash used in investing activities	(667,959)		(1,111,289)		Net cash used in investing activities	(174,435)		(180,241)
Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:
Long-term debt proceeds	Long-term debt proceeds	803,032		517,524		Long-term debt proceeds	15,431		102,185
Long-term debt payments	Long-term debt payments	(365,104)		(440,548)		Long-term debt payments	(137,732)		(115,168)
(Decrease) increase in short-term borrowings, net		(171,310)		639,876
Increase in short-term borrowings, net						Increase in short-term borrowings, net	157,375		60,501
Other	Other	23,958		30,124		Other	11,311		10,496
Net cash provided by financing activities	Net cash provided by financing activities	290,576		746,976		Net cash provided by financing activities	46,385		58,014
Net increase in cash, cash equivalents and restricted cash		59,278		50,832
Net decrease in cash, cash equivalents and restricted cash						Net decrease in cash, cash equivalents and restricted cash	(218,960)		(74,597)
Cash, cash equivalents and restricted cash at beginning of period	Cash, cash equivalents and restricted cash at beginning of period	581,150		405,511		Cash, cash equivalents and restricted cash at beginning of period	625,781		581,150
Cash, cash equivalents and restricted cash at end of period	Cash, cash equivalents and restricted cash at end of period	$	640,428	$	456,343	Cash, cash equivalents and restricted cash at end of period	$	406,821	$	506,553
Supplemental cash flow information:	Supplemental cash flow information:					Supplemental cash flow information:
Cash paid for—	Cash paid for—					Cash paid for—
Interest (net of amounts capitalized)	Interest (net of amounts capitalized)	$	150,208	$	141,206	Interest (net of amounts capitalized)	$	61,915	$	66,117
Supplemental disclosure of non-cash investing and financing activities:	Supplemental disclosure of non-cash investing and financing activities:					Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	Change in asset retirement obligations	$	66,716	$	42,964	Change in asset retirement obligations	$	87,509	$	—
Accrued property additions at end of period	Accrued property additions at end of period	$	45,926	$	71,443	Accrued property additions at end of period	$	69,557	$	21,469

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

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Oglethorpe Power Corporation

Notes to Unaudited Consolidated Financial Statements

(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 ~~and nine-month~~ periods ended ~~September 30, 2022~~March 31, 2023 and ~~2021.~~2022. Examples of estimates used include items related to (i) our asset retirement obligations, such as closure and post-closure cost estimates, timing of expenditures, escalation factors and discount rates, and (ii) ~~revenue recognition,~~depreciation rates, such as determining the ~~nature~~depreciable service lives and ~~timing of satisfaction of performance obligations, determining the standalone selling price of performance obligations and variable consideration.~~net salvage value. Actual results may differ from those estimates. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. ~~Certain prior year amounts have been reclassified to conform with current year presentation.~~

These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2021,~~2022, as filed with the SEC. The results of operations for the three-month ~~and nine-month periods~~period ended ~~September 30, 2022~~March 31, 2023 are not necessarily indicative of results to be expected for the full year. As noted in our ~~2021~~2022 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 ~~2021~~2022 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.

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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.

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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 ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021.~~2022.


		Fair Value Measurements at Reporting Date Using									Fair Value Measurements at Reporting Date Using
				Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs					Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
		September 30, 2022		(Level 1)		(Level 2)		(Level 3)			March 31, 2023		(Level 1)		(Level 2)		(Level 3)
		(dollars in thousands)									(dollars in thousands)
Nuclear decommissioning trust funds:	Nuclear decommissioning trust funds:									Nuclear decommissioning trust funds:
Domestic equity	Domestic equity	$	189,706	$	189,706	$	—	$	—	Domestic equity	$	219,406	$	219,406	$	—	$	—
International equity trust	International equity trust	97,294		—		97,294		—		International equity trust	120,518		—		120,518		—
Corporate bonds and debt	Corporate bonds and debt	63,283		—		63,283		—		Corporate bonds and debt	64,323		—		64,294		29
US Treasury securities	US Treasury securities	44,191		44,191		—		—		US Treasury securities	50,233		50,233		—		—
Mortgage backed securities	Mortgage backed securities	38,779		—		38,779		—		Mortgage backed securities	42,029		—		42,029		—
Domestic mutual funds	Domestic mutual funds	52,740		52,740		—		—		Domestic mutual funds	60,724		60,724		—		—

Federal agency securities	Federal agency securities	2,958		—		2,958		—		Federal agency securities	4,243		—		4,243		—
International mutual funds										International mutual funds	698		—		698		—
Non-US Gov't bonds & private placements	Non-US Gov't bonds & private placements	2,842		—		2,842		—		Non-US Gov't bonds & private placements	2,760		—		2,760		—
Other	Other	11,659		11,659		—		—		Other	9,187		9,187		—		—
Long-term investments:	Long-term investments:									Long-term investments:
International equity trust	International equity trust	29,375		—		29,375		—		International equity trust	37,645		—		37,645		—
Corporate bonds and debt	Corporate bonds and debt	13,444		—		13,346		98		Corporate bonds and debt	20,467		—		20,467		—
US Treasury securities	US Treasury securities	11,141		11,141		—		—		US Treasury securities	16,322		16,322		—		—
Mortgage backed securities	Mortgage backed securities	12,725		—		12,725		—		Mortgage backed securities	2,445		—		2,445		—
Domestic mutual funds	Domestic mutual funds	264,413		264,413		—		—		Domestic mutual funds	315,433		315,433		—		—

Treasury STRIPS	Treasury STRIPS	297,346		—		297,346		—		Treasury STRIPS	271,338		—		271,338		—
Non-US Gov't bonds & private placements	Non-US Gov't bonds & private placements	1,886		—		1,886		—		Non-US Gov't bonds & private placements	1,960		—		1,960		—
Other	Other	81		81		—		—		Other	400		400		—		—
Short-term investments: Treasury STRIPS	Short-term investments: Treasury STRIPS	52,061		—		52,061		—		Short-term investments: Treasury STRIPS	76,064		—		76,064		—
Natural gas swaps	Natural gas swaps	192,026		—		192,026		—		Natural gas swaps	64,584		—		64,584		—

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		Fair Value Measurements at Reporting Date Using									Fair Value Measurements at Reporting Date Using
				Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs					Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
		December 31, 2021		(Level 1)		(Level 2)		(Level 3)			December 31, 2022		(Level 1)		(Level 2)		(Level 3)
		(dollars in thousands)									(dollars in thousands)
Nuclear decommissioning trust funds:	Nuclear decommissioning trust funds:									Nuclear decommissioning trust funds:
Domestic equity	Domestic equity	$	249,999	$	249,999	$	—	$	—	Domestic equity	$	204,129	$	204,129	$	—	$	—
International equity trust	International equity trust	140,718		—		140,718		—		International equity trust	111,266		—		111,266		—
Corporate bonds and debt	Corporate bonds and debt	72,936		—		72,369		567		Corporate bonds and debt	60,806		—		60,788		18
US Treasury securities	US Treasury securities	53,321		53,321		—		—		US Treasury securities	49,775		49,775		—		—
Mortgage backed securities	Mortgage backed securities	40,460		—		40,460		—		Mortgage backed securities	41,210		—		41,210		—
Domestic mutual funds	Domestic mutual funds	75,384		75,384		—		—		Domestic mutual funds	57,348		57,348		—		—
Municipal bonds		1,133		—		1,133		—

Federal agency securities	Federal agency securities	9,608		—		9,608		—		Federal agency securities	2,037		—		2,037		—
Non-US Gov't bonds & private placements										Non-US Gov't bonds & private placements	2,890		—		2,890		—
International mutual funds										International mutual funds	653		—		653		—
Other	Other	16,351		13,623		2,728		—		Other	10,602		10,602		—		—
Long-term investments:	Long-term investments:									Long-term investments:
International equity trust	International equity trust	35,873		—		35,873		—		International equity trust	33,606		—		33,606		—
Corporate bonds and debt	Corporate bonds and debt	14,022		—		12,656		1,366		Corporate bonds and debt	10,473		—		10,473		—
US Treasury securities	US Treasury securities	15,259		15,259		—		—		US Treasury securities	15,488		15,488		—		—
Mortgage backed securities	Mortgage backed securities	12,021		—		12,021		—		Mortgage backed securities	12,113		—		12,113		—
Domestic mutual funds	Domestic mutual funds	277,937		277,937		—		—		Domestic mutual funds	302,302		302,302		—		—
Federal agency securities		257		—		257		—

Treasury STRIPS	Treasury STRIPS	350,532		—		350,532		—		Treasury STRIPS	293,281		—		293,281		—
Non-US Gov't bonds & private placements										Non-US Gov't bonds & private placements	1,976		—		1,976		—
Other	Other	5,478		5,478		—		—		Other	240		240		—		—
Short-term investments: Treasury STRIPS										Short-term investments: Treasury STRIPS	61,702		—		61,702		—
Natural gas swaps	Natural gas swaps	63,994		—		63,994		—		Natural gas swaps	131,804		—		131,804		—

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

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

The estimated fair values of our long-term debt, including current maturities at ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 were as follows:
2022 2021
Carrying
Value Fair
Value Carrying
Value Fair
Value
(in thousands)
Long-term debt $ 11,356,651 $ 9,585,512 $ 10,915,054 $ 12,741,046


	2023				2022
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	11,818,058	$	10,618,552	$	11,940,359	$	10,194,954

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

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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

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Financing Bank are based on U.S. Treasury rates as of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 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. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account and the carrying amount of these investments approximates fair value because of the liquid nature of the deposits with the U.S. Treasury.

(C)Derivative Instruments. We use commodity 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 ~~September 30, 2022,~~March 31, 2023, 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 ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, the estimated fair values of our natural gas contracts were net assets of approximately ~~$192,026,000~~$64,584,000 and ~~$63,994,000,~~$131,804,000, respectively.

~~As of September 30, 2022, three of our counterparties were required to post credit collateral totaling $67,600,000 under our natural gas swap agreements. As of~~At March 31, 2023 and December 31, ~~2021,~~2022, one of our counterparties was required to post credit collateral totaling ~~$1,800,000~~$16,000,000 and $30,400,000, 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 ~~items~~item within our unaudited consolidated balance sheets.

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The following table reflects the notional volume of our natural gas derivatives as of ~~September 30, 2022~~March 31, 2023 that is expected to settle or mature each year:


Year	Year	Natural Gas Swaps (MMBTUs) (in millions)	Year	Natural Gas Swaps (MMBTUs) (in millions)
2022		5.0
2023	2023	31.0	2023	30.3
2024	2024	27.4	2024	30.4
2025	2025	23.2	2025	24.9
2026	2026	18.2	2026	19.9
2027	2027	6.0	2027	7.6

Total	Total	110.8	Total	113.1

The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021.~~2022.


		Balance Sheet Location	Fair Value					Balance Sheet Location	Fair Value
			2022		2021				2023		2022
			(dollars in thousands)						(dollars in thousands)
Assets:	Assets:						Assets:
Natural gas swaps	Natural gas swaps	Other current assets	$	67,839	$	23,596	Natural gas swaps	Other current assets	$	3,966	$	35,285
Natural gas swaps	Natural gas swaps	Other deferred charges	$	126,729	$	40,398	Natural gas swaps	Other deferred charges	$	68,232	$	99,725

Liabilities:	Liabilities:						Liabilities:
Natural gas swaps	Natural gas swaps	Other current liabilities	$	2,542	$	—	Natural gas swaps	Other current liabilities	$	7,614	$	3,206
Natural gas swaps	Natural gas swaps	Other deferred credits	$	—	$	—	Natural gas swaps	Other deferred credits	$	—	$	—

The following table presents the gross realized gains and (losses) on derivative instruments recognized in net margins for the three ~~and nine~~ months ended ~~September 30, 2022~~March 31, 2023 and ~~2021.~~2022.


		Statement of Revenues and Expenses Location	Three Months Ended September 30,				Nine Months Ended September 30,				Statement of Revenues and Expenses Location	Three Months Ended March 31,
			2022		2021		2022		2021						2023		2022
			(dollars in thousands)								(dollars in thousands)
Natural gas swaps gains	Natural gas swaps gains	Fuel	$	57,639	$	15,831	$	108,280	$	18,229			Natural gas swaps gains	Fuel	$	135	$	8,078
Natural gas swaps losses	Natural gas swaps losses	Fuel	(2,995)		—		(3,277)		(1,311)				Natural gas swaps losses	Fuel	(9,397)		(79)
Total	Total		$	54,644	$	15,831	$	105,003	$	16,918			Total		$	(9,262)	$	7,999

The following table presents the unrealized gains on derivative instruments deferred on the balance sheet at ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021.~~2022.


		Balance Sheet Location	2022		2021			Balance Sheet Location	2023		2022
			(dollars in thousands)						(dollars in thousands)
Natural gas swaps	Natural gas swaps	Regulatory liability	$	192,026	$	63,994	Natural gas swaps	Regulatory liability	$	64,584	$	131,804
Total	Total		$	192,026	$	63,994	Total		$	64,584	$	131,804

(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.

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The following tables summarize debt and equity securities as of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021.~~2022.


		Gross Unrealized									Gross Unrealized
		(dollars in thousands)									(dollars in thousands)
September 30, 2022		Cost		Gains		Losses		Fair Value
March 31, 2023										March 31, 2023	Cost		Gains		Losses		Fair Value
Equity	Equity	$	315,378	$	121,785	$	(8,879)	$	428,284	Equity	$	324,488	$	191,858	$	(7,030)	$	509,316
Debt	Debt	799,133		298		(53,665)		745,766		Debt	830,095		1,698		(34,803)		796,990
Other	Other	11,853		66		(45)		11,874		Other	9,885		30		(26)		9,889
Total	Total	$	1,126,364	$	122,149	$	(62,589)	$	1,185,924	Total	$	1,164,468	$	193,586	$	(41,859)	$	1,316,195


		Gross Unrealized									Gross Unrealized
		(dollars in thousands)									(dollars in thousands)
December 31, 2021		Cost		Gains		Losses		Fair Value
December 31, 2022										December 31, 2022	Cost		Gains		Losses		Fair Value
Equity	Equity	$	304,305	$	280,127	$	(4,682)	$	579,750	Equity	$	323,907	$	159,445	$	(8,949)	$	474,403
Debt	Debt	774,580		4,859		(7,001)		772,438		Debt	833,035		372		(46,369)		787,038
Other	Other	19,102		—		(1)		19,101		Other	10,445		20		(9)		10,456
Total	Total	$	1,097,987	$	284,986	$	(11,684)	$	1,371,289	Total	$	1,167,387	$	159,837	$	(55,327)	$	1,271,897

(E)Recently Issued or Adopted Accounting Pronouncements. InAs of March ~~2020,~~31, 2023, we have implemented all applicable new accounting standards and updates issued by the Financial Accounting Standards Board (FASB) ~~issued “Reference Rate Reform (Topic 848): Facilitation of~~that were in effect. There were no applicable standards or updates during the ~~Effects of Reference Rate Reform on Financial Reporting”. The amendments in this update apply to all entities~~three months ended March 31, 2023 that have contracts, hedging relationships, and other transactions that reference London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of reference rate reform. The amendments in this update provide optional expedients and exceptions for applying U.S. GAAP to transactions affected by reference rate reform if certain criteria are met. The expedients and exceptions provided by the amendments in this update do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022, except for hedging relationships existing as of December 31, 2022, for which an entity has elected certain optional expedients that are retained through the end of the hedging relationship.

In January 2021, the FASB issued “Reference Rate Reform (Topic 848): Scope,” to further clarify the scope of the reference rate reform guidance in Topic 848. The amendments in this update refine the scope of Topic 848 to clarify that certain optional expedients and exceptions therein for contract modifications and hedge accounting apply to contracts that are affected by the discounting transition. Specifically, modifications related to reference rate reform would not be considered an event that requires reassessment of previous accounting conclusions. The amendments in this update also amend the expedients and exceptions in Topic 848 to capture the incremental consequences of the scope clarification and to tailor the existing guidance to derivative instruments affected by the discounting transition.

The amendments in these updates are effective for all entities as of March 12, 2020 through December 31, 2022. We have fully completed our evaluation of this new standard and we do not expect this standard will havehad a material impact 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. These contracts, which extend to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. We also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments.

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

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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 ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, we did not have any 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

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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 ~~if any,~~ are ~~typically~~ billed and recognized in ~~equal monthly installments over~~accordance with the ~~term~~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. For the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2023 and 2022, ~~and 2021,~~ we provided approximately ~~62%~~64% and ~~61%~~57% of our members' energy requirements, respectively. 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 ~~2022,~~2023, our board has approved a targeted margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity 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 ~~September 30,~~March 31, 2023, we did not recognize a refund liability. As of December 31, 2022, ~~and September 30, 2021,~~ we recognized refund liabilities totaling ~~$9,022,000 and $16,500,000, respectively.~~$28,471,000. 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, 2023 and 2022 were as follows:


	Three Months Ended March 31,
	(dollars in thousands)

	2023			2022
Capacity revenues	$	242,043		$	243,291
Energy revenues	145,610			174,158
Total	$	387,653		$	417,449
Member energy requirements supplied	64		%	57		%

Receivables from contracts with our members at March 31, 2023 and December 31, 2022 were $126,448,000 and $187,401,000, respectively.

Sales to non-members during the three months ended March 31, 2023 and 2022 were as follows:

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~~Sales to members for the three and nine months ended September 30, 2022 and 2021 were as follows:~~


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
		(dollars in thousands)												(dollars in thousands)
																	2023		2022
		2022			2021			2022			2021
Energy revenues																Energy revenues	$	1,037	$	2,993
Capacity revenues	Capacity revenues	$	243,860		$	228,048		$	728,992		$	716,303				Capacity revenues	763		—
Energy revenues		383,270			209,192			794,369			455,130
Total	Total	$	627,130		$	437,240		$	1,523,361		$	1,171,433				Total	$	1,800	$	2,993
Member energy requirements supplied		68		%	65		%	62		%	61		%

Receivables from ~~contracts~~the sale of electricity to non-members were $820,000 at March 31, 2023 and $8,787,000 at December 31, 2022 and are primarily from the sale of the Effingham deferring members’ output. The remainder of our receivables is primarily related to transactions with ~~our members~~affiliated companies and investment income which were $35,867,000 and $13,834,000 at ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021 were $188,951,000 and $143,715,000, respectively.~~

~~Sales to non-members during the three and nine months ended September 30,~~ 2022, ~~and 2021 were as follows:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
(dollars in thousands)
2022 2021 2022 2021
Energy revenues $ 77,135 $ 23,582 $ 134,474 $ 23,847

~~Receivables from non-member energy sales at September 30, 2022 and December 31, 2021 were $18,534,000 and $302,000,~~ respectively.

Energy revenues from non-members for the three ~~and nine~~ months ended ~~September 30, 2022~~March 31, 2023 were primarily from the sale of ~~a portion of~~ the ~~energy~~Effingham deferring members' output ~~at Effingham, which we acquired in July 2021,~~ into the wholesale market. For the three months ended March 31, 2023, we recognized capacity revenues from non-members related to our Washington County acquisition in December 2022. For additional information regarding the ~~Effingham~~Washington County acquisition, see Note 1314 in our ~~2021~~2022 Form 10-K. ~~There were no capacity revenues from non-members for the three and nine months ended September 30, 2022 and 2021.~~

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

We have a rate management program that allows us to expense and recover interest costs associated with the construction of Vogtle Units No. 3 and No. 4, on a current basis, that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual basis. Under this program, amounts billed to participating members during the ~~nine~~three months ended ~~September 30,~~March 31, 2023 and 2022 were $1,761,000 and ~~2021 were $11,987,000 and $11,601,000,~~$3,861,000, respectively. The cumulative amount billed since inception of the program totaled ~~$123,623,000.~~$128,193,000.

In 2018, we began an additional rate management program that allows us to recover future expense on a current basis from our members. In general, the program allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. During the first quarter of 2022, we began applying billing credits to some of our participating members within this program. Under this program, net billing credits and amounts billed to participating members, ~~net of billing credits,~~ during the ~~nine~~three months ended ~~September 30,~~March 31, 2023, and 2022 were $15,713,000 and ~~2021 were $8,831,000 and $115,837,000,~~$2,944,000, 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 are applying regulated operations accounting to defer these revenues and related investment income on the funds collected. Amounts deferred under the program will be amortized to income when applied to members' bills. The net cumulative amount billed, since inception of the program totaled ~~$366,159,000.~~$353,389,000.

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(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 ~~and nine~~ months ended ~~September 30,~~March 31, 2023 and 2022 ~~and 2021~~ 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,

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•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 ~~March 16, 2024.~~October 31, 2026. 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 an additional operating lease that has a term that extends 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.

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


Classification	Classification	September 30, 2022		December 31, 2021		Classification	March 31, 2023		December 31, 2022
		(dollars in thousands)					(dollars in thousands)
Right-of-use assets—Finance leases	Right-of-use assets—Finance leases					Right-of-use assets—Finance leases
Right-of-use assets	Right-of-use assets	$	302,732	$	302,732	Right-of-use assets	$	302,732	$	302,732
Less: Accumulated provision for depreciation	Less: Accumulated provision for depreciation	(271,559)		(267,606)		Less: Accumulated provision for depreciation	(274,194)		(272,876)
Total finance lease assets	Total finance lease assets	$	31,173	$	35,126	Total finance lease assets	$	28,538	$	29,856
Lease liabilities—Finance leases	Lease liabilities—Finance leases					Lease liabilities—Finance leases
Obligations under finance leases	Obligations under finance leases	$	57,249	$	61,335	Obligations under finance leases	$	52,937	$	52,937
Long-term debt and finance leases due within one year	Long-term debt and finance leases due within one year	7,958		7,541		Long-term debt and finance leases due within one year	8,398		8,398
Total finance lease liabilities	Total finance lease liabilities	$	65,207	$	68,876	Total finance lease liabilities	$	61,335	$	61,335


Classification	March 31, 2023		December 31, 2022
	(dollars in thousands)
Right-of-use assets—Operating leases
Electric plant in service, net	$	3,032	$	3,326
Total operating lease assets	$	3,032	$	3,326
Lease liabilities—Operating leases
Capitalization—Other	$	1,961	$	2,256
Other current liabilities	1,084		1,164
Total operating lease liabilities	$	3,045	$	3,420

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Classification September 30, 2022 December 31, 2021
(dollars in thousands)
Right-of-use assets—Operating leases
Electric plant in service, net $ 1,664 $ 2,293
Total operating lease assets $ 1,664 $ 2,293
Lease liabilities—Operating leases
Capitalization—Other $ 960 $ 1,550
Other current liabilities 718 838
Total operating lease liabilities $ 1,678 $ 2,388


			Three months ended				Nine months ended					Three months ended
Lease Cost	Lease Cost	Classification	September 30, 2022		September 30, 2021		September 30, 2022		September 30, 2021				Lease Cost	Classification	March 31, 2023		March 31, 2022
			(dollars in thousands)								(dollars in thousands)
Finance lease cost:	Finance lease cost:												Finance lease cost:
Amortization of leased assets	Amortization of leased assets	Depreciation and amortization	$	1,885	$	1,693	$	5,656	$	4,726			Amortization of leased assets	Depreciation and amortization	$	2,099	$	1,885
Interest on lease liabilities	Interest on lease liabilities	Interest expense	1,852		2,045		5,556		6,133				Interest on lease liabilities	Interest expense	1,638		1,852
Operating lease cost:	Operating lease cost:	Inventory(1) & production expense	222		270		666		809				Operating lease cost:	Inventory(1) & production expense	329		222
Total leased cost	Total leased cost		$	3,959	$	4,008	$	11,878	$	11,668			Total leased cost		$	4,066	$	3,959

(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.


		September 30, 2022		December 31, 2021			March 31, 2023		December 31, 2022
Lease Term and Discount Rate:	Lease Term and Discount Rate:					Lease Term and Discount Rate:
Weighted-average remaining lease term (in years)	Weighted-average remaining lease term (in years)					Weighted-average remaining lease term (in years)
Finance leases	Finance leases	6.17		6.90		Finance leases	5.69		5.94
Operating leases	Operating leases	9.88		8.01		Operating leases	6.76		6.44
Weighted-average discount rate:	Weighted-average discount rate:					Weighted-average discount rate:
Finance leases	Finance leases	11.05	%	11.05	%	Finance leases	11.05	%	11.05	%
Operating leases	Operating leases	4.97	%	4.73	%	Operating leases	5.63	%	5.52	%

Nine months ended September 30,
2022 2021
(dollars in thousands)
Other Information:
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from finance leases $ 3,806 $ 4,180
Operating cash flows from operating leases $ 747 $ 890
Financing cash flows from finance leases $ 3,669 $ 3,295
Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ —

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	Three months ended March 31,
	2023		2022
	(dollars in thousands)
Other Information:
Cash paid for amounts included in the measurement of lease liabilities

Operating cash flows from operating leases	$	409	$	303

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

Maturity analysis of our finance and operating lease liabilities as of ~~September 30, 2022~~March 31, 2023 is as follows:


		(dollars in thousands)							(dollars in thousands)
Year Ending December 31,	Year Ending December 31,	Finance Leases		Operating Leases		Total		Year Ending December 31,	Finance Leases		Operating Leases		Total
2022		$	7,475	$	182	$	7,657
2023	2023	14,949		708		15,657		2023	$	14,949	$	914	$	15,863
2024	2024	14,949		234		15,183		2024	14,949		850		15,799
2025	2025	14,949		72		15,021		2025	14,949		641		15,590
2026	2026	14,949		72		15,021		2026	14,949		350		15,299
2027								2027	14,949		72		15,021
Thereafter	Thereafter	25,634		940		26,574		Thereafter	10,683		868		11,551
Total lease payments	Total lease payments	$	92,905	$	2,208	$	95,113	Total lease payments	$	85,428	$	3,695	$	89,123
Less: imputed interest	Less: imputed interest	(27,698)		(530)		(28,228)		Less: imputed interest	(24,093)		(650)		(24,743)
Present value of lease liabilities	Present value of lease liabilities	$	65,207	$	1,678	$	66,885	Present value of lease liabilities	$	61,335	$	3,045	$	64,380

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.

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Lease income recognized during the three ~~and nine~~ months ended ~~September 30,~~March 31, 2023 and 2022 ~~and 2021~~ was as follows:
Three Months Ended September 30, Nine Months Ended September 30,
2022 2021 2022 2021
(dollars in thousands)
Lease income $ 1,651 $ 1,603 $ 4,965 $ 4,806


	Three Months Ended March 31,
	2023		2022
	(dollars in thousands)
Lease income	$	1,685	$	1,645

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

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

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

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

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

In July 2020, a group of individual plaintiffs filed a complaint, which was amended on December 9, 2022, in the Superior Court of Fulton County, Georgia against Georgia Power alleging that ~~releases from~~the construction and operation of Plant Scherer, of which we are a co-owner, ~~have~~has impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. Georgia

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Power has filed multiple motions to dismiss the ~~complaint.~~complaint, one of which remains pending. On December 29, 2022, the Superior Court of Fulton County granted Georgia Power’s motion to transfer the case to the Superior Court of Monroe County. As of the date of this quarterly report, this case has approximately 48 plaintiffs.

Eight additional complaints, three on October 8, 2021, ~~three additional complaints~~four on February 7, 2022, and one on January 9, 2023, were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages. ~~On November 11, 2021,~~ Georgia Power ~~filed a notice to remove the three~~has removed each of these cases ~~pending in the Superior Court of Monroe County~~ to the U.S. District Court infor the Middle District of Georgia. On November 16, 2022, plaintiffs voluntarily dismissed seven of the cases and, on February ~~7, 2022, four additional complaints were filed in~~21, 2023 the ~~Superior Court of Monroe County, Georgia against~~remaining plaintiff voluntarily dismissed the eighth case. Georgia Power seeking damages for alleged personal injuries or property damage. On March 9, 2022, Georgia Power filed notices to remove the four additional cases pending in the Superior Court of Monroe County to the U.S. District Court in the Middle District of Georgia. Collectively,has stated that it anticipates these ~~cases include approximately 70 plaintiffs.~~ plaintiffs will refile their complaints.

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

In May 2022, Florida Power & Light Company and JEA filed a complaint in the U.S. District Court for the Northern District of Georgia against us and the other co-owners of Plant Scherer alleging that their contractual responsibility for a proportionate share of certain common facility costs relating to future environmental projects at Plant Scherer should be decreased following the retirement of Scherer Unit No. 4 at the end of ~~2021.~~2021 and the announced retirement of Unit No. 3

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at the end of 2028. We and the other co-owners of Plant Scherer ~~have~~ filed motions to dismiss Florida Power & Light and JEA's complaint and, on February 9, 2023, the court granted our motions to dismiss with leave to amend. On March 13, 2023, Florida Power & Light and JEA filed an amended complaint and on April 17, 2023, we and the other co-owners filed motions to dismiss this amended complaint. While we do not believe that the co-ownership agreements support the arguments raised by Florida Power & Light Company and JEA, if their arguments were to be successful in this case, we could be responsible for an increased percentage of these costs relating to our interests in Scherer Unit Nos. 1 and 2. The amount of additional costs relating to these future projects, if any, cannot be determined at this time.

(I)Restricted Cash and Investments. Restricted investments ~~consist~~consisted of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account that ~~are~~were held by the U.S. Treasury, acting through the Federal Financing Bank. ~~We can only utilize these~~At December 31, 2022, we had restricted investments totaling $74,031,000, all of which were classified as current. During the three-month period ended March 31, 2023, we utilized all of our restricted investments for ~~future~~scheduled Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. For the period from January 1, 2021 to September 30, 2021, deposits earned interest at 4% per annum. Beginning October 1, 2021, the rate was set at the 1-year floating treasury rate, which was 0.09% per annum, and will be reset annually on October 1 of each year thereafter. On October 1, 2022, the rate was reset at the 1-year floating treasury rate, which was 4.05% per annum. The program no longer allows additional funds to be deposited into the account. At September 30, 2022 and December 31, 2021, we had restricted investments totaling $73,282,000 and $320,052,000, respectively, of which $73,282,000 and $246,350,000, respectively, were classified as current.

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	Classification					Classification
		Nine months ended					Three months ended
		September 30, 2022		September 30, 2021			March 31, 2023		March 31, 2022
		(dollars in thousands)					(dollars in thousands)
Cash and cash equivalents	Cash and cash equivalents	$	572,828	$	452,943	Cash and cash equivalents	$	390,821	$	467,353

Restricted cash included in restricted cash and short-term investments	Restricted cash included in restricted cash and short-term investments	67,600		3,400		Restricted cash included in restricted cash and short-term investments	16,000		39,200
Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows	Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows	$	640,428	$	456,343	Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows	$	406,821	$	506,553

(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, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members.

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The following regulatory assets and liabilities are reflected on the consolidated balance sheets as of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021.~~2022.


		2022		2021			2023		2022
		(dollars in thousands)					(dollars in thousands)
Regulatory Assets:	Regulatory Assets:					Regulatory Assets:
Premium and loss on reacquired debt(a)	Premium and loss on reacquired debt(a)	$	30,498	$	33,200	Premium and loss on reacquired debt(a)	$	28,490	$	29,494
Amortization of financing leases(b)	Amortization of financing leases(b)	32,476		34,179		Amortization of financing leases(b)	31,126		31,908
Outage costs(c)	Outage costs(c)	33,301		31,956		Outage costs(c)	42,421		29,317
Asset retirement obligations—Ashpond and other(l)	Asset retirement obligations—Ashpond and other(l)	411,072		335,231		Asset retirement obligations—Ashpond and other(l)	378,997		353,212
Asset retirement obligations—Nuclear(l)	Asset retirement obligations—Nuclear(l)	65,148		—		Asset retirement obligations—Nuclear(l)	275		32,192
Depreciation expense - Plant Vogtle(d)	Depreciation expense - Plant Vogtle(d)	35,905		36,973		Depreciation expense - Plant Vogtle(d)	35,193		35,549
Depreciation expense - Plant Wansley(e)	Depreciation expense - Plant Wansley(e)	366,770		204,891		Depreciation expense - Plant Wansley(e)	356,759		361,784
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f)	Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f)	54,488		55,857		Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f)	55,811		54,701
Interest rate options cost(g)	Interest rate options cost(g)	135,434		131,556		Interest rate options cost(g)	138,154		136,827
Deferral of effects on net margin—Smith Energy Facility(h)	Deferral of effects on net margin—Smith Energy Facility(h)	138,216		142,675		Deferral of effects on net margin—Smith Energy Facility(h)	135,244		136,730
Other regulatory assets(o)	Other regulatory assets(o)	11,156		2,272		Other regulatory assets(o)	12,507		10,591
Total Regulatory Assets	Total Regulatory Assets	$	1,314,464	$	1,008,790	Total Regulatory Assets	$	1,214,977	$	1,212,305
Regulatory Liabilities:	Regulatory Liabilities:					Regulatory Liabilities:
Accumulated retirement costs for other obligations(i)	Accumulated retirement costs for other obligations(i)	$	35,905	$	22,197	Accumulated retirement costs for other obligations(i)	$	32,587	$	35,580
Deferral of effects on net margin—Hawk Road Energy Facility(h)	Deferral of effects on net margin—Hawk Road Energy Facility(h)	16,790		17,253		Deferral of effects on net margin—Hawk Road Energy Facility(h)	16,482		16,636
Deferral of effects on net margin—Effingham Energy Facility(p)	Deferral of effects on net margin—Effingham Energy Facility(p)	20,764		—		Deferral of effects on net margin—Effingham Energy Facility(p)	9,028		14,825
Major maintenance reserve(j)	Major maintenance reserve(j)	97,745		73,059		Major maintenance reserve(j)	83,690		74,584
Amortization of financing leases(b)	Amortization of financing leases(b)	6,282		8,457		Amortization of financing leases(b)	4,832		5,557
Deferred debt service adder(k)	Deferred debt service adder(k)	150,615		138,897		Deferred debt service adder(k)	158,541		154,514
Asset retirement obligations—Nuclear(l)		—		164,256

Revenue deferral plan(m)	Revenue deferral plan(m)	352,115		359,799		Revenue deferral plan(m)	347,379		357,460
Natural gas hedges(n)	Natural gas hedges(n)	192,026		63,994		Natural gas hedges(n)	64,584		131,804
Other regulatory liabilities(o)	Other regulatory liabilities(o)	1,307		1,537		Other regulatory liabilities(o)	1,153		1,230
Total Regulatory Liabilities	Total Regulatory Liabilities	$	873,549	$	849,449	Total Regulatory Liabilities	$	718,276	$	792,190
Net Regulatory Assets	Net Regulatory Assets	$	440,915	$	159,341	Net Regulatory Assets	$	496,701	$	420,115

(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 2221 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 inon August 31, 2022. Amortization commenced ~~in September 2022~~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 will commence effective with the commercial operation date of each unit and 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 will commence the earlier of when Vogtle Unit No. 3 is placed in ~~service.~~service or December 2023.

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

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

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

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

(l)Represents the difference in the timing of recognition of decommissioning costs for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for decommissioning.

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

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

(o)The amortization periods for other regulatory assets range up to 2827 years and the amortization periods of other regulatory liabilities range up to 54 years.

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

(K)Member Power Bill Prepayments. We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through December ~~2026,~~2028, with the majority of the balance scheduled to be credited by the end of ~~2023.~~2024.

(L)Debt.

a)Department of Energy Loan Guarantee:

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under a Note Purchase Agreement, dated as of February 20, 2014 (the Original Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Documents).

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

Together, the Original FFB Documents and Additional FFB Documents provide for a ~~multi-advance~~ term loan facility (the Facility) under which we ~~may make long-term loan borrowings through the Federal Financing Bank.~~

~~Proceeds~~borrowed a total of ~~advances made~~$4,633,028,088. We received our final advance under the Facility ~~are used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3~~in December 2022. Interest is payable quarterly in arrears and ~~No. 4 that are eligible for financing~~principal payments on all advances under the ~~Title XVII loan guarantee program (Eligible Project Costs). Borrowings under the Original~~ FFB Notes ~~could not exceed $3,057,069,461,~~began on February 20, 2020. As of ~~which $335,471,604 was designated for capitalized interest. We~~March 31, 2023, we have ~~advanced all amounts available under~~repaid $363,113,299 of principal on the ~~Original FFB Notes. We were unable to advance $43,721,079 of the amount designated for capitalized interest under the Original~~ FFB Notes ~~due to timing of borrowing~~ and ~~lower than expected interest rates.~~

~~Borrowings under~~ the Additional FFB Note may not exceed (i) $1,619,679,706 or (ii) an amount that, when aggregated with borrowings under the Original FFB Notes, equals 70% of Eligible Project Costs less the $1,104,000,000 guarantee payment we received from Toshiba Corporation in late 2017. At September 30, 2022, borrowings under the Additional FFB Note totaled $1,262,000,000.

~~At September 30, 2022,~~ aggregate Department of Energy-guaranteed borrowings outstanding, including capitalized interest, totaled ~~$4,275,348,382.~~$4,269,914,789. The final maturity date is February 20, 2044. Under the FFB Documents, we may voluntarily prepay outstanding borrowings under the Facility subject to a make-whole premium or discount, as applicable.

Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event it is required to make any payments to the Federal Financing Bank under its guarantee. Our payment obligations to the Federal Financing Bank under the FFB Notes and reimbursement obligations to the Department of Energy under its guarantee, but not our covenants to the Department of Energy under the Loan Guarantee Agreement, are secured equally and ratably with all of our other obligations issued under our first mortgage indenture. The final maturity date for each advance is February 20, 2044. Interest is payable quarterly in arrears and principal payments on all advances under the FFB Notes began on February 20, 2020. As of September 30, 2022, we have repaid $280,458,000 of principal on the FFB Notes. Interest rates on advances during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%.

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

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

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

If certain events occur, referred to as an "Alternate Amortization Event," at the Department of Energy's option ~~the Federal Financing Bank's commitment to make further advances under the Facility will terminate and~~ we will be required to repay the outstanding principal amount of all borrowings under the Facility over a period of five years, with level principal amortization. These events include (i) abandonment of the Vogtle Units No. 3 and No. 4 project, including a decision by Georgia Power to cancel the project, (ii) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (iii) termination of the Services Agreement or rejection of the Services Agreement in bankruptcy, if Georgia Power does not maintain access to certain related intellectual property rights, (iv) termination of the Services Agreement by Westinghouse or termination of the Bechtel Agreement by Bechtel Power Corporation, (v) delivery of certain notices by the Co-owners to the Department of Energy of their intent to cancel construction of Vogtle Units No. 3 and No. 4 coupled with termination by the Co-owners of the Services Agreement or the Bechtel Agreement, (vi) failure of the Co-owners to enter into a replacement contract with respect to the Services Agreement or

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the Bechtel Agreement following the Co-owners' termination of such agreement with the intent to replace it, (vii) the Department of Energy's takeover of construction of Vogtle Units No. 3 and No. 4 under certain conditions, (viii) the occurrence of any Project Adverse Event that results in a cancellation of the Vogtle Units No. 3 and No. 4 project or the cessation or deferral of construction beyond the periods permitted under the Loan Guarantee Amendment, (ix) loss of or failure to receive necessary regulatory approvals under certain circumstances, (x) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (xi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (xii) change of control of Oglethorpe and (xiii) certain events of loss or condemnation. If we receive proceeds from an event of condemnation relating to Vogtle Units No. 3 and No. 4, such proceeds must be applied to immediately prepay outstanding borrowings under the Facility.

b)Rural Utilities Service Guaranteed Loans:

For the ~~nine-month~~three-month period ended ~~September 30, 2022,~~March 31, 2023, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling ~~$63,031,000~~$15,431,000 for long-term financing of general and environmental improvements at existing plants.

~~On October 18, 2022, we closed on a second Rural Utilities Service-guaranteed loan for $234,681,000 to fund a portion of our cost to acquire Effingham.~~

~~On October 20, 2022,~~In April 2023, we received an additional ~~$19,532,000~~$22,970,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants.

c)~~First Mortgage~~Pollution Control Revenue Bonds:

On ~~April 12, 2022,~~February 1, 2023, we ~~issued $500,000,000~~remarketed $99,785,000 of ~~4.50% first mortgage~~Series 2017 pollution control revenue bonds. The remarketed bonds ~~Series 2022A, for the purpose of providing long-term financing for expenditures~~bear interest at an indexed rate until February 1, 2028 and are scheduled to mature in 2045. Our payment obligations related to ~~the construction of Vogtle Units No. 3 and No. 4. In conjunction with the issuance of the~~these bonds ~~we repaid $493,405,000 of outstanding commercial paper. The bonds are due to mature April 2047 and~~ are secured under our first mortgage indenture.

d)~~Pollution Control Revenue Bonds:~~

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We redeemed $31.0 million of Series 2017 pollution control revenue bonds in the third quarter of 2022. At June 30, 2022, these bonds were classified as long-term debt based upon the contractual maturity date.

(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 under construction at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services.

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

Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technical support and staff augmentation on a time and materials cost basis. The Services Agreement provides that it will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days' written notice.

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

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Cost and Schedule

Our current budget for our ownership interest in Vogtle Units No. 3 and No. 4, which includes capital costs, allowance for funds used during construction and some level of contingency is $8.1 billion and is based on commercial operation dates of ~~March~~July 2023 and March 2024 for Units No. 3 and No. 4, respectively. This budget reflects our June 17, 2022 exercise of the tender option in the Global Amendments to the Joint Ownership Agreements as described below. Had we not exercised the tender option, our budget would be approximately ~~$8.6~~$8.67 billion. At ~~September 30, 2022,~~March 31, 2023, our total ~~investment~~capital and financing costs for our interest in the additional Vogtle units was $8.2 billion, approximately ~~$7.7 billion.~~$200 million of which relates to costs that exceed the tender option threshold that is the subject of litigation between us and Georgia Power, as described below.

The table below shows our project budget and actual costs through March 31, 2023 for our share of the project.


	(in millions)
	Project Budget		Actual Costs at March 31, 2023
Construction Costs (1)	$	6,559	$	6,286
Freeze Capital Credit (2)	(532)		—
Financing Costs	2,038		1,844
Subtotal	$	8,065	$	8,130	(3)

Deferred Training Costs	47		47
Total Project Costs Before Contingency	$	8,112	$	8,177



Oglethorpe Contingency	$	3	$	—
Totals	$	8,115	$	8,177

(1) Construction costs are net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and $99 million in cost sharing benefits associated with the Global Amendments to the Joint Ownership Agreements.
(2) As described below, we exercised the tender option to cap our capital costs at the EAC in VCM 19 plus $2.1 billion, the freeze tender threshold. The freeze capital credit reflects our share of budgeted amounts that exceed this threshold.
(3) At March 31, 2023, approximately $200 million relates to costs that exceed the tender option threshold that is the subject of litigation between us and Georgia Power.

The Oglethorpe-level contingency, which we have carried at various levels since the beginning of the project, provides additional margin to cover potential cost, schedule, and financing risks associated with our share of the project. At the end of the project, if there is remaining Oglethorpe-level contingency, we will adjust our project budget to remove this contingency and bill our members based on the actual project costs. Any schedule extension beyond July 2023 and March 2024 for Units No. 3 and No. 4, respectively, is expected to increase our financing costs by approximately $15-$20 million per month for Unit No. 3 and approximately $10-$15 million per month for Unit No. 4. We and some of our members have implemented various rate management programs to lessen the impact on rates when Vogtle Units No. 3 and No. 4 reach commercial operation.

Our initial ownership interest and proportionate share of the cost to construct the additional Vogtle units was 30%, representing approximately 660 megawatts. However, we have exercised the tender option discussed below which caps our capital costs in exchange for a proportionate reduction of our 30% interest in the two units. Based on the current project budget and schedule and our interpretation of the Global Amendments (described below), we would transfer approximately 5055 megawatts, out of 660 megawatts, to Georgia Power. Our resulting ownership share would decline from 30% to approximately ~~28%~~27.5%. However, if the total project ~~budget exceeds~~costs exceed the current budget, our ownership share and megawatts would be further reduced.

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~~actual costs through September 30, 2022 for our share of the project.~~
(in millions)
Project Budget (Tender) Actual Costs at
September 30, 2022
Construction Costs (1)
$ 6,025 $ 6,000
Financing Costs 1,974 1,695
   Subtotal $ 7,999 $ 7,695
Deferred Training Costs 49 46
   Total Project Costs Before Contingency $ 8,048 $ 7,741
Oglethorpe-Level Contingency 52 —
   Total Contingency $ 52 $ —
Totals $ 8,100 $ 7,741
(1) Construction costs are net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and $99 million in cost sharing benefits associated with the Global Amendments to the Joint Ownership Agreements.

Any schedule extension beyond March 2023 and March 2024 for Units No. 3 and No. 4, respectively, is expected to increase our financing costs by approximately $30 million per month for both units and approximately $13 million per month for Unit No. 4.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of start-up testing and related test results, engineering support, commodity installation, system turnovers ~~and related test results~~ and workforce statistics.

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included in the project budget. ~~Subsequent waves of the~~Future COVID-19 ~~pandemic~~variants could further disrupt or delay construction ~~testing, supervisory,~~ and ~~support~~testing activities at Vogtle Units No. 3 and No. 4.

On ~~July 29, 2022, Southern Nuclear announced that all~~March 6, 2023, the Unit No. 3 ~~inspections, tests, analyses,~~nuclear reactor achieved self-sustaining nuclear fission, commonly referred to as initial criticality, and, ~~acceptance criteria documentation had been submitted~~on April 1, 2023, the generator successfully synchronized to the power grid and generated electricity for the first time. Operators continue to perform tests at various power levels to help ensure the reactor performs as designed, and Southern Nuclear Regulatory Commission. On August 3, 2022, the Nuclear Regulatory Commission published its 103(g) finding that the acceptance criteria in the combined license for Unit No. 3 had been met, which allowed for nuclear fuelcontinues to ~~be loaded~~remediate various equipment and ~~allows start-up testing to begin. Fuel load for Unit No. 3 was completed on October 17, 2022.~~component issues as they are identified. Georgia Power has disclosed that it projects an in-service date for Unit No. 3 ~~by the end of the first quarter~~during May or June of 2023. ~~Our current budget reflects our expectation of an~~While a June 2023 in-service date for Unit No. 3 remains achievable, based on testing progress and remediation work related to valve and flange repairs in ~~March 2023.~~the condenser area of the secondary system, we believe that a July 2023 in-service date is more likely and have reflected a July in-service date in our current budget. The projected schedule for Unit No. 3 primarily depends on the ~~pace~~progression of ~~system and area transitions to operations, including the completion of closure documentation necessary to support start-up~~pre-operational testing and ~~the progression of~~ start-up, ~~final component, and pre-operational testing,~~ which may be impacted by further equipment, component and/or other operational ~~failures.~~challenges.

On May 1, 2023, hot functional testing was completed at Unit No. 4. Georgia Power has disclosed that it projects an in-service date for Unit No. 4 ~~by the end of the~~during late fourth quarter ~~2023.~~2023 or during the first quarter 2024. Given the remaining work to be done and potential risks associated with completing the work, our current budget anticipates an in-service date for Unit No. 4 ~~that is one quarter later,~~ in March 2024. Meeting the projected in-service date for Unit No. 4 primarily depends on potential impacts arising from Unit No. 4 testing activities overlapping with Unit No. 3 ~~progress through~~ start-up and ~~testing,~~commissioning; maintaining overall construction productivity and production levels ~~significantly~~ improving, particularly in ~~electrical installation, including terminations;~~subcontractor scopes of work; and maintaining appropriate levels of craft ~~laborers, particularly electricians, being added and maintained.~~laborers. As Unit No. 4 ~~progresses through~~completes construction and ~~continues to transition~~transitions further into testing, ongoing and potential future challenges include the duration of hot functional testing, the timeframe and duration of other testing, the pace and quality of ~~electrical, mechanical, and instrumentation and controls~~remaining commodities installation; ~~availability~~the completion of ~~craft and supervisory resources, including the temporary diversion of such resources~~documentation to support ~~Unit No. 3;~~inspections, tests, analyses and acceptance criteria submittals; the pace of remaining work package closures and system turnovers; and the ~~timeframe~~availability of craft, supervisory and ~~duration of hot functional and other testing.~~technical support resources.

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cost escalation. New challenges also may continue to arise ~~particularly~~ as ~~Units~~Unit No. 3 completes start-up and commissioning and Unit No. 4 ~~move~~moves further into ~~initial~~ testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale). These challenges may result in further schedule delays and/or cost increases.

There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. On March 25, 2022, the Nuclear Regulatory Commission completed a follow up inspection related to the November 2021 final significance report on its special inspection to review the root cause of additional construction remediation work identified in 2021 and Southern Nuclear’s corresponding corrective action plans. The Nuclear Regulatory Commission closed the findings identified in November 2021 and returned Unit No. 3 to the Nuclear Regulatory Commission’s baseline inspection program.

With the receipt of the Nuclear Regulatory Commission’s 103(g) finding in August 2022, Unit No. 3 is now ~~under~~subject to the Nuclear Regulatory Commission’s operating reactor oversight process and must meet applicable technical and operational requirements contained ~~within Unit No. 3’s~~in its operating license. Various design and other licensing-based compliance matters, including the ~~completion~~timely submittal by Southern Nuclear of the inspections, tests, analyses, and acceptance criteria documentation and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel for Unit No. 4, may arise, which may result in additional license amendment requests or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections, tests, analyses, and acceptance criteria for Unit No. 4, are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners.

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

Co-Owner Contracts and Other Information

In November 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 to provide for, among other conditions, additional Co-owner approval requirements. These joint ownership agreements, including the Co-owner approval requirements, were subsequently amended, effective August 31, 2018. As described below, certain provisions of the Joint Ownership Agreements were modified further on September 26, 2018 by the Term Sheet that was memorialized on February 18, 2019 when the Co-owners entered into certain amendments (the Global Amendments) to the Joint Ownership Agreements (as amended, the Joint Ownership Agreements).

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ownership interests in Vogtle Units No. 3 and No. 4 were required to vote to continue construction. In September 2018, the Co-owners unanimously voted to continue construction of Vogtle Units No. 3 and No. 4.

In connection with the September 2018 vote to continue construction, Georgia Power entered into a binding term sheet with the other Co-owners and MEAG’s wholly-owned subsidiaries MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, and MEAG Power SPVP, LLC to mitigate certain financial exposure for the other Co-owners and offered to purchase production tax credits from each of the other Co-Owners, at that Co-owner’s option (the Term Sheet). On February 18, 2019, the Co-owners entered into the Global Amendments to memorialize the provisions of the Term Sheet. Pursuant to the Global Amendments and consistent with the Term Sheet, the Joint Ownership Agreements provide that:

•each Co-owner is obligated to pay its proportionate share of construction costs for Vogtle Units No. 3 and No. 4 based on its ownership interest up to (i) the estimated cost at completion ("EAC") for Vogtle Units No. 3 and No. 4 which formed the basis of Georgia Power's forecast of $8.4 billion in Georgia Power's VCM 19 filed with the Georgia Public Service Commission plus (ii) $800 million of additional construction costs;

•Georgia Power will be responsible for 55.7% of construction costs, subject to exceptions such as costs that are a result of a force majeure event, that exceed the EAC in VCM 19 by $800 million to $1.6 billion (resulting in up to $80 million of potential additional costs to Georgia Power which would save Oglethorpe up to $44 million), with the remaining Co-owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests (equal to 24.5% for our 30% ownership interest); and

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up to a further $100 million of potential additional costs to Georgia Power which would save Oglethorpe up to an additional $55 million), with the remaining Co-owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests (equal to 19.0% for our 30% ownership interest).

If the EAC is revised and exceeds the EAC in VCM 19 by more than $2.1 billion, each of the Co-owners, other than Georgia Power, has a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power’s agreement to pay 100% of such Co-owner’s share of construction costs actually incurred in excess of the EAC in VCM 19 plus $2.1 billion. If any Co-owner elects to exercise this tender option, Georgia Power would have the option to cancel the project in lieu of accepting the offer to purchase a portion of the Co-owner’s ownership interest. If Georgia Power does not elect to cancel the project, then Georgia Power must accept the offer, and the ownership interest to be conveyed from the tendering Co-owner to Georgia Power will be calculated based on the percentage of the cumulative amount of construction costs paid by such tendering Co-owner as of the commercial operation date of Vogtle Unit No. 4. For purposes of this calculation, payments made by Georgia Power on behalf of the tendering Co-owner in accordance with the second and third bullets above will be treated as payments made by that Co-owner. This option to tender a portion of our interest to Georgia Power upon such a budget increase ~~would allow~~allowed us to freeze our construction budget associated with the Vogtle project in exchange for a proportionate reduction of our 30% ownership interest.

The VCM 19 total project cost is $17.1 billion (which excludes non-shareable costs) as reflected in numerous Georgia Public Service Commission filings. As of December 31, 2021, budget increases since VCM 19 ~~have~~ reached $3.4 billion for all Co-owners. As a result of ~~these~~those increases, we believe that the tender option was triggered at the Co-owner construction budget vote on February 14, 2022 and that Georgia Power’s increased responsibility for certain construction costs as described above commenced in March 2022.

On June 17, 2022, we notified Georgia Power of our election to exercise the tender option and cap our capital costs in exchange for a proportionate reduction of our 30% interest in the two new units. Our decremental ownership interest will be calculated and conveyed to Georgia Power after both Vogtle units are placed in service. Based on the current project budget, our schedule assumptions and our interpretation of the Global Amendments, our project budget is $8.1 billion and we expect to transfer approximately 5055 megawatts, out of 660 megawatts, to Georgia Power. Our resulting ownership share will decline from 30% to approximately ~~28%~~27.5%. By exercising the tender option and based on current assumptions, we estimate that we will avoid incurring approximately ~~$500~~$535 million in construction costs associated with the project. However, if the total project ~~budget exceeds~~costs exceed the current budget, our ownership share and megawatts would be further reduced. On July 26, 2022, the City of Dalton notified Georgia Power that it had elected to exercise its tender option.

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triggered. For purposes of determining when our option to tender ~~has been~~was triggered, the Global Amendments do not exclude costs resulting from force majeure events (such as COVID-19) from the calculation of when the EAC in VCM 19 plus $2.1 billion has been reached. We and Georgia Power also do not agree on the dollar amount that ~~triggers~~triggered Georgia Power’s increased responsibility for certain construction costs as described above, and the extent to which costs that are the result of a force majeure event (such as COVID-19), impact the calculation of the point at which Georgia Power’s increased responsibility for certain construction costs as described above iswas triggered. The exclusion of costs resulting from a force majeure event (such as COVID-19) in the Global Amendments only applies to Georgia Power’s increased cost responsibility during the time period when construction costs exceed the EAC in ~~the nineteenth~~ VCM ~~report~~19 by $800 million to $2.1 billion.

Accordingly, in March 2022, we notified Georgia Power of a billing dispute with regards to both the starting dollar amount and the application of costs resulting from a force majeure event and how such amounts impact the thresholds and timing of the cost-sharing and tender option provisions. On June 18, 2022, after completing the dispute resolution procedures set forth in the Ownership Participation Agreement for the additional Vogtle units, we and MEAG filed separate lawsuits against Georgia Power in the Superior Court of Fulton County, Georgia seeking to enforce the terms of the Global Amendments. Our lawsuit seeks declaratory judgment that the cost sharing and tender provisions of the Global Amendments have been triggered based on a VCM 19 forecast of $17.1 billion. Our lawsuit also alleges breach of contract and asserts other claims and seeks damages and injunctive relief requiring Georgia Power to track and allocate construction costs consistent with our interpretation of the Global Amendments. On July 28, 2022, Georgia Power filed a counterclaim against us seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power’s related financial obligations. Based on the current project budget and Georgia Power’s interpretation of the Global Amendments, our project budget would be ~~$8.6~~$8.67 billion, ~~an increase of~~and we would incur approximately ~~$500~~$535 million of additional construction costs (excluding related financing costs) and ~~we would~~ retain substantially all of our 30% interest in the additional units. On September 26, 2022, the

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City of Dalton filed a complaint in our lawsuit and joined our claims. On September 29, 2022, Georgia Power and MEAG reached an agreement with respect to their pending litigation.

Pursuant to the Joint Ownership Agreements, as amended by the Global Amendments, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement, the Bechtel Agreement or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Vogtle Units No. 3 and No. 4 (or associated financing costs) or the Georgia Public Service Commission determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Co-owners pursuant to the Global Amendment provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia Public Service Commission for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates or (iv) an incremental extension of one year or more from the seventeenth VCM report estimated in-service dates of November 2021 and November 2022 for Units No. 3 and No. 4, respectively (each, a Project Adverse Event). The schedule extensions, announced in February 2022, which reflected a cumulative delay of over a year for each unit from the schedules approved in the seventeenth VCM report, triggered the requirement for the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 to vote to continue construction, and the Co-owners unanimously voted to continue construction.

The Global Amendments provide that Georgia Power may cancel the project at any time at its sole discretion. In the event that Georgia Power determines to cancel the project or fewer than 90% of the Co-owners vote to continue construction upon the occurrence of a subsequent project adverse event, we and the other Co-owners would assess our options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval. Further, if Georgia Power or the Co-owners decided to cancel the project, the Department of Energy would have the discretion to require that we repay all amounts outstanding under our loan guarantee agreement with the Department of Energy over a five-year period as discussed in Note L of Notes to Unaudited Consolidated Financial Statements.

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

See “Item 1A – RISK FACTORS” in our ~~2021~~2022 Form 10-K for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating ~~units~~units.

(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

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billings to our members. See Note F for information regarding our member receivables. Commercial paper issuances we invest in are rated as investment grade and backed by a credit facility. 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)Plant Wansley. In July 2022, the Georgia Public Service Commission approved Georgia Power’s 2022 integrated resource plan. This plan requested the decertification of coal-fired Plant Wansley, of which we own a 30% interest, by August 31, 2022. In accordance with the approved plan, Georgia Power retired Plant Wansley in August 2022. Beginning in 2021, we accelerated depreciation of the remaining plant in service assets associated with Plant Wansley based upon the August 2022 retirement date and created a regulatory asset to defer a portion of the accelerated depreciation expense. These deferred costs will be recovered through future rates over a period ending no later than December 31, 2040. The Georgia Public Service Commission also approved Georgia Power’s modified closure proposal for the ash pond at Plant Wansley. The proposal recommended closure by removing the ash from the coal ash pond for several site-specific reasons, including available capacity at an existing on-site landfill, the retirement of Plant Wansley, beneficial use of the coal ash, and managing construction and operational risks of the previous close in place design. The Georgia Environmental Protection Department must also approve the change in closure plans. ~~We and Georgia Power are continuing~~

(P)Asset Retirement Obligations. On March 6, 2023, Plant Vogtle Unit No. 3's nuclear reactor achieved self-sustaining nuclear fission, commonly referred to ~~evaluate~~as initial criticality. As a result, as of March 31, 2023, we recognized new nuclear asset retirement obligations totaling $62.8 million. During the ~~costs associated with the modified closure plan; however,~~three months ended March 31, 2023, we ~~have received preliminary~~recorded an increase in cash flow estimates ~~from Georgia Power. At September 30, 2022, we have recognized an additional $66.7~~of $24.7 million inrelated to existing coal ash related asset retirement ~~obligations based upon these preliminary cost estimates.~~obligations. We expect to periodically receive more refined estimates from Georgia Power regarding closure costs and the timing of expenditures prior to year-end 2022. See Note J of Notes to Unaudited Consolidated Financial Statements for additional information regarding the retirement of Plant Wansley and the associated regulatory asset and see “Item 1 – OUR BUSINESS – REGULATION – Environmental – Coal Combustion Residuals and Effluent Limitations Guidelines” in our 2021 Form 10-K for additional information regarding the closure of the coal ash pond.expenditures.

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~~(P)Subsequent Events.~~ On October 24, 2022, we entered into an agreement to acquire two generating units at Washington County Power, a four-unit 660 megawatt combustion turbine generation and transmission facility located in Sandersville, Georgia, from Gulf Pacific Power, LLC, an investment fund managed by Harbert Management Corporation. The two acquired units will add approximately 330 megawatts of natural gas-fired capacity to our generation portfolio. This acquisition is subject to customary closing conditions, including regulatory approvals, and is expected to close in the fourth quarter of 2022.

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

General

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

Results of Operations

For the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2023 and 2022 ~~and 2021~~

Net Margin

Our net ~~margins~~margin for the three-month ~~and nine-month periods~~period ended ~~September 30, 2022 were $32.1~~March 31, 2023 was $24.4 million, ~~and $72.2 million, respectively,~~ compared to ~~$8.9~~$22.0 million ~~and $48.0 million, respectively,~~ for the same ~~periods~~period of ~~2021.~~2022. Through ~~September 30, 2022,~~March 31, 2023, we collected approximately ~~117.1%~~37% of our targeted net margin of ~~$61.7~~$66.0 million for the year ending December 31, ~~2022.~~2023. 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 ~~2022~~2023 targeted margins for interest ratio of 1.14. As a result, we assessed our projected margin and annual revenue requirement to meet the targeted margins for interest ratio to determine if a refund liability should be recognized. As a result of this assessment, we ~~recognized cumulative~~did not recognize a refund ~~liabilities of $9.0 million and $16.5 million~~liability as of ~~September 30, 2022 and September 30, 2021, respectively.~~March 31, 2023. 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 ~~2021~~2022 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, 2023 and ~~nine-month periods ended September 30,~~ 2022 ~~and 2021~~ were as follows:


		Three Months Ended September 30,								Nine Months Ended September 30,								Three Months Ended March 31,
		(dollars in thousands)								(dollars in thousands)									(dollars in thousands)
		2022			2021			% Change		2022			2021			% Change					2023			2022			% Change
Capacity revenues	Capacity revenues	$	243,860		$	228,048		6.9	%	$	728,992		$	716,303		1.8	%			Capacity revenues	$	242,043		$	243,291		(0.5)	%
Energy revenues	Energy revenues	383,270			209,192			83.2	%	794,369			455,130			74.5	%			Energy revenues	145,610			174,158			(16.4)	%
Total	Total	$	627,130		$	437,240		43.4	%	$	1,523,361		$	1,171,433		30.0	%			Total	$	387,653		$	417,449		(7.1)	%
MWh Sales to members	MWh Sales to members	8,243,846			7,566,980			8.9	%	20,053,117			18,727,189			7.1	%			MWh Sales to members	5,948,052			5,573,760			6.7	%
Cents/kWh	Cents/kWh	7.61			5.78			31.7	%	7.60			6.26			21.4	%			Cents/kWh	6.52			7.49			(13.0)	%
Member energy requirements supplied	Member energy requirements supplied	68		%	65		%	4.6	%	62		%	61		%	1.6	%			Member energy requirements supplied	64		%	57		%	12.3	%

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Energy revenues from members ~~increased~~decreased for the three-month ~~and nine-month periods~~period ended ~~September 30, 2022~~March 31, 2023 compared to the same ~~periods~~period in ~~2021,~~2022, primarily due to the recovery of lower fuel costs. The increase in megawatt-hours sold to members for the three-month ~~and nine-month periods~~

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period ended ~~September 30, 2022~~March 31, 2023 compared to the same ~~periods~~period in ~~2021 also contributed to the increase~~2022 partially offset a decrease in ~~energy revenues, primarily due to slightly warmer weather and members' consumer growth.~~fuel costs. For a discussion of fuel costs, which are the primary costs recovered by energy revenues, see "—Operating Expenses."

Sales to non-members. Energy revenues from non-members were primarily from the sale of ~~a portion of~~ the ~~energy~~Effingham deferring members' output ~~at Effingham, which we acquired in July 2021,~~ into the wholesale market. ~~There were no capacity~~Capacity revenues from non-members ~~for~~related to our Washington County acquisition in December 2022. For additional information regarding the ~~three-month and nine-month periods ended September 30,~~Washington County acquisition, see Note 14 in our 2022 ~~and 2021.~~Form 10-K.

Sales to non-members during the three-month period ended March 31, 2023 and ~~nine-month periods ended September 30,~~ 2022 ~~and 2021~~ were as follows:


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
		(dollars in thousands)						(dollars in thousands)							(dollars in thousands)

		2022		2021		% Change		2022		2021		% Change			2023		2022		% Change
Energy revenues	Energy revenues	$	77,135	$	23,582	227.1	%	$	134,474	$	23,847	463.9	%	Energy revenues	$	1,037	$	2,993	(65.4)	%
Capacity revenues														Capacity revenues	763		—		—
Total														Total	$	1,800	$	2,993	(39.9)	%
MWh Sales to non-members	MWh Sales to non-members	694,911		562,724		23.5	%	1,450,107		575,629		151.9	%	MWh Sales to non-members	39,215		69,268		(43.4)	%
Cents/kWh	Cents/kWh	11.10		4.19		164.9	%	9.27		4.14		123.9	%	Cents/kWh	4.59		4.32		6.2	%

Energy revenues from non-members ~~increased~~decreased for the three-month ~~and nine-month periods~~period ended ~~September 30, 2022~~March 31, 2023 compared to the same ~~periods~~period in ~~2021~~2022 primarily due to ~~higher market prices and an increase~~the decrease 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				Cost					Generation			Cents per kWh
		(dollars in thousands)					(MWh)							(dollars in thousands)					(MWh)
		Three Months Ended September 30,					Three Months Ended September 30,			Three Months Ended September 30,				Three Months Ended March 31,					Three Months Ended March 31,			Three Months Ended March 31,
Fuel Source	Fuel Source	2022		2021		% Change	2022	2021	% Change	2022	2021	% Change	Fuel Source	2023		2022		% Change	2023	2022	% Change	2023	2022	% Change
Coal	Coal	$	35,908	$	50,384	(28.7)%	984,046	1,535,053	(35.9)%	3.65	3.28	11.3%	Coal	$	22,788	$	32,287	(29.4)%	578,342	976,322	(40.8)%	3.94	3.31	19.0%
Nuclear	Nuclear	19,492		18,849		3.4%	2,692,666	2,434,355	10.6%	0.72	0.77	(6.5)%	Nuclear	16,043		16,611		(3.4)%	2,210,269	2,249,064	(1.7)%	0.73	0.74	(1.4)%
Gas:	Gas:												Gas:
Combined Cycle	Combined Cycle	263,871		121,220		117.7%	4,350,220	3,885,404	12.0%	6.07	3.12	94.6%	Combined Cycle	91,686		115,057		(20.3)%	3,326,422	2,549,581	30.5%	2.76	4.51	(38.8)%
Combustion Turbine	Combustion Turbine	99,947		24,228		312.5%	1,110,747	489,436	126.9%	9.00	4.95	81.8%	Combustion Turbine	2,651		1,529		73.4%	77,659	23,322	233.0%	3.41	6.56	(48.0)%
		$	419,218	$	214,681	95.3%	9,137,679	8,344,248	9.5%	4.59	2.57	78.6%		$	133,168	$	165,484	(19.5)%	6,192,692	5,798,289	6.8%	2.15	2.85	(24.6)%

		Cost					Generation			Cents per kWh
		(dollars in thousands)					(MWh)
		Nine Months Ended September 30,					Nine Months Ended September 30,			Nine Months Ended September 30,
Fuel Source		2022		2021		% Change	2022	2021	% Change	2022	2021	% Change
Coal		$	88,681	$	86,061	3.0%	2,425,508	2,559,235	(5.2)%	3.66	3.36	8.9%
Nuclear		54,678		57,853		(5.5)%	7,516,956	7,529,053	(0.2)%	0.73	0.77	(5.2)%
Gas:
Combined Cycle		561,460		252,472		122.4%	10,422,541	8,876,229	17.4%	5.39	2.84	89.8%
Combustion Turbine		143,004		39,891		258.5%	1,671,317	873,175	91.4%	8.56	4.57	87.3%
		$	847,823	$	436,277	94.3%	22,036,322	19,837,692	11.1%	3.85	2.20	75.0%

Total fuel costs ~~increased~~decreased for the three-month ~~and nine-month periods~~period ended ~~September 30, 2022~~March 31, 2023 compared to the same ~~periods~~period in ~~2021~~2022 as a result of ~~an increase~~a decrease in the average cost of fuel ~~and~~offset by an increase in generation for ~~members and non-members. In~~

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~~June 2022, our member system hit a new peak demand of 10,018 megawatts, eclipsing our members' prior peak of 9,477 megawatts.~~members. The ~~increase~~decrease in average fuel cost was primarily due to ~~higher~~lower average natural gas prices in ~~2022 as prices have increased due to supply and demand pressures.~~2023. The overall increase in generation for the three-month ~~and nine-month periods~~period ended ~~September 30, 2022~~March 31, 2023 compared to the same ~~periods~~period in ~~2021~~2022 was largely due to our members obtaining more of their energy requirements from us rather than their third party suppliers due to relative energy ~~prices and an increase in sales to non-members.~~prices.

Production

Production costs ~~increased~~ for the three-month ~~and nine-month periods~~period ended ~~September 30, 2022 as compared~~March 31, 2023 was comparable to the same ~~periods~~period of 2021 primarily as a result of deferring Effingham's effects on net margin of $17.8 million and $24.5 million, respectively. For additional information regarding the Effingham deferral, see Note 13 in our 2021 Form 10-K.2022.

Interest Charges

Net interest charges ~~decreased~~increased slightly for the three-month ~~and nine-month periods~~period ended ~~September 30, 2022~~March 31, 2023 as compared to the same ~~periods~~period of ~~2021~~2022 as a result of higher interest expense offset by the capitalization of interest expense associated with construction expenditures for Vogtle Units No. 3 and No. 4.

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Financial Condition

Balance Sheet Analysis as of ~~September 30, 2022~~March 31, 2023

Assets

Electric plant in service decreased $750.7 million for the nine-month period ended September 30, 2022, primarily due to the retirement of $870.3 million of Plant Wansley assets, including the coal ash pond, in August 2022, offset partially by additions to plant of $157.4 million. Accumulated provision for depreciation decreased $489.2 million also primarily as a result of the $870.3 million Plant Wansley retirement, partially offset by depreciation recorded for the nine-month period which included $271.3 million of Plant Wansley depreciation. In anticipation of the plant's early retirement, we created a regulatory asset in 2021 to defer a portion of the accelerated depreciation expense. See Notes J and O of Notes to Unaudited Consolidated Financial Statements for a discussion of the regulatory asset associated with the early retirement of Plant Wansley.

Cash used for property additions for the ~~nine-month~~three-month period ended ~~September 30, 2022~~March 31, 2023 totaled ~~$872.6~~$259.1 million. Of this amount, ~~$686.1~~$208.6 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4 and ~~$60.2~~$19.3 million was for nuclear fuel purchases. The remainder was for expenditures related to normal additions and replacements to our existing generation facilities.

The ~~$156.5~~$33.4 million ~~decrease~~increase in nuclear decommissioning trust fund was primarily due to the ~~decrease~~increase in the fair market value of ~~trust assets~~investments due to the ~~downturn~~recovery in the stock market during the ~~nine-month~~three-month period ended ~~September 30, 2022.~~March 31, 2023.

Long-term investments decreased ~~$81.0~~$3.5 million for the ~~nine-month~~three-month period ended ~~September 30, 2022~~March 31, 2023 primarily due to $14.4 million of investments reclassified to short-term investments and a ~~$66.0~~net $4.3 million decrease due to redemptions, largely offset by a $15.4 million increase in fair market value of our long-term investments during the nine-month period ended September 30, 2022. In addition, $52.1 million of investments associated with one of our rate management programs was reclassified to short-term investments as we expect to apply the proceeds from these maturing investments to members' bills during the next twelve months. Offsetting these decreases were $20.5 million of collections and fund earnings invested in our major maintenance outage, coal ash remediation and internal decommissioning funds and $16.6 million in net collections invested under one of our member rate programs during the nine-month period ended September 30, 2022. See Note F of Notes to Unaudited Consolidated Financial Statements for a discussion of our member rate management programs.investments.

Restricted cash and investments ~~consist~~consists of ~~$67.6 million in~~ collateral posted by our counterparties under our natural gas swap agreements and ~~$73.3 million in~~ funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. ~~We can only utilize~~During the three-month period ended March 31, 2023, restricted cash and investments decreased $88.4 million as we fully utilized our remaining $74.0 million of restricted investments ~~in the Cushion of Credit Account~~ for ~~future~~scheduled Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The program no longer allows additional funds to be deposited into the account. During the nine-month period ended September 30, 2022, restricted cash and investments decreased $180.6 million as we utilized $246.9 million for debt service payments and ~~expect to utilize the remainder~~as a result of ~~the balance through 2023. The~~a $14.4 million decrease ~~in restricted investments was offset by a $65.8 million increase~~ in restricted cash posted by counterparties under our natural gas swap agreements. For additional information regarding restricted cash and investments, see Note I of Notes to Unaudited Consolidated Financial Statements.

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Receivables ~~increased $76.1~~decreased $56.1 million for the ~~nine-month~~three-month period ended ~~September 30, 2022~~March 31, 2023 primarily due to a ~~$46.4~~$57.2 million ~~increase~~decrease in member ~~revenues~~receivables and a ~~$26.9~~$17.2 million ~~increase~~decrease in other receivables. Other receivables ~~increased~~decreased primarily due to ~~$18.2~~$12.6 million of trade receivables related to non-member ~~sales and $8.2~~sales. Offsetting these decreases was an increase of $23.6 million in receivables from ~~related parties.~~Georgia Power.

Prepayments and other current assets ~~increased $39.2~~decreased $35.3 million during the ~~nine-month~~three-month period ended ~~September 30, 2022~~March 31, 2023 primarily due to a ~~$44.2~~$31.3 million ~~increase~~decrease in fair value of our natural gas contracts that will settle within the next twelve months and an increase of $3.1 million in collateral we were required to post with a counterparty under our natural gas purchase and sale agreements. Offsetting these increases was a decrease of $11.9 million in prepaid inventory primarily relating to return of refurbished inventory associated with a major maintenance outage at one of our combined cycle plants.

Regulatory assets increased $305.7 million largely as a result of a $161.9 million increase in the deferral of accelerated depreciation associated with the early retirement of Plant Wansley, which occurred in August 2022. The increase in our regulatory assets was also attributable to a $76.0 million increase in the deferral associated with coal ash pond asset retirement obligations and a $65.1 million increase in the deferral associated with nuclear asset retirement obligations.months.

Other deferred charges ~~increased $83.3~~decreased $32.3 million during the ~~nine-month~~three-month period ended ~~September 30, 2022~~March 31, 2023 primarily due to ~~an $86.3~~a $31.5 million ~~increase~~decrease in fair value of our natural gas contracts that will settle after the next twelve months.

Equity and Liabilities

Long-term debt and long-term debt and finance leases due within one year ~~increased $438.7~~decreased $121.3 million primarily as a result of ~~the issuance of $500.0~~$137.7 million ~~of Series 2022A first mortgage bonds, a $168.0 million advance under the Department of Energy-guaranteed loan and $63.0~~in debt service payments. Offsetting this decrease was $15.4 million in advances under ~~the~~a Rural Utilities Service-guaranteed loan. ~~Offsetting this increase was $258.5 million in debt service payments and the early redemption of $31.0 million of Series 2017 pollution control revenue bonds.~~ See Note L of Notes to Unaudited Consolidated Financial Statements for additional information regarding long-term debt.

Short-term borrowings, which primarily provide interim financing for Vogtle Units No. 3 and No. 4 construction costs, ~~decreased $171.3~~increased $157.4 million during the ~~nine-month~~three-month period ended ~~September 30, 2022 primarily as a result of $493.4 million in repayments made from the proceeds of the first mortgage bonds issuance noted above.~~March 31, 2023. During this period, total short-term borrowings were $231.5 million and repayments ~~were $1.0 billion and borrowings~~ totaled ~~$832.7~~$74.1 million.

Accounts payable ~~increased $10.5~~decreased $121.5 million during the ~~nine-month~~three-month period ended ~~September 30, 2022.~~March 31, 2023. The ~~increase~~decrease was primarily due to a ~~$76.6~~$62.7 million ~~increase~~decrease in payables for natural gas purchases and related transportation and ~~a $9.2 million increase in payables to related parties. Offsetting this increase was a decrease of $41.7 million in trade accounts payable, primarily for property taxes, and the application of $30.0~~applying $28.5 million in credits to our members' bills in the first quarter of ~~2022~~2023 for a board-approved reduction in ~~2021~~2022 revenue in excess of the requirement to meet the ~~2021~~2022 targeted net margin.

Other current liabilities ~~increased $108.3~~decreased $61.9 million for the ~~nine-month~~three-month period ended ~~September 30, 2022~~March 31, 2023 primarily as a result of a ~~$65.8~~$36.7 million ~~increase~~decrease in accrued property taxes during the first quarter of 2023 and a $14.4 million decrease in restricted cash posted by and due to counterparties under our natural gas swap ~~agreements~~agreements.

Asset retirement obligations increased $100.8 million for the three-month period ended March 31, 2023 primarily due to recognized nuclear asset retirement obligations of $62.8 million, change in cash flow estimates of $24.7 million for coal ash related decommissioning costs and ~~a $48.6~~$15.5 million ~~increase~~ in ~~accrued property taxes.~~accretion expense.

Regulatory liabilities ~~increased $24.1~~decreased $73.9 million for the ~~nine-month~~three-month period ended ~~September 30, 2022~~March 31, 2023 primarily due to ~~$128.0~~$67.2 million ~~increase~~decrease in the liability associated with unrealized gains on our natural gas contracts ~~a $24.7 million increase in sinking fund collections for future major maintenance outages~~ and a ~~$21.3~~$10.1 million ~~increase~~decrease in the liability associated with the deferral of Effingham's effects on net margin. Partially offsetting this increase was a $164.3 million decrease in the liability associated with deferred nuclear asset retirement obligations that was primarily driven by a decrease in unrealized gains associated withone of our ~~nuclear decommissioning investments. For additional information regarding the Effingham deferral, see Note 13 in our 2021 Form 10-K.~~rate management programs.

~~Asset retirement obligations increased $101.6 million for the nine-month period ended September 30, 2022 primarily due to change in cash flow estimates~~

Table of ~~$66.7 million related to coal ash pond decommissioning and $41.4 million in accretion expense.~~Contents

Capital Requirements and Liquidity and Sources of Capital

Vogtle Units No. 3 and No. 4

We, Georgia Power, the Municipal Electric Authority of Georgia (MEAG), and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units under construction at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Pursuant to this agreement, Georgia Power has designated Southern Nuclear

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Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services.

Cost and Schedule

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The table below shows our project budget and actual costs through March 31, 2023 for our share of the project.


	(in millions)
	Project Budget		Actual Costs at March 31, 2023
Construction Costs (1)	$	6,559	$	6,286
Freeze Capital Credit (2)	(532)		—
Financing Costs	2,038		1,844
Subtotal	$	8,065	$	8,130	(3)

Deferred Training Costs	47		47
Total Project Costs before Contingency	$	8,112	$	8,177

Oglethorpe Contingency	$	3	$	—
Totals	$	8,115	$	8,177

(1) Construction costs are net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and $99 million in cost sharing benefits associated with the Global Amendments to the Joint Ownership Agreements.
(2) As described below, we exercised the tender option to cap our capital costs at the EAC in VCM 19 plus $2.1 billion, the freeze tender threshold. The freeze capital credit reflects our share of budgeted amounts that exceed this threshold.
(3) At March 31, 2023, approximately $200 million relates to costs that exceed the tender option threshold that is the subject of litigation between us and Georgia Power.

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~~September 30, 2022 for our share of the project.~~
(in millions)
Project Budget (Tender) Actual Costs at
September 30, 2022
Construction Costs (1)
$ 6,025 $ 6,000
Financing Costs 1,974 1,695
   Subtotal $ 7,999 $ 7,695
Deferred Training Costs 49 46
   Total Project Costs before Contingency $ 8,048 $ 7,741
Oglethorpe-Level Contingency 52 —
   Total Contingency $ 52 $ —
Totals $ 8,100 $ 7,741
(1) Construction costs are net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and $99 million in cost sharing benefits associated with the Global Amendments to the Joint Ownership Agreements.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of start-up testing and related test results, engineering support, commodity installation, system turnovers and ~~related test results and~~ workforce statistics.

Since March 2020, the number of active cases of COVID-19 at the site has fluctuated consistent with the surrounding area and impacted productivity levels and pace of activity completion. As of ~~September 30, 2022,~~March 31, 2023, the incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity, substantially all of which occurred during 2020 and 2021, is estimated by Georgia Power to be between $350 million and $438 million and is included in the project budget. ~~Subsequent waves of the~~Future COVID-19 ~~pandemic~~variants could further disrupt or delay construction ~~testing, supervisory,~~ and ~~support~~testing activities at Vogtle Units No. 3 and No. 4.

On ~~July 29, 2022, Southern Nuclear announced that all~~March 6, 2023, the Unit No. 3 ~~inspections, tests, analyses,~~nuclear reactor achieved self-sustaining nuclear fission, commonly referred to as initial criticality, and, ~~acceptance criteria documentation had been submitted~~on April 1, 2023, the generator successfully synchronized to the power grid and generated electricity for the first time. Operators continue to perform tests at various power levels to help ensure the reactor performs as designed, and Southern Nuclear Regulatory Commission. On August 3, 2022, the Nuclear Regulatory Commission published its 103(g) finding that the acceptance criteria in the combined license for Unit No. 3 had been met, which allowed for nuclear fuelcontinues to ~~be loaded~~remediate various equipment and ~~allows start-up testing to begin. Fuel load for Unit No. 3 was completed on October 17, 2022.~~component issues as they are identified. Georgia Power has disclosed that it projects an in-service date for Unit No. 3 ~~by the end of the first quarter of~~during May or June 2023. ~~Our current budget reflects our expectation of an~~While a June 2023 in-service date for Unit No. 3 remains achievable, based on testing progress and remediation work related to valve and flange repairs in ~~March 2023.~~the condenser area of the secondary system, we believe that a July 2023 in-service date is more likely and have reflected a July in-service date in our current budget. The projected schedule for Unit No. 3 primarily depends on the ~~pace~~progression of ~~system and area transitions to operations, including the completion of closure documentation necessary to support start-up~~pre-operational testing and ~~the progression of~~ start-up, ~~final component, and pre-operational testing,~~ which may be impacted by further equipment, component and/or other operational ~~failures.~~challenges.

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Ongoing or future challenges for both units also include management of contractors and vendors; subcontractor performance; ~~supervision of craft labor and related productivity; ability to attract and retain craft labor,~~ and/or related cost escalation. New challenges also may continue to arise ~~particularly~~ as ~~Units~~Unit No. 3 completes start-up and commissioning and Unit No. 4 ~~move~~moves further into ~~initial~~ testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures or components (some of which are based on

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new technology that only within the last few years began initial operation in the global nuclear industry at this scale). These challenges may result in further schedule delays and/or cost increases.

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

Co-Owner Contracts and Other Information

As a result of an increase in the total project capital cost forecast and Georgia Power’s decision not to seek recovery of its allocation of the increase in the base capital costs and the increased construction budget in connection with Georgia Power’s nineteenth Vogtle construction monitoring report (VCM 19) in 2018, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 were required to vote to continue construction. In September 2018, the Co-owners unanimously voted to continue construction of Vogtle Units No. 3 and No. 4.

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•Georgia Power will be responsible for 65.7% of construction costs, subject to exceptions such as costs that are a result of a force majeure event, that exceed the EAC in VCM 19 by $1.6 billion to $2.1 billion (resulting in up to a further $100 million of potential additional costs to Georgia Power which would save Oglethorpe up to an additional $55 million), with the remaining Co-owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests (equal to 19.0% for our 30% ownership interest).

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On June 17, 2022, we notified Georgia Power of our election to exercise the tender option and cap our capital costs in exchange for a proportionate reduction of our 30% interest in the two new units. Our decremental ownership interest will be calculated and conveyed to Georgia Power after both Vogtle units are placed in service. Based on the current project budget, our schedule assumptions and our interpretation of the Global Amendments, our project budget is $8.1 billion and we expect to transfer approximately ~~50 me~~55 ~~gawatts,~~megawatts, out of 660 megawatts, to Georgia Power. Our resulting ownership share will decline from 30% to approximately ~~28%~~27.5%. By ~~exercising~~exercising the tender option and based on current assumptions, we estimate that we will avoid incurring ~~approximate~~app~~ly $500~~roximately $535 million in construction costs associated with the project. However, if the total project ~~budget exceeds~~costs exceed the current budget, our ownership share and megawatts would be further reduced. On July 26, 2022, the City of Dalton notified Georgia Power that it had elected to exercise its tender option.

We and Georgia Power do not agree on certain aspects of the tender option, including the dollar amount that triggers our option to tender a portion of our ownership interest to Georgia Power under the tender option or the extent to which costs that are the result of a force majeure event (such as COVID-19) impact the point at which the tender option is triggered. For purposes of determining when our option to tender ~~has been~~was triggered, the Global Amendments do not exclude costs resulting from force majeure events (such as COVID-19) from the calculation of when the EAC in VCM 19 plus $2.1 billion has been reached. We and Georgia Power also do not agree on the dollar amount that ~~triggers~~triggered Georgia Power’s increased responsibility for certain construction costs as described above, and the extent to which costs that are the result of a force majeure event (such as COVID-19), impact the calculation of the point at which Georgia Power’s increased responsibility for certain construction costs as described above iswas triggered. The exclusion of costs resulting from a force majeure event (such as COVID-19) in the Global Amendments only applies to Georgia Power’s increased cost responsibility during the time period when construction costs exceed the EAC in ~~the nineteenth~~ VCM ~~report~~19 by $800 million to $2.1 billion.

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Amendments. On July 28, 2022, Georgia Power filed a counterclaim against us seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power’s related financial obligations. Based on the current project budget and Georgia Power’s interpretation of the Global Amendments, our project budget would be ~~$8.6~~$8.67 billion, ~~an increase of~~and we would incur approximately ~~$500~~$535 million of additional construction costs (excluding related financing costs) and~~we would~~ retain substantially all of our 30% interest in the additional units. On September 26, 2022, the City of Dalton filed a complaint in our lawsuit and joined our claims. On September 29, 2022, Georgia Power and MEAG reached an agreement with respect to their pending litigation.

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Units No. 3 and No. 4 (or associated financing costs) or the Georgia Public Service Commission determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Co-owners pursuant to the Global Amendment provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia Public Service Commission for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates or (iv) an incremental extension of one year or more from the seventeenth VCM report estimated in-service dates of November 2021 and November 2022 for Units No. 3 and No. 4, respectively. The schedule extensions, announced in February 2022, which reflected a cumulative delay of over a year for each unit from the schedules approved in the seventeenth VCM report, triggered the requirement for the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 to vote to continue construction, and the Co-owners unanimously voted to continue construction.

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

See “Item 1A – RISK FACTORS” in our ~~2021~~2022 Form 10-K for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.

~~Washington County Power~~

On October 24, 2022, we entered into an agreement to acquire two generating units at Washington County Power, a four-unit 660 megawatt combustion turbine generation and transmission facility located in Sandersville, Georgia, from Gulf Pacific Power, LLC, an investment fund managed by Harbert Management Corporation. The two acquired units will add approximately 330 megawatts of natural gas-fired capacity to our generation portfolio. This acquisition is subject to customary closing conditions, including regulatory approvals, and is expected to close in the fourth quarter of 2022.

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 ~~2021~~2022 Form 10-K.

On ~~June 30, 2022,~~May 11, 2023, the ~~Supreme Court of the United States issued an opinion that limits the EPA's authority~~Environmental Protection Agency (EPA) announced proposed rules to regulate and reduce greenhouse gas emissions under the Clean Air Act. The ~~Court held that~~proposed rules would affect both new and existing coal and natural gas-fired generation resources. We are reviewing the ~~Clean Air Act does not authorize~~proposed rules but the EPA to regulate the electric industry in a manner as broad as the generation shifting approach set forth in the Clean Power Plan. The EPA has announced its intent to propose a rule for existing power plants pursuant to the Clean Air Act in early 2023. The ultimate impact of the ~~Court's decision~~proposed rules cannot be determined at this time.

In ~~July 2022,~~addition, the ~~Georgia Public Service Commission approved Georgia Power’s 2022 integrated resource plan. This plan requested~~EPA proposed three other rules that will affect power plants earlier in 2023. The first, published on January 27, 2023, would tighten the ~~decertification of~~National Ambient Air Quality Standards (NAAQS) for fine particulate matter (PM2.5) from emissions sources. The second, published on March 29, 2023, would revise effluent limitation guidelines (ELG) for wastewater streams at coal-fired ~~Plant Wansley, of which we own a 30% interest, by August 31, 2022. In accordance with~~power plants and the ~~approved plan, Georgia Power retired Plant Wansley in August 2022. Beginning in 2021, we accelerated depreciation of~~third, published on April 24, 2023, would revise the ~~remaining plant in service assets associated with Plan Wansley based upon~~Mercury and Air Toxics Standards (MATS) for coal-fired power plants. We are reviewing the ~~August 2022 retirement date and created a regulatory asset to defer a portion of the accelerated depreciation expense. These deferred costs will~~proposed rules, however, their ultimate impact cannot be ~~recovered through future rates over a period ending no later than December 31, 2040. The Georgia Public Service Commission also approved Georgia Power’s modified closure proposal for the ash pond~~determined at Plant Wansley. The proposal recommended closure by removing the ash from the coal ash pond for several site-specific reasons, including available capacity at an existing on-site landfill, the retirement of Plant Wansley, beneficial use of the coal ash, and managing construction and operational risks of the previous close in place design. The Georgia Environmental Protection Department must also approve the change in closure plans. We and Georgia Power are continuing to evaluate the costs associated with the modified closure plan; however, we have received preliminary estimates from Georgia Power. At September 30, 2022, we have recognized an additional $66.7 million in coal ash related asset retirement obligations based upon these preliminary cost estimates. We expect to receive more refined estimatesthis time.

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from Georgia Power regarding closure costs and the timing of expenditures prior to year-end 2022. See Note J of Notes to Unaudited Consolidated Financial Statements for additional information regarding the retirement of Plant Wansley and the associated regulatory asset and see “Item 1 – OUR BUSINESS – REGULATION – Environmental – Coal Combustion Residuals and Effluent Limitations Guidelines” in our 2021 Form 10-K for additional information regarding the closure of the coal ash pond.

Liquidity

At ~~September 30, 2022,~~March 31, 2023, we had ~~$1.5~~$1.4 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included ~~$573~~$391 million in cash and cash equivalents, and ~~$880~~$990 million available under our $1.8 billion of committed credit arrangements, the details of which are reflected in the table below:

Committed Credit Facilities

Authorized
Amount

Available
September 30, 2022

Expiration
Date

Authorized
Amount

Available
March 31, 2023

Expiration
Date

(dollars in millions)

Unsecured Facilities:

Syndicated Line of Credit led by CFC

1,210

283

'(1)

December 2024

Syndicated Line among 12 banks led by CFC

1,210

393

'(1)

December 2024

CFC Line of Credit(2)

110

December 2023

CFC Line of Credit(2)

110

December 2023

JPMorgan Chase Line of Credit

350

347

'(3)

October 2024

JPMorgan Chase Line of Credit

350

347

'(3)

October 2024

Secured Facilities:

CFC Term Loan(2)

250

140

December 2023

CFC Term Loan(2)

250

140

December 2023

(1)This facility is dedicated to support outstanding commercial paper and the portion of this facility that was unavailable represents outstanding commercial paper at ~~September 30, 2022.~~March 31, 2023.

(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 ~~September 30, 2022,~~March 31, 2023, $2.5 million of this facility was used for letters of credit issued to provide performance assurance to third parties.

We have the flexibility to use the $1.2 billion syndicated line of credit for several purposes, including borrowing for general corporate purposes, issuing letters of credit and backing up commercial paper.

Under our commercial paper program, we are authorized to issue commercial paper in amounts that do not exceed the amount of our committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding. Due to this requirement, any commercial paper we issue will reduce the availability under the $1.2 billion syndicated line of credit. Currently, we are issuing commercial paper primarily to provide interim funding for:

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

•principal payments due under our Department of Energy-guaranteed loans, which began in February 2020 and which we intend to continue funding with commercial paper until Vogtle Unit No. 4 is placed in service, and

•costs related to the ~~Effingham plant~~Washington County acquisition.

We plan to refinance our commercial paper with long-term ~~debt, either through the issuance of first mortgage bonds, through our loan guaranteed by the Department of Energy, or through financing by the Rural Utilities Service.~~

Our loan guaranteed by the Department of Energy is our preferred source of long-term financing of eligible costs for Vogtle Units No. 3 and No. 4. See Note L of Notes to Unaudited Consolidated Financial Statements and “—Financing Activities—D~~epartment of Energy-Guaranteed Loans” for additional information regarding the Department of Energy-guaranteed loans.~~

Rural Utilities Service financing is our preferred source of long-term financing for the Effingham acquisition. We have a loan agreement with the Rural Utilities Service for this financing and we anticipate fully advancing this loan before the end of 2022.

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debt. We intend to issue first mortgage bonds to provide long-term ~~refinancing~~financing of ~~all~~the remaining construction costs ~~not financed through the Department of Energy or the Rural Utilities Service, including~~for Vogtle Units No. 3 and No. 4, refinancing of the principal payments we are currently paying under our Department of Energy-guaranteed ~~loans.~~loans, and for certain other costs not financed through the Rural Utilities Service. Rural Utilities Service financing is our preferred source of long-term financing for the Washington County acquisition. For additional information regarding the Washington County acquisition, see Note 14 in our 2022 Form 10-K.

At ~~September 30, 2022, under~~March 31, 2023, our unsecured committed lines of credit ~~we had~~provided us the ~~ability~~capacity to issue letters of credit totaling $960 million in the aggregate and ~~$740.3~~$850.3 million remained available for the issuance of letters of credit under these lines 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 Vogtle units, Department of Energy principal payments, and the ~~Effingham~~Washington County acquisition, 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 ~~September 30, 2022,~~March 31, 2023, the required minimum level was $750 million and our actual patronage capital was $1.2 billion. These agreements contain an additional covenant that limits our secured indebtedness and unsecured indebtedness, both as defined in

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the credit agreements, to $14 billion and $4 billion, respectively. At ~~September 30, 2022,~~March 31, 2023, we had ~~$11.4~~$11.8 billion of secured indebtedness and ~~$925~~$813 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 ~~September 30, 2022,~~March 31, 2023, we had seven members participating in the program and a balance of ~~$93.3~~$107.3 million remaining to be applied against future power bills.

At ~~September 30, 2022,~~March 31, 2023, we had ~~$73.3 million on deposit in the Rural Utilities Service Cushion of Credit Account, and $67.6~~$16.0 million of cash collateral posted by counterparties to our natural gas hedge program, all of which is classified as a restricted ~~investment and restricted cash, respectively.~~cash.

Financing Activities

First Mortgage Indenture. At ~~September 30, 2022,~~March 31, 2023, we had ~~$11.4~~$11.8 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 ~~2021~~2022 Form 10-K for further discussion of our first mortgage indenture.

~~Bond Financings~~. In April 2022, we issued $500 million of taxable first mortgage bonds due in 2047 to repay $493.4 million of commercial paper issued to fund a portion of the cost of constructing Vogtle Units No. 3 and No. 4. In the third quarter of 2022, we repaid $31.0 million of our Series 2017 pollution control revenue bonds prior to their final maturity. The first mortgage bonds and the pollution control revenue bonds are secured under our first mortgage indenture.

Rural Utilities Service-Guaranteed Loans. At ~~September 30, 2022,~~March 31, 2023, we had one approved Rural Utilities Service-guaranteed loan totaling $630.3 million to fund general and environmental improvements that had ~~$284.3~~$249.3 million remaining to be advanced. We began borrowing from this loan in January 2021. When advanced, the debt will be secured ratably under our first mortgage indenture. As of ~~September 30, 2022,~~March 31, 2023, we had ~~$2.5~~$2.7 billion of debt outstanding under various Rural Utilities Service-guaranteed loans. On October 18, 2022, we closed on a second Rural Utilities Service-guaranteed loan for $234.7 million to fund a portion of our cost to acquire Effingham, and we anticipate fully advancing this loan before the end of 2022.

Department of Energy-Guaranteed Loans. We have loans from the Federal Financing Bank guaranteed by the Department of Energy ~~to provide~~that provided funding for over $4.6 billion of the cost to construct our interest in Vogtle Units No. 3 and No. 4.

~~At September 30, 2022, aggregate~~ We have fully advanced the $4.6 billion available under the Department of Energy-guaranteed ~~borrowings totaled~~loans and $4.3 billion ~~including capitalized interest.~~was outstanding at March 31, 2023. All of the debt advanced under the loan guarantee agreement is secured ratably with all other debt under our first mortgage indenture. ~~We anticipate making the final advance under these loans in the fourth quarter of 2022 in the amount of $358 million.~~

In accordance with the promissory notes, we began principal repayments of our Department of Energy-guaranteed loans in February 2020. As of ~~September 30, 2022,~~March 31, 2023, we had repaid ~~$280.5~~$363.1 million under these ~~loans. If we fully advance these~~ loans weand expect to repay a total of approximately $486 million in principal on these loans by March 2024. We plan to issue first mortgage bonds to refinance the principal repaid after the in-service date of Vogtle Unit No. 4.

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 ~~2021~~2022 Form 10-K.

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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 ~~2021~~2022 Form 10-K.

Item 4. Controls and Procedures

As of ~~September 30, 2022,~~March 31, 2023, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

There have been no changes in internal control over financial reporting or other factors that occurred during the quarter ended ~~September 30, 2022~~March 31, 2023 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

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Item 1. Legal Proceedings

On June 18, 2022, after completing the dispute resolution procedures set forth in the Ownership Participation Agreement for the additional Vogtle units, we and MEAG filed separate lawsuits against Georgia Power in the Superior Court of Fulton County Georgia seeking to enforce the terms of the Global Amendments. Our lawsuit seeks declaratory judgment that the ~~cost-sharing~~cost-sharing and tender provisions of the Global Amendments have been triggered based on a VCM 19 forecast of $17.1 billion. Our lawsuit also alleges breach of contract and asserts other claims and seeks damages and injunctive relief requiring Georgia Power to track and allocate construction costs consistent with our interpretation of the Global Amendments. On July 28, 2022, Georgia Power filed a counterclaim seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power’s related financial obligations. Based on the current project budget and Georgia Power’s interpretation of the Global Amendments, our project budget would be ~~$8.6~~$8.67 billion, ~~an increase~~and we would incur approximately $535 million of ~~approximately $500 million,~~ additional construction costs (excluding related financing costs) and we would retain substantially all of our 30% interest in the additional units. On September 26, 2022, the City of Dalton filed a complaint in our lawsuit and joined our claims. On September 29, 2022, Georgia Power and MEAG reached an agreement with respect to their pending litigation.

~~The ultimate outcome of this litigation cannot be determined at this time.~~

See “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Financial Condition – Capital Requirements and Liquidity and Sources of Capital – Vogtle Units No. 3 and No. 4” for additional information regarding Vogtle Units No. 3 and No. 4.

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

Item 1A. Risk Factors

There have been no material changes to the risk factors disclosed in "Item 1A—Risk Factors" in our ~~2021~~2022 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

~~Table of Contents~~

Not Applicable.

4037

Table of Contents

Item 6. Exhibits


Number						Description
~~4.1~~						T w el f th ~~Amended and Restated Loan Contract, dated~~ ~~October~~ ~~18,~~ ~~202~~2 ~~, between Oglethorpe and the United States of America.~~
~~4.2~~						~~Eighty-Fourth~~ ~~Supplemental Indenture, dated as of~~ ~~October 18, 202~~2 ~~, made by Oglethorpe to U.S. Bank~~ ~~Trus~~t ~~Company, National~~ ~~Association, as trustee, relating to the Series 202~~2 ~~(FFB A~~E ~~48) Note, Series 202~~2 ~~(RUS A~~E ~~48) Reimbursement Note~~.
31.1						Rule 13a-14(a)/15d-14(a) Certification, by Michael L. Smith (Principal Executive Officer).
31.2						Rule 13a-14(a)/15d-14(a) Certification, by Elizabeth B. Higgins (Principal Financial Officer).
32.1						Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Michael L. Smith (Principal Executive Officer).
32.2						Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Elizabeth B. Higgins (Principal Financial Officer).
101						XBRL Interactive Data File.
104						Cover Page Interactive Data File, ~~– (embedded within the~~formatted in Inline ~~XBRL document).~~XBRL.

4138

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:

~~November 10, 2022~~May 11, 2023

By:

/s/ Michael L. Smith

Michael L. Smith
President and Chief Executive Officer

Date:

~~November 10, 2022~~May 11, 2023

/s/ Elizabeth B. Higgins

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(dollars in thousands)
Lease income	$	1,651	$	1,603	$	4,965	$	4,806


	(in millions)
		Project Budget (Tender)		Actual Costs at September 30, 2022
Construction Costs (1)		$	6,025	$	6,000
Financing Costs		1,974		1,695
Subtotal		$	7,999	$	7,695

Deferred Training Costs		49		46
Total Project Costs Before Contingency		$	8,048	$	7,741

Oglethorpe-Level Contingency		52		—

Total Contingency		$	52	$	—
Totals		$	8,100	$	7,741

(1) Construction costs are net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and $99 million in cost sharing benefits associated with the Global Amendments to the Joint Ownership Agreements.