Use these links to rapidly review the document

Table of Contents

Index To Financial Statements

PART IV

Table of Contents

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

---

FORM 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)
ý☒						ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
			For the fiscal year ended December 31, 20182020
						OR
o			OR
☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
				For the Transition Period Fromto
		Commission File No. 333-192954

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		58-1211925
Georgia			58-1211925
(State or other jurisdiction of incorporation or organization)						(I.R.S. employer identification no.)

2100 East Exchange Place Tucker, Georgia						30084-5336
Tucker, Georgia				30084-5336
(Address of principal executive offices)				(Zip Code)

Registrant's telephone number, including area code:						(770) 270-7600

Securities registered pursuant to Section 12(b) of the Act:						None
Securities registered pursuant to Section 12(g) of the Act:		None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o  ☐ No ý

 ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ý☐ Noo

☒

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

☒

Indicate by check mark whether the registrant has submitted every Interactive Data File required to be submitted and posted 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 and post such files). Yes ý☒ No o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

☐

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

Large accelerated filer ☐

Accelerated filer ☐

Non-accelerated filer ý☒

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 has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.                             ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o☐ Noý

☒

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter.The Registrant is a membership corporation and has no0 authorized or outstanding equity securities.

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 no0 authorized or outstanding equity securities.

Documents Incorporated by Reference:None

---

T

Tableable of Contents

OGLETHORPE POWER CORPORATION

2018

2020 FORM 10-K ANNUAL REPORT

Table of Contents

ITEM									Page
						PART I
1						Business			1
						Oglethorpe Power Corporation			1
						Our Power Supply Resources			9
						Our Members and Their Power Supply Resources			16
						Regulation			20
1A						Risk Factors			26
1B						Unresolved Staff Comments			36
2						Properties			37
3						Legal Proceedings			42
4						Mine Safety Disclosures			42
						PART II
5						Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			43
6						Selected Financial Data			43
7						Management's Discussion and Analysis of Financial Condition and Results of Operations			45
7A						Quantitative and Qualitative Disclosures About Market Risk			61
8						Financial Statements and Supplementary Data			64
9						Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			106
9A						Controls and Procedures			106
9B						Other Information			106
						PART III
10						Directors, Executive Officers and Corporate Governance			107
11						Executive Compensation			115
12						Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			124
13						Certain Relationships and Related Transactions, and Director Independence			125
14						Principal Accountant Fees and Services			126
						PART IV
15						Exhibits and Financial Statement Schedules			127
						Signatures			143

i

ITEM				Page
PART I
1		Business		1
		Oglethorpe Power Corporation		1
		Our Power Supply Resources		9
		Our Members and Their Power Supply Resources		15
		Regulation		19
1A		Risk Factors		26
1B		Unresolved Staff Comments		35
2		Properties		36
3		Legal Proceedings		41
4		Mine Safety Disclosures		41
PART II
5		Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		42
6		Selected Financial Data		42
7		Management's Discussion and Analysis of Financial Condition and Results of Operations		43
7A		Quantitative and Qualitative Disclosures About Market Risk		60
8		Financial Statements and Supplementary Data		62
9		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		100
9A		Controls and Procedures		100
9B		Other Information		100
PART III
10		Directors, Executive Officers and Corporate Governance		101
11		Executive Compensation		108
12		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		117
13		Certain Relationships and Related Transactions, and Director Independence		117
14		Principal Accountant Fees and Services		118
PART IV
15		Exhibits and Financial Statement Schedules		119
		Signatures		140

i

---

T

Tableable of Contents

CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING INFORMATION

This annual report on Form 10-K 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 the heading "RISK FACTORS" and in other sections of this annual report. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this annual report may not occur.

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

•

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

•

the duration and severity of the current 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;

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

•

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

•

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 construction ofconstructing two additional nuclear units at Plant Vogtle;

•

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

ii

---

Table of Contents

•

the continued availability of funding from the Rural Utilities Service;

•

increasing debt caused by significant capital expenditures;

•

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

•

actions by credit rating agencies;

•

commercial banking and financial market conditions;

•

the impact of 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;

ii

---

Table of Contents

•

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



•

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

•

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

•

early retirement of one or more 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;

•

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

•

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

•

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

•

litigation or legal and administrative proceedings and settlements;

•

our members' ability to perform their obligations to us;

•

our members' ability to offer their retail,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

---

Table of Contents

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

•

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

iii

iv

---

T

Tableable of Contents

ITEM 1.    BUSINESS

OGLETHORPE POWER CORPORATION

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 principal business is providing wholesale electric power to our members. As with cooperatives generally, we operate on a not-for-profit basis. We are one of the largest electric cooperatives in the United States in terms of revenues, assets, kilowatt-hour sales to members and, through our members, consumers served. We are also the second largest power supplier in the state of Georgia. We have 281299 employees.

Our members are local consumer-owned distribution cooperatives that provide retail electric service on a not-for-profit basis. In general, our members' customer base consists of residential, commercial and industrial consumers within specific geographic areas. Our members serve approximately 1.92.0 million electric consumers (meters) representing approximately 4.14.3 million people. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES."

Our mailing address is 2100 East Exchange Place, Tucker, Georgia 30084-5336, and telephone number is (770) 270-7600. We maintain a website atwww.opc.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are made available on this website as soon as reasonably practicable after this material is filed with the Securities and Exchange Commission. Information contained on our website is not incorporated by reference into and should not be considered to be part of this annual report on Form 10-K.

Cooperative Principles

Cooperatives like Oglethorpe are business organizations owned by their members, which are also either their wholesale or retail customers. As not-for-profit organizations, cooperatives are intended to provide services to their members at the lowest possible cost, in part by eliminating the need to produce profits or a return on equity. Cooperatives may make sales to non-members, the effect of which is generally to reduce costs to members. Today, cooperatives operate throughout the United States in such diverse areas as utilities, agriculture, irrigation, insurance and banking.

All cooperatives are based on similar business principles and legal foundations. Generally, an electric cooperative designs its rates to recover its cost-of-service and to collect a reasonable amount of revenues in excess of expenses, which constitutes margins. The margins increase patronage capital, which is the equity component of a cooperative's capitalization. These margins are considered capital contributions (that is, equity) from the members and are held for the accounts of the members and returned to them when the board of directors of the cooperative deems it prudent to do so. The timing and amount of any actual return of capital to the members depends on the financial goals of the cooperative and the cooperative's loan and security agreements. See "– First Mortgage Indenture."

Power Supply Business

We provide wholesale electric service to our members for more than half of their aggregate power requirements primarily from our fleet of generation assets but also with power purchased from other power suppliers. We provide this service pursuant to long-term, take-or-pay wholesale power contracts. The wholesale power contracts obligate our members jointly and severally to pay rates sufficient for us to recover all the costs of owning and operating our power supply business, including the payment of principal and interest on our indebtedness and to yield a minimum 1.10 margins for interest ratio under our first mortgage indenture. Our members satisfy all of their power requirements above their purchase obligations to us with purchases from other suppliers. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES –Member– Member Power Supply Resources."

Our fleet of generating units total 7,7917,862 megawatts of summer planning reserve capacity, which includes 731737 megawatts of Smarr EMC assets that we manage but do not own. Our generation portfolio includes units powered by nuclear, gas, coal, oil and water. We also supply financial and management services to support Green Power EMC's purchase of energy from 320 megawatts of renewable resources, including, low-impact hydroelectric, landfill gas, wood-waste biomass and solar facilities. See "– Relationship with Green Power EMC," "OUR POWER SUPPLY RESOURCES," "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES –Member– Member Power Supply ResourcesResources" –Smarr EMC" and"PROPERTIES and "PROPERTIES – Generating Facilities."

1

---

T

Tableable of Contents

In 2018,2020, two of our members, Jackson EMC and Cobb EMC, accounted for 14.1%15% and 13.9%13% of our total revenues, respectively. Each of our other members accounted for less than 10% of our total revenues in 2018.

2020.

Wholesale Power Contracts

The wholesale power contracts we have with each member are substantially similar and extend through December 31, 2050 and continue thereafter until terminated by three years' written notice by us or the respective member. Under the wholesale power contracts, each member is unconditionally obligated, on an express "take-or-pay" basis, for a fixed percentage of the capacity costs of each of our generation resources and purchased power resources with a term greater than one year. Each wholesale power contract specifically provides that the member must make payments whether or not power is delivered and whether or not a resource is completed, delayed, terminated, operable, operating, retired, sold, leased, transferred or is otherwise unavailable. We are obligated to use our reasonable best efforts to operate, maintain and manage our resources in accordance with prudent utility practices.

We have assigned fixed percentage capacity cost responsibilities to our members for all of our generation and purchased power resources, although not all members participate in all resources. For any future resource, we will assign fixed percentage capacity cost responsibilities only to members choosing to participate in that resource. The wholesale power contracts provide that each member is jointly and severally responsible for all costs and expenses of all existing generation and purchased power resources, as well as for approved future resources, whether or not that member has elected to participate in the resource, that are approved by 75% of the members of our board of directors, 75% of our members and members representing 75% of our patronage capital. In the event a member defaults on all or a portion of its payment obligation, the default amount is shared first among the participating members in each resource in which the defaulting member participates. If all these participating members default, each non-participating member is expressly obligated to pay a proportionate share of the default.

Under the wholesale power contracts, we are not obligated to provide all of our members' capacity and energy requirements. Individual members must satisfy all of their requirements above their purchase obligations from us from other suppliers, unless we and our members agree that we will supply additional capacity and associated energy, subject to the approval requirements described above. In 2018,2020, we supplied energy that accounted for approximately 57% of the retail energy requirements of our members. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES –Member– Member Power Supply Resources."

Under the wholesale power contracts, each member must establish rates and conduct its business in a manner that will enable the member to pay (i) to us when due, all amounts payable by the member under its wholesale power contract and (ii) any and all other amounts payable from, or which might constitute a charge or a lien upon, the revenues and receipts derived from the member's electric system, including all operation and maintenance expenses and the principal of, premium, if any, and interest on all indebtedness related to the member's electric system.

New Business Model Member Agreement

The New Business Model Member Agreement that we have with our members requires member approval for us to undertake certain activities. The agreement does not limit our ability to own, manage, control and operate our resources or perform our functions under the wholesale power contracts.

We may not provide services unrelated to our resources or our functions under the wholesale power contracts if these services would require us to incur indebtedness, provide a guarantee or make any loan or investment, unless approved by 75% of the members of our board of directors, 75% of our members, and members representing 75% of our patronage capital. We may provide any other unrelated service to a member so long as (i) doing so would not create a conflict of interest with respect to other members, (ii) the service is being provided to all members or (iii) the service has received the three 75% approvals described above.

Electric Rates

Each member is required to pay us for capacity and energy we furnish under its wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. We are required to revise our rates as necessary so that the revenues derived from our rates,

Table of Contents

together with our revenues from all other sources,

2

---

Table of Contents

will be sufficient to pay all of the costs of our system, including the payment of principal and interest on our indebtedness, to provide for reasonable reserves and to meet all financial requirements.

The formulary rate we established in the rate schedule to the wholesale power contracts employs a rate methodology under which all categories of costs are specifically separated as components of the formula to determine our revenue requirements. The rate schedule also implements the responsibility for fixed costs assigned to each member based on each member's fixed percentage capacity cost responsibilities for all of our generation and purchased power resources. The monthly charges for capacity and other non-energy charges are based on our annual budget. These capacity and other non-energy charges may be adjusted by our board of directors, if necessary, during the year through an adjustment to the annual budget. Energy charges reflect the pass-through of actual energy costs, including fuel costs, variable operations and maintenance costs and purchased energy costs. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Summary of Cooperative Operations –Rate Regulation."

Under the first mortgage indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates which are reasonably expected, together with our other revenues, to yield a margins for interest ratio for each fiscal year equal to at least 1.10. The formulary rate is intended to provide for the collection of revenues which, together with revenues from all other sources, are equal to all costs and expenses we recorded, plus amounts necessary to achieve at least the minimum 1.10 margins for interest ratio. In the event we were to fall short of the minimum 1.10 margins for interest ratio at year end, the formulary rate is designed to recover the shortfall from our members in the following year without any additional action by our board of directors.

Under our loan agreements with each of the Rural Utilities Service and Department of Energy, changes to our rates resulting from adjustments in our annual budget are generally not subject to their approval. We must provide the Rural Utilities Service and Department of Energy with a notice of and opportunity to object to most changes to the formulary rate under the wholesale power contracts. See "– Relationship with Federal Lenders." Currently, our rates are not subject to the approval of any other federal or state agency or authority, including the Georgia Public Service Commission.

First Mortgage Indenture

Our principal financial requirements are contained in the Indenture, dated as of March 1, 1997, from us to U.S. Bank National Association, as trustee (successor to SunTrust Bank), as amended and supplemented, referred to herein as the first mortgage indenture. The first mortgage indenture constitutes a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. The mortgaged property includes our owned electric generating plants, the wholesale power contracts with our members and some of our contracts relating to the ownership, operation or maintenance of electric generation facilities owned by us.

Under our first mortgage indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates which are reasonably expected, together with our other revenues, to yield a margins for interest ratio for each fiscal year equal to at least 1.10. The margins for interest ratio is determined by dividing margins for interest by total interest charges on debt secured under our first mortgage indenture. Margins for interest is the sum of:

•

our net margins (after certain defined adjustments), plus

•

interest charges on all indebtedness secured under our first mortgage indenture, plus

•

any amount included in net margins for accruals for federal or state income taxes.

Margins for interest takes into account any item of net margin, loss, gain or expenditure of any of our affiliates or subsidiaries only if we have received the net margins or gains as a dividend or other distribution from such affiliate or subsidiary or if we have made a payment with respect to the losses or expenditures. In addition, our margins include certain items that are excluded from the margins for interest ratio, such as non-cash capital credits allocation from Georgia Transmission Corporation.

Under our first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to the distribution, (i) an event of default exists under the first

Table of Contents

mortgage indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of

3

---

Table of Contents

our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however, will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is at least 30% of our total long-term debt and equities. As of December 31, 2018,2020, our equity ratio was 9.2%9.1%.

As of December 31, 2018,2020, we had approximately $8.9$10.6 billion of secured indebtedness outstanding under the first mortgage indenture. From time to time, we may issue additional first mortgage obligations ranking equally and ratably with the existing first mortgage indenture obligations. The aggregate principal amount of obligations that may be issued under the first mortgage indenture is not limited; however, our ability to issue additional obligations under the first mortgage indenture is subject to certain requirements related to the certified value of certain of our tangible property, repayment of obligations outstanding under the first mortgage indenture and payments made under certain pledged contracts relating to property to be acquired.

Relationship with Federal Lenders

Rural Utilities Service

Historically, federal loan programs administered by the Rural Utilities Service, an agency of the United States Department of Agriculture, have provided the principal source of financing for electric cooperatives. Loans guaranteed by the Rural Utilities Service and made by the Federal Financing Bank have been a major source of funding for us. However, Rural Utilities Service loan funds are subject to annual federal budget appropriations, and, due to budgetary and political pressures faced by Congress, the availability and magnitude of these loan funds cannot be assured. Congress has authorized the Rural Utilities Service to charge a fee to cover the cost of loan guarantees for baseload generation, if requested by a borrower. The Rural Utilities Service must establish a process to implement this authorization prior to making it available to borrowers. The President's budget for fiscal year 2021, which began October 2020, which begins October 2019, proposesincludes a loan program level of $5.5 billion, the same as the current program level. However, wein recent years. The new Administration has not yet proposed a budget for fiscal year 2022. We cannot predict the amount or cost of Rural Utilities Service loans that may be available to us in the future.

We have a loan contract with the Rural Utilities Service. Under the loan contract, we may have to obtain approval from the Rural Utilities Service or provide the Rural Utilities Service with a notice and an opportunity to object before we take certain actions, including, without limitation,

•

significant additions to or dispositions of system assets,

•

significant power purchase and sale contracts,

•

changes to the wholesale power contracts and the formulary rate contained in the wholesale power contracts, and

•

changes to plant ownership and operating agreements.

As of December 31, 2018,2020, we had $2.6$2.4 billion of outstanding loans guaranteed by the Rural Utilities Service and secured under our first mortgage indenture.

Department of Energy

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we entered into a $3.1 billion loan guarantee agreement with the Department of Energy in 2014, pursuant to which the Department of Energy agreed to guarantee over $3.0 billion of our obligations under a multi-advance term loan facility with the Federal Financing Bank. Proceeds of advances made under the facility will behave been used to reimburse us for a portion of certain costs of construction relating to two additional nuclear units at Plant Vogtle that are eligible for financing under the Title XVII loan guarantee program.

    Following the bankruptcy of the primary contractor for the nuclear units in 2017, our ability to request further advances under the facility was restricted pending satisfaction of certain conditions, including an amendment to the loan guarantee agreement. In September 2017, the Department of Energy issued a conditional commitment to us for $1.6 billion of additional guaranteed funding under the loan guarantee agreement.

    On March 7, 2019, we and the Department of Energy entered into an amendment and waiver to the loan guarantee agreement, which allowed us to receive an advance of $585 million which increased our total

Table of Contents

borrowings under the loan to $2.4 billion. On March 22, 2019, we and the Department of Energy executed an amended and restated loan guarantee agreement that both permits us to draw the approximately $670 million remaining under the original $3.1 billion loan and adds an additionaladded $1.6 billion commitment to the loan guarantee. In connection with the increase of the loan guarantee, we also entered into additional loan documents with the Federal Financing Bank to increase the aggregate amount available under the term loan facility.

As of December 31, 2020, we had advanced $3.6 billion in Department of Energy-guaranteed loans. In total, the Department of Energy-guaranteed loans will provide up to $4.7over $4.6 billion of long-term financing at lower interest rates than our alternative sources of financings. All advances received under this facility are secured under our first mortgage indenture.

4

---

Table of Contents

Under the loan guarantee agreement, we may have to obtain approval from the Department of Energy or provide the Department of Energy with a notice and opportunity to object before we take certain actions, including, without limitation,

•

the transfer of our undivided ownership interest in Vogtle Units No. 3 and No. 4 prior to commercial operation of both units,

•

significant dispositions of assets pledged under our first mortgage indenture,

•

changes to the wholesale power contracts and the formulary rate contained in the wholesale power contracts,

•

certain changes to plant ownership and operating agreements relating to Vogtle Units No. 3 and No. 4, and

•

agreeing to the removal or replacement of Georgia Power Company or Southern Nuclear Operating Company, Inc. in their respective roles as agents for the Co-owners in connection with the additional Vogtle units.

For additional information regarding the terms of the loan guarantee agreement, including conditions to future advances and potential repayment over a five-year period, see Note 7a of Notes to Consolidated Financial Statements. For additional information on Vogtle Units No. 3 and No. 4, see "–OUR POWER SUPPLY RESOURCES –Future– Future Power Resources –Vogtle Units No. 3 and No. 4."

Relationship with Georgia Transmission Corporation

We and our 38 members are members of Georgia Transmission Corporation (An Electric Membership Corporation), which was formed in 1997 to own and operate the transmission business we previously owned. Georgia Transmission provides transmission services to its members for delivery of its members' power purchases from us and other power suppliers. Georgia Transmission also provides transmission services to third parties. We have entered into an agreement with Georgia Transmission to provide transmission services for third party transactions and for service to our own facilities.

Georgia Transmission has rights in the integrated transmission system, which consists of transmission facilities owned by Georgia Transmission, Georgia Power Company, the Municipal Electric Authority of Georgia and the City of Dalton, Georgia. Through agreements, common access to the combined facilities that compose the integrated transmission system enables the owners to use their combined resources to make deliveries to or for their respective consumers, to provide transmission service to third parties and to make off-system purchases and sales. The integrated transmission system was established in order to obtain the benefits of a coordinated development of the parties' transmission facilities and to make it unnecessary for any party to construct duplicative facilities.

Relationship with Georgia System Operations Corporation

We, Georgia Transmission and our 38 members are members of Georgia System Operations Corporation, which was formed in 1997 to own and operate the system operations business we previously owned. Georgia System Operations operates the system control center and currently provides Georgia Transmission and us with system operations services and administrative support services. We have contracted with Georgia System Operations to schedule and dispatch our resources. We also purchase from Georgia System Operations services that it purchases from Georgia Power under the Control Area Compact, which we co-signed with Georgia System Operations. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES –Members'– Members' Relationship with Georgia Transmission and Georgia System Operations." Georgia System Operations provides support services to us in the areas of accounts payable, payroll, auditing, human resources,

Table of Contents

campus services, telecommunications and information technology at cost.

    We currently have

As of December 31, 2020, we had approximately $14.0$11.5 million of loans outstanding to Georgia System Operations, primarily for the purpose of financing capital expenditures. Georgia System Operations has an additional $7.0 million that can be drawn under one of its loans with us.

Georgia Transmission has contracted with Georgia System Operations to provide certain transmission system operation services including reliability monitoring, switching operations, and the real-time management of the transmission system.

5

---

Table of Contents

Relationship with Georgia Power Company

Our relationship with Georgia Power is a significant factor in several aspects of our business. Except for the Rocky Mountain Pumped Storage Hydroelectric Facility, Georgia Power, on behalf of itself as a co-owner and as agent for the other co-owners, is responsible for the construction and operation of all our co-owned generating facilities, including the construction of Vogtle Units No. 3 and No. 4. For further information regarding the agreements between Georgia Power and us, see "PROPERTIES – Fuel Supply," "– Co-Owners of Plants –Georgia Power Company" and "– The Plant Agreements." Georgia Power supplies services to us and Georgia System Operations to support the scheduling and dispatch of our resources, including off-system transactions. Georgia Power and our members are competitors in the State of Georgia for electric service to any new customer that has a choice of supplier under the Georgia Territorial Electric Service Act, which was enacted in 1973, commonly known as the Georgia Territorial Act (see "– Competition"). For further information regarding our members' relationships with Georgia Power, see "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Service Area and Competition.

"

Relationship with Smarr EMC

Smarr EMC is a Georgia electric membership corporation owned by 35 of our 38 members. Smarr EMC owns two combustion turbine facilities with aggregate summer planning reserve capacity of 731737 megawatts. We provide operations, financial and management services for Smarr EMC. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."

As of December 31, 2020, we had $6.5 million loan available to Smarr EMC for the purpose of funding major maintenance expenditures. Currently, no amounts have been drawn under the loan.

Relationship towith Green Power EMC

Green Power Electric Membership Corporation, owned by our 38 members, is a power supply cooperative specializing in the purchase of renewable energy for its members. Green Power EMC currently manages 120320 megawatts of renewable energy resources. By 2022, the capacity is expected to increase by at least 460264 megawatts, bringing the total capacity to more than 580584 megawatts. We supply financial and management services to Green Power EMC. SeeFor more information on the renewable resources of Green Power EMC, see "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources –Green Power EMC."

Competition

Under current Georgia law, our members generally have the exclusive right to provide retail electric service in their respective territories. However, the Georgia Territorial Act permits limited competition among electric utilities located in Georgia for sales of electricity to certain large commercial or industrial customers. The owner of any new facility may receive electric service from the power supplier of its choice if the facility is located outside of municipal limits and has a connected load upon initial full operation of 900 kilowatts or more. Our members are actively engaged in competition with other retail electric suppliers for these new commercial and industrial loads. This limited competition has given our members the opportunity to develop resources and strategies to operate in a more competitive market.

Some states have implemented varying forms of retail competition among power suppliers. No legislation related to retail competition has yet been enacted in Georgia which would amend the Georgia Territorial Act or otherwise affect the exclusive right of our members to supply power to their current service territories. However, parties have unsuccessfully sought and will likely continue to seek to advance legislative proposals that will directly or indirectly affect the Georgia Territorial Act in order to allow increased retail competition in our members' service territories. The Georgia Public Service Commission does not have the authority under Georgia law to order retail competition or amend the Georgia Territorial Act.

Table of Contents

We routinely consider, along with our members, a wide array of potential actions to meet future power supply needs, maintain competitive rates, adapt to technological innovations, including distributed generation and energy storage technologies, and respond to the evolving competitive and regulatory landscape. We cannot predict at this time the outcome of various developments that may lead to increased competition in the electric utility industry or the effect of any developments on us or our members.

6

---

Table of Contents

Regulation of greenhouse gas emissions has the potential to affect energy suppliers, including us and our competitors, differently, depending on the relative greenhouse gas emissions from a supplier's sources and the nature of the regulation. Some of our generation sources emit greenhouse gases while others emit none. Comparatively, our competitors may rely on sources that emit proportionately more or less greenhouse gases than we do. Further, many of our members' third-party suppliers also rely on generation sources that emit greenhouse gases. The terms and conditions in the contracts with these third-party suppliers would determine the extent to which any greenhouse gas regulation of these suppliers affects our members. We believe our and our members' diverse portfolios of generation facilities, including the diversity of third-party suppliers, would mitigate impacts on our and our members' competitiveness resulting from any regulation. See "REGULATION – Environmental –Carbon Dioxide Emissions and Climate Change" and "RISK FACTORS."

Many members are also providing or considering proposals to provide non-traditional products and services such as natural gas, telecommunications (including broadband) and other services. The Georgia Public Service Commission can authorize member affiliates to market natural gas but is required to condition any authorization on terms designed to ensure that cross-subsidizations do not occur between the electricity services of a member and the gas activities of its gas affiliates.

Among other conditions, for members providing broadband services through an affiliate, the Georgia Public Service Commission must approve a cost allocation manual designed to ensure that cross-subsidizations do not occur between the broadband services and the electric and/or gas services of a member or its affiliates.

Further, a member's power supply planning may include consideration of assignment of its rights and obligations under its wholesale power contract to another member or a third party. We have existing provisions for wholesale power contract assignment, as well as provisions for a member to withdraw and concurrently to assign its rights and obligations under its wholesale power contract. Assignments upon withdrawal require the assignee to have certain published credit ratings and to assume all of the withdrawing member's obligations under its wholesale power contract with us, and must be approved by our board of directors. Assignments without withdrawal are governed by the wholesale power contract and must be approved by both our board of directors and the Rural Utilities Service.

From time to time, individual members may be approached by parties indicating an interest in purchasing their systems. A member generally must obtain our approval before it may consolidate or merge with any person or reorganize or change the form of its business organization from an electric membership corporation or sell, transfer, lease or otherwise dispose of all or substantially all of its assets to any person, whether in a single transaction or series of transactions. A member may enter into such a transaction without our approval if specified conditions are satisfied, including, but not limited to, an agreement by the transferee, satisfactory to us, to assume the obligations of the member under the wholesale power contract, and certifications of accountants as to certain specified financial requirements of the transferee. The wholesale power contracts also provide that a member may not dissolve, liquidate or otherwise wind up its affairs without our approval.

Seasonal Variations

Our members' demand for energy is influenced by seasonal weather conditions. Historically, higher demand has occurred during summer and winter months than in spring and fall months. Even so, summer and winter demand historically has been lower when weather conditions are milder and higher when weather conditions are more extreme. A variety of factors affect our members' decisions whether to purchase their increased seasonal demand from us. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION –Results– Results of Operations – Factors Affecting Results." While changing weather patterns, whether resulting from greenhouse gas emissions or otherwise, could, under certain circumstances, alter seasonal weather patterns, predictions of future changes in weather patterns are inherently speculative, and we cannot make accurate conclusions about seasonality related to changes in weather patterns. Our energy revenues recover energy costs as they are incurred and also fluctuate month to month. Capacity revenues are based

Table of Contents

upon budgeted expenditures and are generally recognized and billed to our members in substantially 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 and if required, we reduce our capacity revenues and recognize a refund liability to our members. See Note 1e for information regarding revenue recognition.

Human Capital

Our success depends on the people who are part of our company. We believe that in order to deliver superior performance and maximize the value of our members’ investment, we must attract and retain the most qualified workforce available. We further believe that a strong corporation requires initiative, commitment and talent from its employees and that exceptional results evolve from diversity, continuous improvement, personal development and the contributions of many

7

---

T

Tableable of Contents

working toward common goals. We are focused on fostering innovation and leadership with our associates. We also place a strong emphasis on training because we know this ultimately leads to our associates’ professional success and the success of our company.

As of December 31, 2020, we had 299 employees. Substantially all of our associates are full-time employees and are located in Georgia. We have a formal Code of Conduct that, among other things, requires that we treat each other, and those outside our company with whom we do business, professionally and with fairness and respect. We must also conduct ourselves in a manner that promotes a favorable image of our company and a positive and professional workplace environment that promotes harmonious relationships among each other and our members.

We strive to provide fair and equitable compensation to each of our associates through a combination of competitive base pay, performance incentives, retirement plans and other benefits. The philosophy and objective of our compensation and benefits program is to establish and maintain competitive total compensation programs that will attract, motivate and retain the qualified skilled workforce necessary for our continued success. We set uniform performance goals at the corporate level. Those goals are the same for both executive officers and non-executive associates as achieving these performance incentives requires the effort and attention of associates across our business, see “EXECUTIVE COMPENSATION – Compensation Discussion and Analysis – Corporate Goals for Performance Pay.”

We are also committed to continuing efforts to enhance diversity, inclusion and equity. We are dedicated to creating and maintaining an environment that respects and values diversity, recognizes the rights of all individuals to mutual respect, and accepts others without biases based on differences of any kind.

Safety is a key concern of our management team. As an electric generation utility, we are committed to providing a safe work environment for all our associates. Our corporate goals, which are reflected in the performance pay component of total compensation, reflect a commitment to provide comprehensive safety training and education and continue to find new ways to reduce workplace hazards.

Throughout the COVID-19 pandemic, we continued operating to provide electricity to our members and the populations they serve. To protect our associates, we implemented applicable business continuity plans, including working remotely where possible; increased cleaning frequency at business locations; and implemented applicable safety and health guidelines issued by federal and state officials. In June 2020, we began a phased reopening of our corporate offices with new safety protocols intended to reduce the risk of transmission of COVID-19. To date, these measures have been effective and we continue to keep in contact with state and federal regulators to ensure the safety of our associates and reliability of our generation facilities.

As an electric cooperative, we are also committed to being a positive influence in the communities we serve. To accomplish this goal, we support and encourage our associates to participate in a variety of initiatives and activities that help the communities where we and our members live and work.

8

---

Table of Contents

OUR POWER SUPPLY RESOURCES

General

We supply capacity and energy to our members for a portion of their requirements from a combination of our fleet of generating assets and power purchased from other suppliers. In 2018,2020, we supplied approximately 57% of the retail energy requirements of our members.

Our members purchased the remaining 43% from a variety of suppliers, including Green Power EMC (renewable resources), Smarr EMC (gas-fired resources), Georgia Energy Cooperative (gas-fired resource), Southeastern Power Administration (hydroelectric power), and several power marketers and other wholesale suppliers. For more detailed information on these other purchases, see "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."

Generating Plants

Our fleet of generating units total 7,7917,862 megawatts of summer planning reserve capacity, including 731737 megawatts of Smarr EMC assets, which we manage. Our generation portfolio includes interests in nuclear, coal, natural gas, oil and hydro units. Georgia Power, the Municipal Electric Authority of Georgia (MEAG) and the City of Dalton also have interests in nine of these units at Plants Hatch, Vogtle, Wansley and Scherer. Georgia Power serves as operating agent for these nine units. Georgia Power also has an interest in the three units at Rocky Mountain, which we operate. In addition to our 31 generating units, we operate and manage six gas-fired generating units on behalf of Smarr EMC.

See "PROPERTIES" for a description of our generating facilities, fuel supply and the co-ownership arrangements. For a description of Smarr EMC's assets, see "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES –Member– Member Power Supply Resources –Smarr EMC."

Power Purchase and Sale Arrangements

We currently have no material power purchase or sale agreements.

We purchase small amounts of energy from a "qualifying facility" under the Public Utility Regulatory Policies Act of 1978 under a contract that will terminate on March 31, 2019. Under a waiver order from the Federal Energy Regulatory Commission, we historically made all purchases the members would have otherwise been required to make under the Public Utility Regulatory Policies Actsupply financial and we were relieved of our obligation to sell certainmanagement services to "qualifying facilities" so long as the members make those sales. In 2018, our purchases from this qualifying facility provided less than 0.1% of the energy we supplied to our members. Under their wholesale power contracts, the members may now make such purchases instead of us.

    We managesupport Green Power EMC's purchase of energy from 120320 megawatts of renewable resources.resources, plus an additional 264 megawatts under contract to be constructed. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources –Green Power EMC."

We have interchange, transmission and/or short-term capacity and energy purchase or sale agreements with a number of power marketers and other power suppliers. The agreements provide variously for the purchase and/or sale of capacity and energy and/or for the purchase of transmission service.

A recent filing at the FERC proposed a Southeast Energy Exchange Market (SEEM) that includes many of the electric service providers in the Southeast, including us. SEEM is an extension of the existing bilateral market where participants would use an automated, intra-hour energy exchange to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission. If approved by the FERC, SEEM is expected to begin service in early 2022. The ultimate outcome of this matter cannot be determined at this time.

Future Power Resources

Plant Vogtle Units No. 3 and No. 4

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

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

9

---

Table of Contents

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

Table of Contents

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'days’ written notice.

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

Cost and Schedule

Our current budget for our 30% ownership interest in Vogtle Units No. 3 and No. 4 is $7.5 billion, which includes capital costs, allowance for funds used during construction, our allocation of the project-level contingency and a separate Oglethorpe-level contingency. As of December 31, 2020, our total investment in the additional Vogtle units was approximately $6.0 billion. 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. The Georgia Public Service Commission approved in-service dates for Vogtle Units No. 3 and No. 4 are November 2021 and November 2022, respectively.

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

The August 2018 project-level budget included an $800 million construction contingency estimate, of which our 30% interest was $240 million. As of June 30, 2020, assignments of contingency exceeded the 2018 construction contingency estimate by $75 million (of which our 30% interest was $23 million) and Georgia Power established $250 million of additional construction contingency (of which our 30% interest is $75 million). During the third and fourth quarters of 2020, this construction contingency, plus an additional $10 million (of which our 30% interest was $3 million) was assigned to the base capital cost forecast. Assignment of contingency during 2020 addressed cost risks related to construction productivity, including the April 2020 reduction in workforce designed to mitigate impacts of the COVID-19 pandemic described below; other COVID-19 impacts; craft labor incentives; additional resources for supervision, field support, project management, initial test program, start-up, engineering support and operations and maintenance support; subcontracts; and procurement, among other factors. These factors continue to represent further potential cost risk to the project; therefore Georgia Power established $375 million of additional contingency as of December 31, 2020 (of which our 30% interest is $112.5 million). Georgia Power has stated its expectation to allocate the remainder of this project-level contingency by completion of the project.

The project-level contingency is separate and in addition to our Oglethorpe-level contingency. The Oglethorpe-level contingency, which we have carried at various levels since the beginning of the project, was designed to cover potential cost, schedule, and financing risks associated with our share of the project which may not be covered by project-level contingencies. As construction progresses, the Oglethorpe-level contingency may continue to fluctuate as it represents the difference between known project-level costs and contingencies and our total budget of $7.5 billion. At the end of the project,

10

---

Table of Contents

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. The table below shows our project budget and actual costs through December 31, 2020 for our 30% interest in the project.

			(in millions)
			Project Budget						Actual Costs at December 31, 2020						Remaining Project Budget
Construction Costs (1)			$	5,559					$	4,754					$	805
Financing Costs			1,578						1,259						319
Total Costs			$	7,137					$	6,013					$	1,124
Project-Level Contingency			$	113					$	0					$	113
Oglethorpe-Level Contingency			250						0						250
Total Contingency			$	363					$	0					$	363
Totals			$	7,500					$	6,013					$	1,487
(1) Construction costs are net of $1.1 billion received from Toshiba Corporation under a Guarantee Settlement Agreement.

In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures. In April 2020, Georgia Power, acting for itself and as agent for the other Co-owners, announced a reduction in workforce at Vogtle Units No. 3 and No. 4 and began reducing the then-existing site workforce by approximately 20%. This reduction in workforce was a mitigation action intended to address ongoing challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic on the Vogtle Units No. 3 and No. 4 workforce and construction site by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. Since April 2020, the number of active cases of COVID-19 at the site has fluctuated and continues to impact productivity levels and pace of activity completion.

From November 2020 through January 2021, the number of active COVID-19 cases at the site increased significantly, consistent with a national rise in cases, which further impacted productivity and the pace of activity completion. Although still present, this spike in cases has since abated into February and early March. The incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated by Georgia Power to be between $325 and $415 million (of which our 30% interest is $98 to $125 million) and is included in the project budget. As described previously, Georgia Power included estimated costs associated with near-term COVID-19 mitigation actions and related impacts on construction productivity in the additional project-level contingency established as of December 31, 2020. The continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Vogtle Units No. 3 and No. 4.

The project continues to face challenges, exacerbated by this recent rise in COVID-19 cases, including, but not limited to, higher than expected absenteeism; overall construction and subcontractor labor productivity; system turnover and testing activities; and electrical equipment and commodity installation.

As a result of these factors, overall production levels were not achieved at the levels anticipated, contributing to the December 31, 2020 allocation of construction contingency and increase in total project capital cost forecast described previously. Southern Nuclear has further extended certain milestone dates, including the start of hot functional testing and fuel load for Unit No. 3. The Unit No. 3 schedule is challenged, and while the ability to achieve the November 2021 regulatory in-service date remains a target for Southern Nuclear, we believe a delay is likely which could add a month or more to the Unit No. 3 in-service date. As Unit No. 3 approaches hot functional testing, key factors impacting the schedule include both the pace of work package completion and system turnovers, and required construction remediation work.

11

---

Table of Contents

Achievement of the November 2022 regulatory in-service date for Unit No. 4 primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, being added and maintained. In the event that there is any schedule extension beyond the November 2021 and November 2022 regulatory in-service dates for Units No. 3 and No. 4, respectively, the Oglethorpe-level contingency level in our current $7.5 billion budget is expected to be sufficient to withstand up to a 4-month delay for Unit No. 3 and a 3-month delay for Unit No. 4. Any further delays beyond these extended dates are expected to impact our cost by approximately $55 million per month for both units and approximately $25 million per month for Unit No. 4 only, including financing costs.

As construction, including subcontract work, continues and testing and system turnover activities increase, risks remain that challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures or components (some of which are based on new technology that has only within the last few years began initial operation in the global nuclear industry at this scale), any of which may require additional labor and/or materials; or other issues could arise and further impact the projected schedule and estimated cost.

There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. Findings from such inspections could require additional remediation and/or further Nuclear Regulatory Commission oversight. In addition, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. On August 10, 2020, the Atomic Safety Licensing Board rejected the Blue Ridge Environmental Defense League’s May 11, 2020 petition challenging a license amendment request. The staff of the Nuclear Regulatory Commission has issued the requested amendment to the combined construction and operating license for Vogtle Unit No. 3. The Blue Ridge Environmental Defense League appealed the Atomic Safety Licensing Board’s decision to the Nuclear Regulatory Commission, which was denied on December 22, 2020. The Blue Ridge Environmental Defense League also filed a motion to reopen the proceeding and submitted an amended contention on December 7, 2020, which is pending before the Nuclear Regulatory Commission.

Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the inspections, tests, analyses, and acceptance criteria documentation for each unit and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections, tests, analyses, and acceptance criteria, 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).

On December 21, 2017,January 11, 2018, the Georgia Public Service Commission took a series of actionsissued an order related to the construction of Vogtle Units No. 3 and No. 4 and issued its related order on January 11, 2018.4. Among other actions, the Public Service Commission (i) accepted Georgia Power'sPower’s recommendation to continue construction of Vogtle Units No. 3 and No. 4, with Southern Nuclear serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain conditions change and assumptions upon which Georgia Power's seventeenth Vogtle construction monitoring (VCM) report are based do not materialize, the Public Service Commission reserved the right to reconsider the decision to continue construction. Third parties have filed two petitions with the Fulton County Superior Court appealingseeking judicial review of the Georgia Public Service Commission'sCommission’s January 11, 2018 order. On December 21, 2018,The petitions were dismissed by the Superior Court granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019, those parties appealed that decision toand

12

---

Table of Contents

later remanded by the Georgia Court of Appeals. Georgia Power has stated that it believesThe Fulton County Superior Court issued another order dismissing the appeal has no merit; however, an adverse outcome in the appeal combined with subsequent adverse action by the Public Service Commission could have a material impact on our financial conditionpetitions and, results of operations.

    In 2018, Georgia Power advised us that it became aware that the estimated future Vogtle project costs were projected to exceed the corresponding budgeted amounts included in its seventeenth VCM report. Upon discovery of these variances, the Co-owners requested Southern Nuclear perform a full cost analysis and reforecast the cost to complete the project and engaged a third party to independently assess this analysis, forecast, and existing project controls for identifying budget variances. Following this analysis, Georgia Power proposed an increased construction budget and included a revised estimate to complete in its nineteenth VCM report filed with the Georgia Public Service Commission in August 2018.2020, the petitioners withdrew their notice of appeal. This revised estimate

Table of Contents

included an approximate $1.5 billion increase in capital costs (our 30% sharematter is approximately $450 million) and a project-level contingency in an amount of $800 million (our 30% share is $240 million). The increase in the revised budget is primarily attributable to Bechtel and subcontractor construction costs, including craft labor incentives, as well as expenses for project management, oversight and support. The scheduled in-service dates of November 2021 and November 2022 for Vogtle Units No. 3 and No. 4, respectively, did not change in connection with these budget revisions.

    Further, Georgia Power informed the Public Service Commission in its nineteenth VCM report that it did not intend to seek rate recovery for its proportionate share of the additional capital costs identified in that report. now concluded.

As a result of an increase in the total project capital cost forecast and Georgia Power'sPower’s decision not to seek rate recovery of its allocation of thesethe increase in the base capital costs and the increased construction budget in connection with Georgia Power’s 19th Vogtle construction monitoring (VCM) report 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. In connection with our vote to continue construction, we approved a revised budget of $7.5 billion for our 30% ownership interest. The impact of the additional project costs on our budget was substantially mitigated by nearly $500 million of contingency included in our prior budget. As with our prior budgets and consistent with our conservative budget practices, our revised budget includes a separate Oglethorpe-level contingency amount in addition to capital costs, allowance for funds used during construction, and our allocation of the project-level contingency. 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. As of December 31, 2018, our total investment in the additional Vogtle units was approximately $3.9 billion.

    As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly and/or installation and testing, including any required engineering changes, of plant systems, structures and components; or other issues could further impact the projected schedule and cost. Monthly construction production targets required to maintain the current project schedule will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be retained and deployed.

    Georgia Power and Southern Nuclear are in the process of validating recent construction progress in comparison to the projected schedule and verifying and updating quantities of commodities remaining to install, labor productivity, and forecasted staffing needs. This verification process, led by Southern Nuclear, is expected to be completed during the second quarter of 2019. Although the verification is not complete, we currently do not anticipate any material changes to our project budget of $7.5 billion or the Public Service Commission approved in-service dates of November 2021 and November 2022 as a result of this verification process. However, the current schedule being utilized to manage construction at the Vogtle site, which targets in-service dates in advance of November 2021 and November 2022, may be adjusted to reflect updated information provided by the verification process. The ultimate impact on cost and schedule, if any, will not be known until the verification process is completed. Georgia Power has stated that it is required to report the results and any project impacts to the Public Service Commission by May 15, 2019.

    There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the timely resolution of inspections, tests, analyses, and acceptance criteria and the related approvals by the Nuclear Regulatory Commission, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners.

Table of Contents

    In late 2018, the first four nuclear units to utilize Westinghouse's AP1000 technology began commercial operation in China. Recently, one of these units reportedly experienced a failure of one of its four reactor coolant pumps and is not operating pending determination of the cause of the failure and replacement of the pump. The other three nuclear units remain in operation.

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'sMEAG’s wholly-owned subsidiaries MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, and MEAG Power SPVP, LLC that mitigated 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'sCo-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:

Table of Contents

As a generator owner and generator operator, we are subject to certain of these mandatory reliability standards. We have established a comprehensive formal compliance program to establish, monitor, maintain and enhance our commitment to electric reliability compliance. This program includes comprehensive cyber security elements designed to protect and preserve our critical information and energy infrastructure systems. Although we intend to comply with all currently effective and enforceable reliability standards, we cannot provide assurance that we will always be in compliance. We are obligated to maintain and retain evidence of compliance with specific requirements. SERC Reliability Corporation also regularly monitors us for compliance with reliability standards. We expect that existing reliability standards will continue to be refined and that new reliability standards will be developed or adopted.

Table of Contents

Unlike most investor-owned utilities, electric cooperatives cannot issue equity securities and therefore rely almost entirely on debt financing.

    In connection with our share of the cost to construct the additional units at Plant Vogtle, in 2014 we obtained a loan from the Federal Financing Bank and a related loan guarantee from the Department of Energy to fund up to $3.1 billion of eligible project costs. Following Westinghouse's bankruptcy in 2017, our ability to request further advances under this loan had been restricted pending satisfaction of certain conditions. On March 7, 2019, we and the Department of Energy entered into an amendment and waiver to the loan guarantee agreement, which allowed us to receive an advance of $585 million, increasing our total borrowings under the original loan to $2.4 billion. On March 22, 2019, we obtained an additional $1.6 billion loan from the Federal Financing Bank and amended and restated the loan guarantee agreement with the Department of Energy to increase the aggregate funding amount available to us to $4.7 billion of eligible project costs and permit us to advance the remaining amount available under the original loan.

    Access to the committed funds under these loans requires us to meet certain conditions related to our business and the Vogtle project and also requires certain third parties related to the Vogtle project to comply with certain laws. In addition, the occurrence of certain adverse events would give the Department of Energy discretion to require that we repay all amounts outstanding under the loan guarantee agreement over a five-year period. In the event that we are unable to draw the full amount of these loans or are required to repay amounts outstanding over a five year period, we expect that we would finance those project expenditures in the capital markets which would likely be at a higher cost.

    See Note 7a of Notes to Consolidated Financial Statements for additional information about the terms of the loan guarantee agreement and related conditions.

    Historically, we relied on federal loan programs guaranteed by the Rural Utilities Service, a branch of the U.S. Department of Agriculture, in order to meet a significant portion of our long-term financing needs, typically at a cost that was lower than traditional capital markets financing. However, the availability and magnitude of Rural Utilities Service funding levels are subject to the annual federal budget appropriations process, and therefore are subject to uncertainty because of budgetary and political pressures faced by Congress. If the amount of this funding available to us in the future is decreased or eliminated, we would seek alternative sources of debt financing in the traditional capital markets which would likely be at a higher cost.

    Our access to both short-term and long-term capital market funding remains an important factor in our financing plans, particularly in light of the significant amount of projected capital investment. We have entered into multiple credit agreements that provide significant short-term and medium-term liquidity and have successfully accessed the capital markets in the past to satisfy our long-term borrowing needs. We believe that we will be able to maintain sufficient access to the short-term and long-term capital markets based on our current credit ratings. However, our credit ratings reflect the views of the rating agencies, which could change at any point in the future. If one or more rating agencies downgrade us and potential investors take a similar view, our borrowing costs would likely increase and our potential pool of investors, funding sources and liquidity could decrease. In addition, if our credit ratings are lowered below investment grade, collateral calls may be triggered under certain agreements and contracts which would decrease our available liquidity.

    Our borrowing costs are also affected by prevailing interest rates. If interest rates have increased at the time we issue fixed rate debt or reset the interest rates on our variable rate debt, our interest costs will increase and our financial condition and future results of operations could be adversely affected.

    In addition, market disruptions could constrain, at least temporarily, lenders' willingness or ability to perform their obligations under existing credit agreements and our ability to access additional sources of capital on favorable terms or at all. These disruptions include:

•

instability in domestic or foreign financial markets;



•

a tightening of lending and lending standards by banks and other credit providers;



•

the overall health of the energy and financial industries;



•

economic downturns or recessions;



•

negative events in the energy industry, such as the bankruptcy of an unrelated energy company or the occurrence of a significant natural disaster;

Table of Contents

•

war or threat of war; and



•

terrorist attacks or threatened attacks on our facilities or the facilities of unrelated energy companies.

    Further, an increasing number of lenders and investors are taking into account environmental, social and corporate governance criteria when making lending and investment decisions. Although we are not aware of any instances where our access to capital was limited due to these criteria, such considerations could potentially limit the number of lenders or investors who are willing to lend capital to us or other utility companies in the future.

    If our ability to access capital becomes significantly constrained or more expensive for any of the reasons stated above or for any other reason, our ability to finance ongoing capital expenditures could be limited and our financial condition and future results of operations could be adversely affected.

Our capital expenditures, particularly in relation to the additional units under construction at Plant Vogtle, are projected to be significant and will continue to increase our debt, which is constraining certain of our financial metrics and may also adversely affect our credit ratings which would likely increase our borrowing costs and could decrease our access to capital.

    In order to meet the energy needs of our members, we are in the midst of a multi-year capital spending plan to fund our participation in the construction of Vogtle Units No. 3 and No. 4. Our current project budget for the additional Vogtle units is $7.5 billion, and our investment as of December 31, 2018 was $3.9 billion. As we have financed generation assets in the past, we are relying on external funding to finance this project. As of December 31, 2018, we had $9.3 billion of long-term debt outstanding, an increase of $5.0 billion since 2009, when construction of the new Vogtle units commenced. At the completion of the Vogtle expansion, we expect that the amount of our outstanding debt will be approximately $12.0 billion. In addition to the increase in absolute dollars, our debt has been increasing as a percentage of our total capitalization, which has constrained our equity ratio. Furthermore, our debt service payment obligations have increased, which has affected certain other financial metrics. Increased debt and the related impacts on our financial metrics could negatively impact our credit ratings. Any downgrade in our credit ratings would likely increase our borrowing costs and could decrease our access to the credit and capital markets.

    Beginning in 2009, in order to increase financial coverage during a period of generation expansion, our board of directors approved budgets to achieve margins for interest ratios greater than the minimum 1.10 margins for interest ratio required under our first mortgage indenture. We have achieved the board-approved margins for interest ratio each year, and for 2019 our board of directors again approved a margins for interest ratio of 1.14.

Our costs of compliance with environmental laws and regulations are significant and have increased in recent years. Potential future environmental laws and regulations, including those designed to address air and water quality, greenhouse gas emissions, including carbon dioxide, and other matters, may result in significant increases in compliance costs or operational restrictions.

    As with most electric utilities, we are subject to extensive federal, state and local environmental requirements which regulate, among other things, air pollutant emissions, wastewater discharges and the management of hazardous and solid wastes. Compliance with these requirements requires significant expenditures for the installation, maintenance and operation of pollution control equipment, monitoring systems and other equipment or facilities. Through 2018, we have spent approximately $1.1 billion on capital expenditures at our facilities to achieve and maintain compliance with Georgia's "multi-pollutant rule" and EPA's MATS, two air quality control regulations that have had a significant impact on our business to date. In addition, as of December 31, 2018, we have spent approximately $185 million on capital expenditures related to the coal ash handling and effluent limitation guidelines described below, and expect to spend approximately $150 million more in the near future.

    Although the current administration has relaxed certain federal regulations, potential future legislation or regulations, including those relating to greenhouse gas emissions, including carbon dioxide, or renewable or clean energy may create new requirements and operational hurdles. More stringent or new standards may require us to modify the design or operation of existing facilities and could result in significant increases in the cost of electricity or decreases in the amount of energy (due to operational constraints)

Table of Contents

provided to our members. Two examples of current and potential regulations are discussed below.

    The EPA has determined that carbon dioxide and other greenhouse gases are regulated pollutants under the Clean Air Act. As a result of this determination, in October 2015 the EPA published final rules regarding emissions of carbon dioxide from certain fossil fuel-fired electric generating units. One of the rules, referred to as the "Clean Power Plan," established guidelines for states to develop plans to limit emissions of carbon dioxide from certain existing fossil fuel-fired electric generating units. The guidelines and standards set forth in the Clean Power Plan could impose future operational restrictions and substantial costs on our coal-fired units. In February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan pending the resolution of litigation challenging the rule. In October 2017, the EPA proposed a rule to rescind the Clean Power Plan and in August 2018, the EPA issued a proposed Affordable Clean Energy (ACE) rule to replace the Clean Power Plan. The final ACE rule is expected in spring of 2019. It is likely that the EPA's actions to replace the Clean Power Plan will be challenged. If the Clean Power Plan is not ultimately replaced and survives litigation challenging the rule, we anticipate that some of the policy approaches it sets forth could have significant negative consequences for the economy and electric system in Georgia and the nation.

    Even if the Clean Power Plan is replaced by the ACE rule, we expect that additional efforts to limit the emissions of greenhouse gases, including carbon dioxide, will continue. For example, the U.S. House of Representatives has introduced legislation aimed at reducing greenhouse gas or other emissions from power plants; although such legislation is currently unlikely to be adopted. The timing, cost and effect of any future laws or regulations attempting to reduce greenhouse gas emissions are uncertain; however, certain laws or regulations could impose substantial costs on our business and operational restrictions on certain of our generating facilities, particularly our coal-fired units.

    In April 2015, the EPA published a final rule to regulate coal combustion residuals from electric utilities as solid wastes. Georgia Power has announced that ash ponds at each of its Georgia coal-fired facilities, including our co-owned facilities, will cease receiving new coal ash in early 2019 and that closure activities for the ash ponds at Plants Wansley and Scherer are initially estimated to be completed in 2026 and 2031, respectively. Currently, we and Georgia Power anticipate utilizing advanced engineering methods to close the existing ash ponds in place and continue to review the ultimate cost of this rule on our co-owned coal facilities. In September 2015, the EPA also finalized a rule to revise the effluent limitations guidelines that apply to certain wastewater discharges from nuclear and fossil fuel-fired steam electric power plants. We have already begun investing in facility upgrades to meet the coal combustion residuals rule and effluent limitations guidelines and estimate our total capital cost for compliance to be $325 million to $350 million. Expenditures for the settlement of related asset retirement obligations are approximately $400 million to $550 million (in year of expenditure dollars).

    Litigation relating to environmental issues, including claims of property damage, personal injury or common law nuisance caused by plant emissions, including greenhouse gases, wastewater discharges or solid waste disposal, including coal combustion residuals, is generally increasing throughout the U.S. Likewise, actions by private citizen groups to enforce environmental laws and regulations are also becoming increasingly prevalent.

    While we will continue to exercise our best efforts to comply with all applicable regulations, there can be no assurance that we will always be in compliance with all current and future environmental requirements. Failure to comply with existing and future requirements, even if this failure is caused by factors beyond our control, could result in civil and criminal penalties and could cause the complete shutdown of individual generating units not in compliance with these regulations. Any additional federal or state environmental restrictions imposed on our operations could result in significant additional compliance costs, including capital expenditures. Such costs could affect future unit retirement and replacement decisions and may result in significant increases in the cost of electric service. The cost impact of future legislation, regulation, judicial interpretations of existing laws or regulations, or international obligations will depend upon the specific requirements thereof and cannot be determined at this time. For additional information regarding certain environmental regulations to which our business is subject, see "BUSINESS –REGULATION – Environmental."

Table of Contents

We own and are participating in the construction of nuclear facilities which give rise to environmental, regulatory, financial and other risks.