Oglethorpe Power Earnings 2019-12-31
OPC 10K Annual Report
| Balance Sheet | Income Statement | Cash Flow |
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| Ticker | M Cap | Assets | Liab | Rev | G Profit | Net Inc | EBITDA | EV | G Margin | EV/EBITDA | ROA |
| BMNM | 210 | 183 | 12 | 0 | 0 | 7 | -9 | 0% | -1.3 | 0% | |
| CHTA | 0 | 0 | 0 | 0 | -0 | -0 | -0 | 0.0 | |||
| NYB | 51,247 | 44,453 | 0 | 0 | 457 | 1,268 | -1,732 | -1.4 | 1% | ||
| AHFC | 76,980 | 59,302 | 664 | 0 | 1,333 | 7,281 | -1,414 | 0% | -0.2 | 2% | |
| TOMI | 9 | 7 | 4 | 3 | -2 | -1 | -1 | 64% | 1.1 | -20% | |
| MOG | 3,114 | 1,792 | 2,905 | 816 | 180 | 358 | 741 | 28% | 2.1 | 6% | |
| FWDR | 0 | 0 | 0 | 0 | -0 | -0 | 0 | -0.7 | -142,637% | ||
| HBUV | 3 | 4 | 0 | 0 | 0 | 0 | -0 | 0% | -0.1 | 7% | |
| SDSP | 151 | 64 | 277 | 15 | 12 | 16 | 16 | 5% | 1.0 | 8% | |
| CFT | 350 | 4 | 0 | 0 | 56 | 56 | -79 | -1.4 | 16% | ||
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
_____________________________________________
FORM 10-K
| (Mark One) | ||||||||
| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||||||
For the fiscal year ended | ||||||||
| OR | ||||||||
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||||||
For the Transition Period From ________________ to ________________
Commission File No. 333-192954
_____________________________________________
(An Electric Membership Corporation)
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation or organization) | (I.R.S. employer identification no.) | ||||
| (Address of principal executive offices) | (Zip Code) | ||||
| Registrant's telephone number, including area code: | ( | ||||
| 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 ☐ No ☒
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 ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted 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 ☒ No ☐
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. ☒
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 ☐ | 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. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No☒
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 no 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 no authorized or outstanding equity securities.
Documents Incorporated by Reference: None
OGLETHORPE POWER CORPORATION
2019 FORM 10-K ANNUAL REPORT
Table of Contents
| ITEM | Page | ||||||||||
| PART I | |||||||||||
| PART II | |||||||||||
| PART III | |||||||||||
| PART IV | |||||||||||
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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;
•a decision by Georgia Power Company to cancel the additional Vogtle units or a decision by more than 10% of the co-owners of the additional Vogtle units not to proceed with the construction of the additional Vogtle units upon the occurrence of certain material adverse events;
•decisions made by the Georgia Public Service Commission in the regulatory process related to the two additional units at Plant Vogtle;
•our access to capital, the cost to access capital, and the results of our financing and refinancing efforts, including availability of funds in the capital markets;
•our ability to receive advances under the U.S. Department of Energy loan guarantee agreement for construction of two additional nuclear units at Plant Vogtle;
•the occurrence of certain events that give the Department of Energy the option to require that we repay all amounts outstanding under the loan guarantee agreement with the Department of Energy over a five-year period and the Department of Energy's decision to require such repayment;
•the continued availability of funding from the Rural Utilities Service;
•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;
•increasing debt caused by significant capital expenditures;
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•unanticipated changes in capital expenditures, operating expenses and liquidity needs;
•actions by credit rating agencies;
•commercial banking and financial market conditions;
•risks and regulatory requirements related to the ownership and construction of nuclear facilities;
•adequate funding of our nuclear decommissioning trust funds including investment performance and projected decommissioning costs;
•continued efficient operation of our generation facilities by us and third-parties;
•the availability of an adequate and economical supply of fuel, water and other materials;
•reliance on third-parties to efficiently manage, distribute and deliver generated electricity;
•acts of sabotage, wars or terrorist activities, including cyber attacks;
•changes in technology available to and utilized by us, our competitors, or residential or commercial consumers in our members' service territories, including from the development and deployment of distributed generation and energy storage technologies;
•early retirement of one or more of our co-owned coal facilities;
•the inability of counterparties to meet their obligations to us, including failure to perform under agreements;
•our members' ability to perform their obligations to us;
•our members' ability to offer their retail, 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;
•catastrophic events such as fires, earthquakes, floods, droughts, hurricanes, explosions, pandemic health events, such as influenza, or similar occurrences;
iii
•the duration and severity of the current coronavirus (COVID-19) pandemic and its impact on our business operations, construction projects and members and their service territories; and
•other factors discussed elsewhere in this annual report and in other reports we file with the SEC.
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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 299 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 1.9 million electric consumers (meters) representing approximately 4.2 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 at www.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 Power Supply Resources."
Our fleet of generating units total 7,863 megawatts of summer planning reserve capacity, which includes 738 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 160 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 Power Supply Resources" – and "PROPERTIES – Generating Facilities."
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In 2019, two of our members, Jackson EMC and Cobb EMC, accounted for 14.4% and 13.8% of our total revenues, respectively. Each of our other members accounted for less than 10% of our total revenues in 2019.
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 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 2019, we supplied energy that accounted for approximately 58% of the retail energy requirements of our members. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – 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, together with our revenues from all other sources,
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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 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
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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, 2019, our equity ratio was 9.4%.
As of December 31, 2019, we had approximately $9.7 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. The President's budget for fiscal year 2021, which begins October 2020, proposes a loan program of $5.5 billion, the same as the current program level. However, 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, 2019, we had $2.5 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 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 have 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.
On March 22, 2019, we and the Department of Energy executed an amended and restated loan guarantee agreement that added $1.6 billion to the loan guarantee. In connection with the increase of the loan guarantee, we 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, 2019, we had advanced $3.0 billion in Department of Energy-guaranteed loans. In total, the Department of Energy-guaranteed loans will provide over $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.
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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 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' 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, campus services, telecommunications and information technology at cost.
As of December 31, 2019, we had approximately $11.8 million of loans outstanding to Georgia System Operations, primarily for the purpose of financing capital expenditures. Georgia System Operations has an additional $4.5 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.
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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 capacity of 738 megawatts. We provide operations, financial and management services for Smarr EMC. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."
In March 2020, we made a $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 with 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 160 megawatts of renewable energy resources. By 2022, the capacity is expected to increase by at least 424 megawatts, bringing the total capacity to more than 584 megawatts. We supply financial and management services to Green Power EMC. For 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.
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.
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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 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 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.
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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 2019, we supplied approximately 58% of the retail energy requirements of our members. Our members purchased the remaining 42% 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 7,863 megawatts of summer planning reserve capacity, including 738 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 Power Supply Resources – Smarr EMC."
Power Purchase and Sale Arrangements
We currently have no material power purchase or sale agreements.
We supply financial and management services to support Green Power EMC's purchase of energy from 160 megawatts of renewable resources, plus an additional 424 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.
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 was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, Westinghouse agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle.
Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code.
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Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technical support and staff augmentation on a time and materials cost basis. The Services Agreement provides that it will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days’ written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, pursuant to which Bechtel serves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel’s performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events.
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, 2019, our total investment in the additional Vogtle units was approximately $4.9 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.
The current project-level budget includes an $800 million construction contingency estimate, of which our 30% interest is $240 million. As of December 31, 2019, approximately $307 million of this project-level contingency, or $92 million for our 30% interest, was allocated to the base capital cost forecast for cost risks including, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. 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.
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 commodity installation, system turnovers and workforce statistics.
In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the total estimated project capital cost forecast for Vogtle Units No. 3 and No. 4 and did not change the regulatory-approved in-service dates of November 2021 for Unit No. 3 and November 2022 for Unit No. 4. As part of this process, Southern Nuclear also established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain margin to the regulatory-approved in-service dates. The project has faced challenges with the April 2019 aggressive strategy targets, including, but not limited to, electrical and pipefitting labor productivity and closure rates for work packages, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.
In February 2020, Southern Nuclear updated its cost and schedule forecast, which did not change the projected overall capital cost forecast and confirmed the regulatory-approved in-service dates. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near term milestone dates. Achieving completion in advance of the regulatory-approved in-service dates relies on meeting increased monthly production target values during 2020. Specifically, existing craft, including subcontractors, construction productivity must improve and be sustained above historical average levels, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be maintained, and additional supervision and other field support resources must be retained. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates.
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In February 2020, Southern Nuclear also provided a schedule benchmark that forecasts production levels and adjusts project milestones to align with the regulatory-approved in-service dates. We believe the production levels and timeframes in this benchmark provide reasonable assurance that Units No. 3 and No. 4 will meet the regulatory-approved in-service dates of November 2021 and November 2022, respectively.
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 craft labor productivity, particularly in the installation of electrical and mechanical 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), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and further impact the projected schedule and estimated cost.
Additionally, the current coronavirus (COVID-19) pandemic may disrupt or delay construction, testing, supervisory and support activities at Vogtle Units No.3 and No. 4. Southern Nuclear has implemented policies and procedures designed to mitigate the risk of transmission at the construction site, including limiting exposure of individuals who are showing symptoms consistent with coronavirus, being tested for coronavirus or in close contact with such persons, self-quarantine and additional precautionary measures. It is too early to determine what impact, if any, suspected or actual cases may have on the current construction schedule or budget.
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 submittal by Southern Nuclear of inspections, tests, analyses, and acceptance documentation for each unit and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support Nuclear Regulatory Commission 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 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 January 11, 2018, the Georgia Public Service Commission issued an order related to the construction of Vogtle Units No. 3 and No. 4. Among other actions, the Public Service Commission (i) accepted Georgia Power’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. Third parties have filed two petitions with the Fulton County Superior Court appealing the Georgia Public Service Commission’s January 11, 2018 order. On December 21, 2018, the Superior Court granted Georgia Power’s motion to dismiss the two appeals. On January 9, 2019, those parties appealed that decision to the Georgia Court of Appeals. On October 29, 2019, the Georgia Court of appeals remanded the case to the Fulton County Superior Court to clarify its ruling (i) that the Georgia Public Service Commission’s January 11, 2018 order was not a final, appealable decision and (ii) whether the petitioners showed that review of the Public Service Commission’s final order would not provide them an adequate remedy. Georgia Power has stated that it believes the petitions have 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 condition and results of operations.
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As a result of an increase in the total project capital cost forecast and Georgia Power’s decision not to seek recovery of its allocation of the increase in the base capital costs and the increased construction budget in connection with Georgia Power’s 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 the September 2018 vote to continue construction, Georgia Power entered into a binding term sheet with the other Co-owners and MEAG’s wholly-owned subsidiaries MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, and MEAG Power SPVP, LLC 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’s option (the Term Sheet). On February 18, 2019, the Co-owners entered into the Global Amendments to memorialize the provisions of the Term Sheet. Pursuant to the Global Amendments and consistent with the Term Sheet, the Joint Ownership Agreements provide that:
•each Co-owner is obligated to pay its proportionate share of construction costs for Vogtle Units No. 3 and No. 4 based on its ownership interest up to (i) the estimated cost at completion (“EAC”) for Vogtle Units No. 3 and No. 4 which formed the basis of Georgia Power’s forecast of $8.4 billion in Georgia Power’s nineteenth VCM report filed with the Georgia Public Service Commission plus (ii) $800 million of additional construction costs;
•Georgia Power will be responsible for 55.7% of construction costs, subject to exceptions, that exceed the EAC in the nineteenth VCM report by $800 million to $1.6 billion (resulting in up to $80 million of potential additional costs to Georgia Power which would save Oglethorpe up to $44 million), with the remaining Co-owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests (equal to 24.5% for our 30% ownership interest); and
•Georgia Power will be responsible for 65.7% of construction costs, subject to exceptions, that exceed the EAC in the nineteenth VCM report by $1.6 billion to $2.1 billion (resulting in up to a further $100 million of potential additional costs to Georgia Power which would save Oglethorpe up to an additional $55 million), with the remaining Co-owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests (equal to 19.0% for our 30% ownership interest).
If the EAC is revised and exceeds the EAC in the nineteenth VCM report by more than $2.1 billion, each of the Co-owners, other than Georgia Power, will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power’s agreement to pay 100% of such Co-owner’s remaining share of construction costs in excess of the EAC in the nineteenth VCM report plus $2.1 billion. In this event, Georgia Power would have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Co-owner. If Georgia Power accepts the offer to purchase a portion of another Co-owner’s ownership interest in Vogtle Units No. 3 and No. 4, the ownership interest to be conveyed from the tendering Co-owner to Georgia Power will be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Co-owner and by Georgia Power as of the commercial operation date of Vogtle Unit No. 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Co-owner in accordance with the second and third bullets above will be treated as payments made by the applicable Co-owner. This option to tender a portion of our interest to Georgia Power upon such a budget increase would allow us to freeze our construction budget associated with the Vogtle project in exchange for a portion of our 30% ownership interest.
In the event the actual costs of construction at completion of a unit are less than the EAC reflected in the nineteenth VCM report and (i) Vogtle Unit No. 3 is placed in service by the currently scheduled date of November 2021 or (ii) Vogtle Unit No. 4 is placed in service by the currently scheduled date of November 2022, Georgia Power will be entitled to 60.7% of the cost savings with respect to the relevant unit and the remaining Co-owners will be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.
Pursuant to the Global Amendments, the Co-owners will continue to retain a third party to independently consult, advise and report to the Co-owners on issues pertaining to (i) project management and controls, (ii) organizational controls, (iii) commercial management plans and (iv) interim project reports until released by 67% of the Co-owners.
Pursuant to the Joint Ownership Agreements, as amended by the Global Amendments, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement, the Bechtel Agreement or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its
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investment in Vogtle Units No. 3 and No. 4 (or associated financing costs) or the Georgia Public Service Commission determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Co-owners pursuant to the Global Amendment provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Public Service Commission for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates or (iv) an incremental extension of one year or more over the most recently approved schedule. In addition, pursuant to the Joint Ownership Agreements, the required approval of holders of ownership interests in Vogtle Units No. 3 and No. 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.
The Global Amendments provide that Georgia Power may cancel the project at any time at its sole discretion. In the event that Georgia Power determines to cancel the project or fewer than 90% of the Co-owners vote to continue construction upon the occurrence of a subsequent project adverse event, we and the other Co-owners would assess our options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval. Further, if Georgia Power or the Co-owners decided to cancel the project, the Department of Energy would have the discretion to require that we repay all amounts outstanding under our loan guarantee agreement with the Department of Energy over a five-year period as discussed in Note 7 of Notes to Consolidated Financial Statements.
The ultimate outcome of these matters cannot be determined at this time.
Financing
In March 2019, we entered into an amended and restated loan guarantee agreement with the Department of Energy to increase our existing loan guarantee agreement from $3.1 billion to over $4.6 billion and amend other terms of the agreement. As of December 31, 2019, we have borrowed $3.0 billion under the loan guarantee agreement. For additional information regarding terms of the loan guarantee agreement with the Department of Energy, including conditions for future advances, potential repayment over a five-year period, covenants and events of default, see Note 7a of Notes to Consolidated Financial Statements.
We have also financed $1.9 billion of the capital costs of the Vogtle units through capital market debt issuances. Combined with the $4.6 billion loan guaranteed by the Department of Energy, we have arranged financing for more than 85% of our $7.5 billion budget. We anticipate financing any project costs not guaranteed by the Department of Energy in the capital markets. For additional information regarding the financing of Vogtle Units No. 3 and No. 4, see “MANAGEMENT'S DISCUSSION OF AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities—Department of Energy-Guaranteed Loans.”
Under the Bipartisan Budget Act of 2018, we qualify for nuclear production tax credits related to Vogtle Units No. 3 and No. 4. We expect to receive these tax credits in accordance with our 30% ownership interest in the Vogtle Units. We estimate that the nominal value of our allocation of production tax credits will be approximately $700 million and will be earned for eight years post commercial operation. Pursuant to the Global Amendments, Georgia Power agreed to purchase our allocation of production tax credits at varying purchase prices dependent upon the actual cost to complete construction of Vogtle Units No. 3 and No. 4 as compared to the EAC included in the nineteenth VCM report. Any purchases will be at our option. The purchases would occur during the month after such production tax credits are earned and would be at the following purchase prices: (i) 88% of face value if the actual cost remains at or below the EAC reflected in the nineteenth VCM report; (ii) 91% of face value if the actual cost increases by no more than $299 million over the EAC reflected in the nineteenth VCM report; (iii) 95% of face value if the actual cost increases $300 million but less than $600 million over the EAC reflected in the nineteenth VCM report; and (iv) 98% of face value if the actual cost increases by $600 million or more over the EAC reflected in the nineteenth VCM report. We will continue to analyze various options to monetize these credits with one or more third parties, including Georgia Power. In order to maximize the value of these production tax credits, we do not anticipate entering into any agreement to sell these production tax credits until one or both of the Vogtle Units reach commercial operation. We expect to use the proceeds received from the sale of production tax credits to offset operating costs following commercial operation of the Vogtle Units. Any amounts received from these sales will not affect our project budget.
The ultimate outcome of these matters cannot be determined at this time.
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See “RISK FACTORS” for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.
Other Future Power Resources
From time to time, we may assist our members in investigating potential new power supply resources, after compliance with the terms of the New Business Model Member Agreement. See "OGLETHORPE POWER CORPORATION – New Business Model Member Agreement."
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OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES
Member Demand and Energy Requirements
Our members are listed below and include 38 of the 41 electric distribution cooperatives in the State of Georgia.
Altamaha EMC Amicalola EMC Canoochee EMC Carroll EMC Central Georgia EMC Coastal EMC (d/b/a Coastal Electric Cooperative) Cobb EMC Colquitt EMC Coweta Fayette EMC Diverse Power Incorporated, an EMC Excelsior EMC Flint EMC (d/b/a Flint Energies) Grady EMC | GreyStone Power Corporation, an EMC Habersham EMC Hart EMC Irwin EMC Jackson EMC Jefferson Energy Cooperative, an EMC Little Ocmulgee EMC Middle Georgia EMC Mitchell EMC Ocmulgee EMC Oconee EMC Okefenoke Rural EMC Planters EMC | Rayle EMC Satilla Rural EMC Sawnee EMC Slash Pine EMC Snapping Shoals EMC Southern Rivers Energy, Inc., an EMC Sumter EMC Three Notch EMC Tri-County EMC Upson EMC Walton EMC Washington EMC | ||||||||||||
Our members serve approximately 1.9 million electric consumers (meters) representing approximately 4.2 million people. Our members serve a region covering approximately 38,000 square miles, which is approximately 65% of the land area in the State of Georgia, encompassing 151 of the State's 159 counties. Historically, our members' sales by customer class have been approximately two-thirds to residential consumers and slightly less than one-third to commercial and industrial consumers. Our members are the principal suppliers for the power needs of rural Georgia. While our members do not serve any major cities, portions of their service territories are in close proximity to urban areas and have experienced substantial growth over the years due to the expansion of urban areas, including metropolitan Atlanta, into suburban areas and the growth of suburban areas into neighboring rural areas. Each year we file an exhibit containing financial and statistical information for our 38 members for the most recent three year period with one of our quarterly reports on Form 10-Q.
The following table shows the aggregate peak demand and energy requirements of our members for the years 2017 through 2019, and also shows the amount of their energy requirements that we supplied. From 2017 through 2019, peak demand of the members and their energy requirements have fluctuated based on various factors, including milder weather in 2017.
Member Peak Demand (MW)(1) | Member Energy Requirements (MWh) | ||||||||||||||||
Total(2) | Supplied by Oglethorpe(3) | ||||||||||||||||
| 2019 | 9,476 | 40,385,813 | 23,255,861 | ||||||||||||||
| 2018 | 8,858 | 40,179,743 | 23,011,079 | ||||||||||||||
| 2017 | 8,716 | 37,880,696 | 23,813,679 | ||||||||||||||
(1)System peak hour demand of our members measured at our members' delivery points (net of system losses), adjusted to include requirements served by us and member resources, to the extent known by us, behind the delivery points.
(2)Retail requirements served by our and member resources, adjusted to include requirements served by resources, to the extent known by us, behind the delivery points. See "– Member Power Supply Resources."
(3)Includes energy supplied to members for resale at wholesale. Also includes energy we supplied to our own facilities.
Service Area and Competition
The Georgia Territorial Act regulates the service rights of all retail electric suppliers in the State of Georgia. Pursuant to the Georgia Territorial Act, the Georgia Public Service Commission assigned substantially all areas in the State to specified retail suppliers. With limited exceptions, our members have the exclusive right to provide retail electric service in their respective territories, which are predominately outside of the municipal limits existing at the time the Georgia Territorial Act was enacted in 1973. The principal exception to this rule of exclusivity is that electric suppliers may compete for most new
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retail loads of 900 kilowatts or greater. 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 may reassign territory only if it determines that an electric supplier has breached the tenets of public convenience and necessity. The Georgia Public Service Commission may transfer service for specific premises only if: (i) it determines, after joint application of electric suppliers and proper notice and hearing, that the public convenience and necessity require a transfer of service from one electric supplier to another; or (ii) it finds, after proper notice and hearing, that an electric supplier's service to the premises is not adequate or dependable or that its rates, charges, service rules and regulations unreasonably discriminate in favor of or against the consumer utilizing the premises and the electric utility is unwilling or unable to comply with an order from the Georgia Public Service Commission regarding the service.
The Georgia Territorial Act allows limited competition among electric utilities in Georgia by allowing the owner of any new facility located outside of municipal limits and having a connected load upon initial full operation of 900 kilowatts or greater to receive electric service from the retail supplier of its choice. Our members, with our support, are actively engaged in competition with other retail electric suppliers for these new commercial and industrial loads. The number of commercial and industrial loads served by our members continues to increase annually. This limited competition has given our members and us the opportunity to develop resources and strategies to operate in an increasingly competitive market.
For further information regarding members' competitive activities, see "OGLETHORPE POWER CORPORATION – Competition."
Cooperative Structure
Our members are cooperatives that operate their systems on a not-for-profit basis. Accumulated margins derived after payment of operating expenses and provision for depreciation constitute patronage capital of the consumers of our members. Refunds of accumulated patronage capital to the individual consumers may be made from time to time subject to limitations contained in mortgages between the members and the Rural Utilities Service or loan documents with other lenders. The Rural Utilities Service mortgages generally prohibit these distributions unless (i) after any of these distributions, the member's total equity will equal at least 30% of its total assets or (ii) distributions do not exceed 25% of the margins and patronage capital received by the member in the preceding year and equity is at least 20% of total assets. See "– Members' Relationship with the Rural Utilities Service."
We are a membership corporation, and our members are not our subsidiaries. Except with respect to the obligations of our members under each member's wholesale power contract with us and our rights under these contracts to receive payment for power and energy supplied, we have no legal interest in (including through a pledge or otherwise), or obligations in respect of, any of the assets, liabilities, equity, revenues or margins of our members. See "OGLETHORPE POWER CORPORATION – Wholesale Power Contracts." The assets and revenues of our members are, however, pledged under their respective mortgages with the Rural Utilities Service or loan documents with other lenders.
We depend on the revenue we receive from our members pursuant to the wholesale power contracts to cover the costs of operation of our power supply business and satisfy our debt service obligations.
Rate Regulation of Members
Through provisions in the loan documents securing loans to the members, the Rural Utilities Service exercises control and supervision over the rates for the sale of power of our members that borrow from it. The Rural Utilities Service mortgage indentures of these members require them to design rates with a view to maintaining an average times interest earned ratio and an average debt service coverage ratio of not less than 1.25 and an operating times interest earned ratio and an operating debt service coverage ratio of not less than 1.10, in each case for the two highest out of every three successive years.
The Georgia Electric Membership Corporation Act, under which each of the members was formed, requires the members to operate on a not-for-profit basis and to set rates at levels that are sufficient to recover their costs and to provide for reasonable reserves. The setting of rates by the members is not subject to approval by any federal or state agency or authority other than the Rural Utilities Service, but the Georgia Territorial Act prohibits the members from unreasonable discrimination
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in the setting of rates, charges, service rules or regulations and requires the members to obtain Georgia Public Service Commission approval of long-term borrowings.
Cobb EMC, Diverse Power Incorporated, an EMC, Mitchell EMC, Oconee EMC, Snapping Shoals EMC and Walton EMC have repaid all of their Rural Utilities Service indebtedness and are no longer Rural Utilities Service borrowers. Each of these members now has a rate covenant with its current lender. Other members may also pursue this option. To the extent a member that is not a Rural Utilities Service borrower engages in wholesale sales or sales of transmission service in interstate commerce, it would, in certain circumstances, be subject to regulation by the Federal Energy Regulatory Commission under the Federal Power Act.
Members' Relationship with the Rural Utilities Service
Through provisions in the loan documents securing loans to the members, the Rural Utilities Service also exercises control and supervision over the members that borrow from it in such areas as accounting, other borrowings, construction and acquisition of facilities, and the purchase and sale of power.
Historically, federal loan programs providing direct and guaranteed loans from the Rural Utilities Service to electric cooperatives have been a major source of funding for the members. Under the current Rural Utilities Service loan programs, electric distribution borrowers are eligible for loans made by the Federal Financing Bank or other lenders and guaranteed by the Rural Utilities Service. Certain borrowers with either low consumer density or higher than average rates and lower than average consumer income are eligible for special loans that bear interest at an annual rate of 5%. 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.
The President's budget for fiscal year 2021, which begins October 2020, proposes a loan program level of $5.5 billion, the same as the current program level. However, we cannot predict the amount or cost of Rural Utilities Service loans that may be available to the members in the future. For additional information regarding the Rural Utilities Service, see "OGLETHORPE POWER CORPORATION – Relationship with Federal Lenders – Rural Utilities Service."
Members' Relationships with Georgia Transmission and Georgia System Operations
Georgia Transmission provides transmission services to our members for delivery of our members' power purchases from us and other power suppliers. Georgia Transmission and the members have entered into member transmission service agreements under which Georgia Transmission provides transmission service to the members pursuant to a transmission tariff. The member transmission service agreements have a minimum term for network service until December 31, 2060. The members' transmission service agreements include certain elections for load growth above 1995 requirements, with notice to Georgia Transmission, to be served by others. These agreements also provide that if a member elects to purchase a part of its network service elsewhere, it must pay appropriate stranded costs to protect the other members from any rate increase that they would otherwise incur. Under the member transmission service agreements, members have the right to design, construct and own new distribution substations.
Georgia System Operations has contracts with each of its members, including Georgia Transmission and us, to provide to them the services that it in turn purchases from Georgia Power under the Control Area Compact, which we co-signed with Georgia System Operations. Georgia System Operations also provides operation services for the benefit of our members through agreements with us, including dispatch of our resources and other power supply resources owned by the members.
For information about our relationship with Georgia System Operations, see "OGLETHORPE POWER CORPORATION – Relationship with Georgia System Operations Corporation."
Member Power Supply Resources
Oglethorpe Power Corporation
In 2019, we supplied approximately 58% of the retail energy requirements of our members. Pursuant to the wholesale power contracts, we supply each member energy from our generation resources based on its fixed percentage capacity cost responsibility, which are take-or-pay obligations. See "OGLETHORPE POWER CORPORATION – Wholesale Power
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Contracts." Our members satisfy all of their requirements above their purchase obligations to us with purchases from other suppliers as described below.
Contracts with Southeastern Power Administration
Our members purchase hydroelectric power from the Southeastern Power Administration, or SEPA, under contracts that will continue until terminated by two years' written notice by SEPA or the respective member. Five of our members have terminated or given notice to terminate their contracts with SEPA, with negotiated termination dates of March 31, 2019 (34 megawatts), December 31, 2019 (13 megawatts), July 31, 2020 (2 megawatts), and December 31, 2020 (6 megawatts). A sixth member has agreed to purchase an additional 12 megawatts beginning August 1, 2020. In 2019, the aggregate SEPA allocation to the members was 529 megawatts plus associated energy. The availability of energy under these contracts is significantly affected by hydrologic conditions, including lengthy droughts. Each member must schedule its energy allocation, and each member, other than Flint EMC, has designated us to perform this function. Pursuant to a separate agreement, we schedule, through Georgia System Operations, 35 of our members' SEPA power deliveries. Further, each member may be required, if certain conditions are met, to contribute funds for capital improvements for U.S. Army Corps of Engineers projects from which its allocation is derived in order to retain the allocation.
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 capacity of 738 megawatts. The 35 members participating in these two facilities purchase the output of those facilities pursuant to separate take-or-pay power purchase agreements that will continue until terminated by one year's written notice by Smarr EMC or the respective member.
Green Power EMC
Each of our members is also a member of Green Power Electric Membership Corporation, a power supply cooperative specializing in the purchase of renewable energy for its members. Green Power EMC currently purchases energy from 160 megawatts of low-impact hydroelectric, landfill gas, wood-waste biomass and solar facilities, with an additional 424 megawatts under contract and under construction, with plans to purchase more in the future. Included in this total is energy purchased from Green Power Solar, a for-profit subsidiary of Green Power EMC, which has leased, with an option to purchase, nine solar facilities with a total of 9 megawatts.
Georgia Energy Cooperative
Fifteen of our members are members of Georgia Energy Cooperative, An Electric Membership Corporation, which owns a 100 megawatt gas turbine facility and also provides other services to its members.
Other Member Resources
Our members obtain their remaining power supply requirements from various sources. Thirty-one members are parties to requirements contracts with third parties for some or all of their incremental power needs. The other members use a portfolio of short-term and long-term power purchase contracts to meet their incremental requirements. These requirements contracts and long-term power purchase contracts have remaining terms ranging from 3 to 30 years.
These other purchases include 266 megawatts from solar facilities under long-term contracts, with an additional 332 megawatts under construction.
We have not undertaken to obtain a comprehensive list of member power supply resources. Any of our members may have committed or may commit to additional power supply obligations not described above.
For information about members' activities relating to their power supply planning, see "OGLETHORPE POWER CORPORATION – Competition" and "OUR POWER SUPPLY RESOURCES – Future Power Resources." In addition to future power supply resources that we may construct or acquire for our members, the members will likely also continue to acquire future resources from other suppliers, including suppliers that may be owned by members.
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REGULATION
Environmental
General
As an electric utility, we are subject to a wide range of federal, state and local environmental laws. Air emissions, solid waste disposal, water discharges and water usage are extensively controlled, closely monitored and periodically reported. The manner in which various types of wastes can be stored, transported and disposed is also comprehensively regulated.
In general, environmental requirements applicable to the electric power sector are becoming increasingly prescriptive and stringent. Although we have installed an extensive array of environmental control systems at our plants to ensure continued compliance with all existing applicable requirements, including systems to reduce emissions of sulfur dioxide, nitrogen oxides, mercury and other regulated air pollutants at Plants Scherer and Wansley, new environmental regulatory requirements could be imposed. Such additional requirements, if adopted, could substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities. Failure to comply with these requirements could result in civil and criminal penalties and could even require the complete shutdown of individual generating units not in compliance in some cases. Certain of our debt instruments also require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to comply with these requirements, it would constitute a default under those debt instruments. Although we intend to comply with all current and future regulations, we cannot guarantee that we will always be in full compliance with every applicable requirement.
Our capital expenditures and operating costs continue to reflect expenses necessary to comply with all applicable environmental standards. For further discussion of expected future capital expenditures to comply with environmental requirements and regulations, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Capital Requirements – Capital Expenditures."
Air Quality
Environmental regulations adopted at the federal and state levels have had and will continue to have a significant impact on the electric utility industry. The most significant environmental regulations for us continue to be the requirements imposed under the Clean Air Act. These requirements include stringent regulations for controlling emissions of sulfur dioxide, nitrogen oxides, particulate matter, mercury, greenhouse gases, and other air pollutants from affected electric utility units, including the coal-fired units at Plants Scherer and Wansley. The Environmental Protection Agency, or EPA, has actively regulated emissions under the Clean Air Act and the following are the most significant ongoing Clean Air Act regulatory requirements that affect or may affect our business.
National Ambient Air Quality Standards and Nonattainment Updates. Pursuant to the Clean Air Act, EPA sets National Ambient Air Quality Standards (NAAQS) for the following six air pollutants: particulate matter, ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen dioxide and lead. EPA is required to review the existing NAAQS every five years to determine whether any standards should be made more stringent. Pursuant to a review completed in 2015, EPA tightened the NAAQS for ground-level ozone. In response to EPA's adoption of the 2015 eight-hour ozone NAAQS, Georgia submitted proposed ozone air quality designations and recommend that eight counties in the Atlanta area be designated "nonattainment" and the other counties in Georgia be classified as "attainment or unclassifiable." Nonattainment is defined as having air quality that fails to meet the minimum levels established by the NAAQS. In 2018, the nonattainment designations for those eight counties in Georgia became effective.
In December 2018, EPA published a final rule that established the requirements and procedures that states must follow in implementing the control measures and other applicable requirements necessary to achieve the 2015 NAAQS ozone standard through State Implementation Plans (SIPs). For Georgia, the SIP will establish control measures and other requirements to bring back into attainment the eight counties designated as nonattainment. The SIP measures will likely impose, among other things, additional nitrogen oxide and volatile organic compound emission reduction requirements on many of the major stationary sources located within the designated eight counties and in surrounding counties if those emissions are deemed to contribute significantly to the nonattainment status of this Atlanta ozone nonattainment area. Georgia must submit its SIP to EPA by August 3, 2021.
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Furthermore, Georgia may have to adopt additional emissions reductions to address the interstate transport of ozone air pollution that contributes significantly to attainment or interferes with the maintenance of the 2015 ozone NAAQS in neighboring states. At this time, no determination has been made regarding whether emissions sources in Georgia are significantly contributing to such an ozone nonattainment air quality problem.
While our coal-fired power plants have installed control systems to reduce emissions and achieve current ambient air quality standards, new or revised NAAQS could lead to additional emissions reduction requirements. The costs of any additional or upgraded pollution control equipment that could be required because of new or revised NAAQS cannot be determined at this time.
Air Quality Summary. We believe that the emission control systems currently installed at Plants Scherer and Wansley are generally sufficient to meet the air quality requirements described above. However, additional emissions reduction requirements could be imposed on major sources within Georgia, including our co-owned coal-fired plants, to remedy any local and interstate transport air quality problems for the 2015 eight-hour ozone standard. Subsequent developments, including litigation and new implementation approaches adopted by EPA and Georgia could require significant capital expenditures and increased operating expenses at certain of our generating facilities, particularly Plants Scherer and Wansley.
Carbon Dioxide Emissions and Climate Change
Emissions of carbon dioxide from our fossil-fueled power plants totaled 10.2 million short tons in 2019.
On July 8, 2019, the EPA issued the final Affordable Clean Energy (ACE) rule to repeal the Clean Power Plan and adopt a replacement rule for regulating carbon dioxide emissions from existing affected coal-fired electric generating units. The ACE rule is an "inside the fence" regulation that establishes guidelines for reducing carbon dioxide from existing affected units through heat rate efficiency improvement measures. The ACE rule requires states to develop plans to implement the rule. The ACE rule gives states considerable flexibility to consider remaining useful life and other factors when setting performance standards to limit carbon dioxide from affected units and to establish compliance requirements and deadlines.
Legal challenges to the ACE rule are pending before the U.S. Court of Appeals for the D.C. Circuit. The ultimate impact of the ACE rule on us cannot be determined at this time and will depend on the outcome of the pending litigation and how the rule is implemented in Georgia; however, currently we do not expect the rule to have a significant effect on our operating costs. Among other things, Georgia will have the primary responsibility of setting the carbon dioxide performance standards based on heat rate efficiency improvement measures within the State. Several of the anticipated heat rate improvements have already been completed at Plants Scherer and Wansley, our co-owned coal-fired facilities, and we expect that any additional improvements will be minor.
Because some of the heat rate efficiency improvement measures could potentially trigger New Source Review (NSR), the proposed ACE rule included a modification to the NSR program by adding a "maximum hourly emission increase" test that reduces the likelihood of triggering NSR permitting requirements. This change was not included in the final ACE rule but is expected to be adopted through a separate EPA rulemaking action in 2020.
Additional regulation of carbon dioxide could occur at the federal or state level. One example is potential federal legislation that would require stringent reductions in carbon dioxide emissions from all fossil-fueled electric generation facilities nationwide. In addition, EPA could take regulatory actions to require more stringent control requirements to reduce carbon dioxide emissions under its existing legal authority. At this time, we cannot predict the outcome of any legislative or regulatory changes or the result of potential litigation challenging any of these actions.
Coal Combustion Residuals and Steam Electric Power Generating Effluent Guidelines
In 2015, EPA established a comprehensive regulatory program to manage the disposal of coal combustion residuals (CCR) from electric utilities as non-hazardous material under the Resource Conservation and Recovery Act (RCRA). The 2015 CCR rule sets forth requirements for structural integrity assessments, groundwater monitoring, location siting, composite lining, inactive units, closure and post closure, beneficial use recycling, design and operating criteria, recordkeeping, notification, and internet posting for new and existing CCR landfills, CCR surface impoundments and lateral expansions of CCR facilities. In 2015, the EPA also finalized a rule to revise the effluent limitations guidelines (ELG) that applies to certain wastewater discharges from fossil fuel-fired steam electric power plants, including Plants Scherer and
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Wansley. Since adopting the CCR and ELG rules, EPA has begun to adopt revisions to the compliance deadlines and substantive requirements of the two rules.
ELG Rule Changes. In 2017, EPA extended the ELG compliance deadlines to meet discharge limitations for scrubber wastewater and bottom ash transport water from affected coal-fired units, including Plants Scherer and Wansley to November 1, 2020. On November 22, 2019, EPA issued a proposed rule to moderate the discharge limitations on these two wastestreams under the current ELG regulations. EPA is expected to issue a final rule by August 2020. The impact of the final rule will depend on the content of the final rule as well as any litigation resulting from challenges to the rule.
CCR Rule Changes. In 2016, in response to EPA's CCR rulemaking, the Georgia Environmental Protection Division (EPD) adopted new requirements to regulate CCR wastes. These new rules incorporated EPA's requirements as well as State-only requirements for managing CCR wastes in Georgia. These State requirements were implemented and are enforced through a permit system that was substantially approved by EPA on December 16, 2019. Once CCR permits are issued by Georgia EPD, federal citizen suits under RCRA to enforce federal CCR requirements incorporated in the state permit will not be allowed and permit challenges will be handled through EPD's existing administrative process. Georgia's existing CCR regulations are not anticipated to have a material impact on our compliance obligations under the federal CCR rule. However, we cannot predict the impact of any changes to Georgia's CCR regulations including potential legislation or litigation initiatives.
On December 2, 2019, EPA issued a proposed rule to establish new deadlines by which unlined surface impoundments may no longer receive CCR waste and non-CCR wastestreams. EPA proposed additional revisions to the CCR rule in February 2020 that clarified circumstances under which alternative liners may be used, when coal ash may be used in the closure of landfills and impoundments, and that post-closure groundwater monitoring is required if coal ash is removed from a landfill or impoundment. In 2019, Georgia Power ceased sending CCR to the ash ponds at Plants Scherer and Wansley. Similarly, Georgia Power is in the final stages of completing a new wastewater treatment system that will receive and manage the non-CCR wastestreams at Scherer. As a result, these new closure deadlines are not expected to impact our operations. Although no litigation related to CCR is now pending, we cannot predict whether there will be any future lawsuits on the requirements for closing these impoundments or remedying any impacts of the impoundments may be having on groundwater.
In 2018, Georgia Power applied for CCR permits to close the ash ponds at Plants Scherer and Wansley in place using advanced engineering methods. The permit applications Georgia Power filed with the Georgia EPD estimated closing activities to be completed in 2026 for Plant Wansley and 2031 for Plant Scherer. Our current estimated expenditures for the settlement of related asset retirement obligations are approximately $400 million to $550 million (in year of expenditure dollars) for the closure and post-closure of existing coal ash ponds. See Note 1 of Notes to Consolidated Financial Statements. In addition, current estimates suggest that our capital expenditures to comply with the applicable CCR requirements and effluent discharge limitations will be approximately $325 million to $350 million for conversion to dry ash handling, landfill construction and wastewater treatment. More definitive cost estimates will continue to be developed as the processes of rule evaluation, compliance approach and design and construction implementation proceed. The ultimate impacts associated with the federal and state CCR rules and the federal effluent discharge limitations, any revised regulation or legislation at the state or federal level and related litigation challenging such rules, or future legislation cannot be determined at this time. If the proposed closure plans are not approved or Georgia's requirements for coal ash disposal are subsequently revised, and we and other co-owners at Plants Scherer and Wansley are instead required to construct lined coal ash facilities, our estimated compliance costs would increase materially.
Water Use and Wastewater Issues
In 2015, the U.S. Court of Appeals for the Sixth Circuit stayed a final rule published jointly by EPA and the U.S. Army Corps of Engineers that revised the regulatory definition of waters of the U.S. for all Clean Water Act programs. The final rule would have significantly expanded the scope of federal jurisdiction under the Clean Water Act. Although the rule was not expected to have a substantial impact on our existing operations, it would likely have increased permitting and regulatory requirements and costs associated with the siting and permitting of new facilities. In July 2017, EPA proposed a two-step process to address the stayed rule and followed that proposal with a supplemental proposed rule in June 2018. The first step replaces the 2015 regulations that defined waters of the U.S. with those that were in effect prior to the 2015 rule. In the second step, EPA proposed a rule in December 2018 replacing the 2015 definition with a revised definition that clarifies and narrows the scope of federal authority under the Clean Water Act. A final rule incorporating the proposed rules was issued on
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January 23, 2020. While there is minimal direct impact to our operations as a result of the final rule, we cannot determine the ultimate impact of any change to that rule or any litigation challenging that rule or any replacement rule at this time.
Other Environmental Matters
We are subject to other environmental statutes including, but not limited to, the Georgia Water Quality Control Act, the Georgia Hazardous Site Response Act, the Toxic Substances Control Act, the Endangered Species Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act, and the regulations implementing these environmental statutes. We do not believe that compliance with these statutes and regulations will have a material impact on our financial condition or operation of our facilities. Changes to any of these laws, however, could affect many areas of our operations. Although compliance with new environmental legislation could have a significant impact on those operations, such impacts cannot be fully determined at this time and would depend in part on the final legislation and the development of implementing regulations.
As an owner, co-owner and/or operator of generating facilities, we are also subject, from time to time, to claims relating to operations and/or emissions, including actions by citizens to enforce environmental regulations and claims for personal injury due to such operations and/or emissions. Likewise, actions by private citizen groups to enforce environmental laws and regulations are becoming increasingly prevalent. We cannot predict the outcome of current or future actions, our responsibility for a share of any damages awarded, or any impact on facility operations. We do not believe, however, that current actions will have a material adverse effect on our financial position, results of operations or cash flows.
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 full compliance with all applicable 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 even force the complete shutdown of individual generating units not in compliance with these regulations in some cases. 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.
Nuclear Regulation
We are subject to the provisions of the Atomic Energy Act of 1954 (the Atomic Energy Act), which vests jurisdiction in the Nuclear Regulatory Commission over the construction and operation of nuclear reactors, particularly with regard to certain public health, safety and antitrust matters. The National Environmental Policy Act has been construed to expand the jurisdiction of the Nuclear Regulatory Commission to consider the environmental impact of a facility licensed under the Atomic Energy Act. Plants Hatch and Vogtle are being operated under licenses issued by the Nuclear Regulatory Commission. All aspects of the construction, operation and maintenance of nuclear power plants are regulated by the Commission. From time to time, new Commission regulations require changes in the design, operation and maintenance of existing nuclear reactors. Operating licenses issued by the Commission are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the Commission determines that the public interest, health or safety so requires. The operating licenses issued for each unit of Plants Hatch and Vogtle expire in 2034 and 2038, and 2047 and 2049, respectively.
The Nuclear Regulatory Commission issued combined construction permits and operating licenses that allow the completion of construction and operation of two additional units at Plant Vogtle. See "OUR POWER SUPPLY RESOURCES – Future Power Resources – Plant Vogtle Units No. 3 and No. 4."
Pursuant to the Nuclear Waste Policy Act of 1982, the federal government has the responsibility for the final disposal of commercially produced high-level radioactive waste materials, including spent nuclear fuel. This act requires the owner of nuclear facilities to enter into disposal contracts with the Department of Energy for such material.
Contracts with the Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants, has successfully pursued and continues to
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pursue legal remedies against the Department of Energy for breach of contract. See Note 1 of Notes to Consolidated Financial Statements for information regarding the status of this litigation.
In November 2013, the U.S. District Court for the District of Columbia ordered the Department of Energy to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the Department of Energy either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. We discontinued paying the fee of approximately $9.2 million annually, based on our ownership interests, in June 2014.
Existing on-site dry storage facilities at Plants Hatch and Vogtle can be expanded to accommodate spent fuel through the expected life of each plant, including Vogtle Units No. 3 and No. 4.
For information concerning nuclear insurance, see Note 10 of Notes to Consolidated Financial Statements. For information regarding the Nuclear Regulatory Commission's regulation relating to decommissioning of nuclear facilities and regarding the Department of Energy's assessments pursuant to the Energy Policy Act for decontamination and decommissioning of nuclear fuel enrichment facilities, see Note 1 of Notes to Consolidated Financial Statements.
Federal Power Act
General
Pursuant to the Federal Power Act, the Federal Energy Regulatory Commission is the federal agency that regulates the nation's bulk power system. We are subject to certain rules and regulations under the Federal Power Act; however, as a borrower from the Rural Utilities Service, we are exempted from certain Federal Energy Regulatory Commission regulations, including rate regulation.
Rocky Mountain
We are subject to the hydropower licensing provisions of the Federal Power Act. Rocky Mountain is a hydroelectric project subject to licensing by the Federal Energy Regulatory Commission. The currently effective Federal Energy Regulatory Commission license to operate the Rocky Mountain project expires in 2026. See "PROPERTIES – Generating Facilities" and " – The Plant Agreements – Rocky Mountain" for additional information.
Upon or after the expiration of the license, the United States Government, by act of Congress, may take over the project, or the Federal Energy Regulatory Commission may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another, the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property taken, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property taken. The Federal Energy Regulatory Commission may grant relicenses subject to certain requirements that could result in additional costs. If the Federal Energy Regulatory Commission does not act on the new license application prior to the expiration of the existing license, the commission is required to issue annual licenses, under the same terms and conditions of the existing license, until a new license is issued.
We anticipate making a timely application for a new license for the Rocky Mountain project.
Energy Policy Act of 2005
The Energy Policy Act of 2005 amended the Federal Power Act to authorize the Federal Energy Regulatory Commission to establish an electric reliability organization to develop and enforce mandatory reliability standards and to establish clear responsibility for the commission to prohibit manipulative energy trading practices. In 2006, the Federal Energy Regulatory Commission certified the North American Electric Reliability Corporation, or NERC, as the electric reliability organization. The mandatory reliability standards developed by NERC and approved by the Federal Energy Regulatory Commission impose certain operating, coordination, record-keeping and reporting requirements on us. NERC has delegated day-to-day enforcement of its responsibilities to regional entities and SERC Reliability Corporation is the regional entity to enforce reliability compliance in sixteen central and southeastern states, including Georgia. These entities have the authority to issue fines and penalties for violations of these standards.
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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.
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ITEM 1A. RISK FACTORS
The following describes the most significant risks, in management’s view, that may affect our business and financial condition or the value of our debt securities. This discussion is not exhaustive, and there may be other risks that we face which are not described below. The risks described below, as well as additional risks and uncertainties presently unknown to us or currently not deemed significant, could negatively affect our business operations, financial condition and future results of operations.
Our participation in the construction of Vogtle Units No. 3 and No. 4 could have a material impact on our financial condition and results of operations.
We are participating in the construction of two additional nuclear units at Plant Vogtle and have committed significant capital expenditures to this endeavor. The construction of large, complex generating plants involves significant financial risk. We rely on Georgia Power and Southern Nuclear as our agents for the oversight of the construction of the additional units at Plant Vogtle and do not exercise direct control over the construction process.
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, 2019, our total investment in the additional Vogtle units was approximately $4.9 billion. The regulatory-approved in-service dates for Vogtle Unit No. 3 and No. 4 are November 2021 and November 2022, respectively.
We and the other Co-owners are responsible for construction costs based on our ownership percentages. Factors that could lead to further cost increases and schedule delays or even the inability to complete this project include:
•performance by Georgia Power as agent for the Co-owners and performance by Southern Nuclear as construction manager;
•performance by Bechtel under the Bechtel Agreement as well as subcontractor and supplier performance, including compliance with the design specifications approved and quality standards set forth by the Nuclear Regulatory Commission;
•changes in labor costs, availability and productivity;
•shortages, delays, increased costs or inconsistent quality of labor, equipment and materials;
•performance by Westinghouse under the Services Agreement;
•increases in our cost of debt financing as a result of changes in market interest rates or as a result of construction schedule delays;
•delays or failure to receive necessary permits, approvals and other regulatory authorizations;
•engineering or design problems;
•delays in start-up activities (including major equipment failure, system integration or regional transmission upgrades) and/or operational performance;
•operational readiness, including specialized operator training and required site safety programs;
•the outcome of any legal challenges to the project, including legal challenges to regulatory approvals;
•erosion of public and policymaker support;
•contract disputes;
•changes in project design or scope;
•impacts of new and existing laws and regulations, including environmental laws and regulations;
•adverse weather conditions;
•catastrophic events, natural disasters and pandemic health events; and
•work stoppages.
Additionally, the current coronavirus (COVID-19) pandemic may disrupt or delay construction, testing, supervisory and support activities at Vogtle Units No. 3 and No. 4. Southern Nuclear has implemented policies and procedures designed to mitigate the risk of transmission at the construction site, including limiting exposure of individuals who are showing symptoms consistent with coronavirus, being tested for coronavirus or in close contact with such persons, self-quarantine and
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additional precautionary measures. It is too early to determine what impact, if any, suspected or actual cases may have on the current construction schedule or budget.
The current project-level budget includes an $800 million construction contingency estimate, of which our 30% interest is $240 million. As of December 31, 2019, approximately $307 million of this project-level contingency, or $92 million for our 30% interest, was allocated to the base capital cost forecast for cost risks including, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. 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.
In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the total estimated project capital cost forecast for Vogtle Units No. 3 and No. 4 and did not change the regulatory-approved in-service dates of November 2021 for Unit No. 3 and November 2022 for Unit No. 4. As part of this process, Southern Nuclear also established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain margin to the regulatory-approved in-service dates. The project has faced challenges with the April 2019 aggressive strategy targets, including, but not limited to, electrical and pipefitting labor productivity and closure rates for work packages, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.
In February 2020, Southern Nuclear updated its cost and schedule forecast, which did not change the projected overall capital cost forecast and confirmed the regulatory-approved in-service dates. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near term milestone dates. Achieving completion in advance of the regulatory-approved in-service dates relies on meeting increased monthly production target values during 2020. Specifically, existing craft, including subcontractors, construction productivity must improve and be sustained above historical average levels, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be maintained, and additional supervision and other field support resources must be retained. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates.
In February 2020, Southern Nuclear also provided a schedule benchmark that forecasts production levels and adjusts project milestones to align with the regulatory-approved in-service dates. We believe the production levels and timeframes in this benchmark provide reasonable assurance that Units No. 3 and No. 4 will meet the regulatory-approved in-service dates of November 2021 and November 2022, respectively.
Pursuant to the Global Amendments, Georgia Power agreed to mitigate certain financial exposure for the other Co-owners. In the event that construction costs exceed the EAC in the nineteenth VCM report by more than $800 million up to $2.1 billion, Georgia Power will be responsible for an increasing percentage of construction costs, subject to exceptions, up to a maximum of an additional $180 million, and each Co-owner would maintain its existing ownership interest. In the event that the EAC exceeds the EAC in the nineteenth VCM report by more than $2.1 billion, each of the Co-owners, other than Georgia Power, will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power’s agreement to pay 100% of such Co-owner’s remaining share of construction costs in excess of the EAC in the nineteenth VCM report plus $2.1 billion. This option to tender a portion of our interest to Georgia Power upon such a budget increase would allow us to freeze our construction budget associated with the Vogtle project in exchange for a portion of our 30% ownership interest.
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 craft labor productivity, particularly in the installation of electrical and mechanical 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), or regional transmission upgrades, 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
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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 submittal by Southern Nuclear of inspections, tests, analyses, and acceptance documentation for each unit and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support Nuclear Regulatory Commission 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 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.
Pursuant to the Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement, the Bechtel Agreement or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Vogtle Units No. 3 and No. 4 (or associated financing costs) or the Georgia Public Service Commission determines that any of Georgia Power’s costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Co-owners pursuant to the Global Amendment provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Public Service Commission for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates or (iv) an incremental extension of one year or more over the most recently approved schedule.
The Global Amendments provide that Georgia Power may cancel the project at any time in its sole discretion. In the event that Georgia Power determines to cancel the project or fewer than 90% of the Co-owners vote to continue construction upon the occurrence of a subsequent project adverse event, we and the other Co-owners would assess our options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval. Further, if Georgia Power or the Co-owners decided to cancel the project, the Department of Energy would have the discretion to require that we repay all amount outstanding under the loan guarantee agreement over a five-year period.
The ultimate outcome of these matters cannot be determined at this time; however, these risks could continue to impact the in-service dates and cost of the additional units at Plant Vogtle which would increase the cost of electric service we provide to our members and, as a result, could affect their ability to perform their contractual obligations to us.
Our access to, and cost of, capital could be adversely affected by various factors, including market conditions, limitations on the availability of federally-guaranteed loans and our credit ratings. Significant constraints on our access to, or increases in our cost of, capital may limit our ability to execute our business plan by impacting our ability to fund capital investments and could adversely affect our financial condition and results of operations.
We rely on access to external funding sources as a significant source of liquidity for capital expenditures not satisfied by cash flow generated from operations. 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 pursuant to which we funded $3.0 billion of eligible project costs. 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. As of December 31, 2019, we had no remaining borrowing capacity under the original loan. If we draw the entire amount of the additional loan, the aggregate amount of Department of Energy-guaranteed loans available to us for Vogtle Units No. 3 and No. 4 will be $4.6 billion. Based on our current budget for Vogtle Units No. 3 and No. 4, which includes Oglethorpe and project-level contingency, and our ability to draw the remaining amount of the Department of Energy-guaranteed loans, we anticipate that we will need to raise up to $1 billion of additional long-term funding in the capital markets through 2023.
Access to the committed funds under the additional Department of Energy-guaranteed loan 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 the additional loan 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
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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;
•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 costs of compliance with environmental laws and regulations are significant and have increased in recent years. Potential new or stricter environmental laws and regulations, including those designed to address air and water quality, greenhouse gas emissions, including carbon dioxide, coal combustion residuals 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 2019, 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, 2019, we have spent approximately $239 million on capital expenditures related to the
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coal ash handling and effluent limitation guidelines described below, and expect to spend approximately $102 million more in the near future.
Although the current administration has relaxed certain federal regulations, potential future legislation or regulations at the federal or state level may create new requirements and operational hurdles. More stringent or new standards could require us to modify the design or operation of existing facilities and result in significant increases in the cost of electricity or decreases in the amount of energy (due to operational constraints) provided to our members. Examples of current and potential regulations are discussed below.
In July 2019, the EPA issued the final Affordable Clean Energy (ACE) rule to replace the Clean Power Plan. The ACE rule addresses carbon dioxide emissions from coal plants and requires states to develop unit-specific standards of performance based on six candidate technologies for heat rate improvements, plus best operation and maintenance practices. The ACE rule is currently being challenged in the U.S. Court of Appeals for the D.C. Circuit. The ultimate impact of the ACE rule on us will depend on the performance standards set by Georgia,however, at this time we do not expect the rule to have a significant effect on our current operating costs. The outcome of associated legal challenges cannot be determined at this time.
Even if the ACE rule survives legal challenges and is implemented by the states, we expect that efforts to limit greenhouse gas emissions, including carbon dioxide, will continue. For example, the U.S. House of Representatives recently proposed a framework for legislation requiring the U.S. to achieve net-zero greenhouse gas emissions, including a 100% clean electricity standard, by 2050. Although this legislation is currently unlikely to become law in the near-term, some of the proposals could serve as the basis for future legislation. 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. To comply with this rule, the ash ponds at Plants Wansley and Scherer ceased receiving new coal ash in early 2019 and Georgia Power has estimated closure activities for the ash ponds 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 have proposed such a plan to the Georgia Environmental Protection Division. The proposed closure plans are currently awaiting review. If the proposed plans are not approved or state requirements for coal ash disposal are subsequently revised and we and the other co-owners of Plants Scherer and Wansley are instead required to construct lined coal ash disposal facilities, our estimated compliance costs would increase materially. 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). We continue to review the ultimate cost of these rules on our co-owned coal facilities.
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.”
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.
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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, 2019 was $4.9 billion. As we have financed generation assets in the past, we are relying on external funding to finance this project. As of December 31, 2019, we had $9.7 billion of long-term debt outstanding, an increase of $5.5 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 $12.6 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.
In order to increase financial coverage during this period of generation expansion, our board of directors has 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 2020 our board of directors again approved a margins for interest ratio of 1.14.
We own and are participating in the construction of nuclear facilities which give rise to environmental, regulatory, financial and other risks.
We own a 30% undivided interest in Plant Hatch and Plant Vogtle, each of which is a two-unit nuclear generating facility, and which collectively account for approximately 17% of our total gross generating capacity and 43% of our energy generated during 2019. Our ownership interests in these facilities expose us to various risks, including:
•potential liabilities relating to harmful effects on the environment and human health and safety resulting from the operation of these facilities and the on-site storage, handling and disposal of radioactive materials, including spent nuclear fuel;
•uncertainties with respect to the technological and financial aspects of and the ability to maintain and anticipate adequate capital reserves for decommissioning these facilities at the end of their operational lives;
•significant capital expenditures relating to maintenance, operation, security and repair of these facilities, including repairs or modifications required by the Nuclear Regulatory Commission;
•potential liabilities arising out of nuclear incidents caused by natural disasters, terrorist attacks, cyber security attacks or otherwise, including the payment of retrospective insurance premiums, whether at our own plants or the plants of other nuclear owners; and
•uncertainties with respect to the off-site storage and disposal of spent nuclear fuel in the event that on-site storage is not sufficient.
The Nuclear Regulatory Commission has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. If our nuclear facilities were found to be out of compliance with applicable requirements, the Nuclear Regulatory Commission may impose fines or shut down one or more units of these facilities until compliance is achieved. Revised safety requirements issued by the Nuclear Regulatory Commission have, in the past, necessitated substantial capital expenditures at other nuclear generating facilities.
Further, a major incident at a nuclear facility anywhere in the world could cause the Nuclear Regulatory Commission to limit or prohibit the operation or licensing of any domestic nuclear unit. While we have no reason to expect a serious incident at either of our nuclear plants, if an incident did occur, it could result in substantial cost to us.
We maintain an internal fund and an external trust fund to pay for the estimated cost of decommissioning our existing nuclear facilities. We continue to collect and deposit additional funds into the internal fund. If the values of the investments in the funds significantly decrease or the anticipated decommissioning costs significantly increase, it is possible that the decommissioning costs could exceed the funds available and we would have to collect additional revenue from our members to pay the unfunded costs.
In addition to our ownership of existing nuclear units, we are participating with the other Co-owners of Plant Vogtle in the construction of two additional nuclear units at the Plant Vogtle site. See “BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4.”
We could be adversely affected if we or third parties operating certain of our co-owned facilities are unable to continue to operate our facilities in a successful manner.
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The operation of our generating facilities may be adversely impacted by various factors, including:
•the risk of equipment and information technology failure or operator error;
•operating limitations that may be imposed by environmental or other regulatory requirements;
•physical or cyber attacks against us or key suppliers or service providers;
•interruptions or shortages in fuel, water or material supplies;
•transmission constraints or disruptions;
•compliance with electric reliability organizations’ mandatory reliability and record keeping standards, including mandatory cyber security standards;
•the ability to maintain a qualified workforce;
•an environmental event, such as a spill or release;
•labor disputes; or
•catastrophic events such as fires, earthquakes, floods, droughts, hurricanes, explosions, pandemic health events, such as the current coronavirus (COVID-19) outbreak, or similar occurrences.
We operate in a highly regulated industry that requires the continued operation of advanced information technology systems and network infrastructure. Our generation assets and information technology systems, or those of our co-owned plants, could be directly or indirectly affected by deliberate or unintentional cyber incidents. If our technology systems were to be breached or otherwise fail, we may be unable to fulfill critical business functions, including the operation of our generation assets and our ability to effectively maintain certain internal controls over financial reporting. Further, our generation assets rely on an integrated transmission system to deliver power to our members, and a disruption of this transmission system could negatively impact our ability to do so. In order to reduce the likelihood and severity of any cyber intrusion, we have comprehensive cyber security programs designed to protect and preserve the confidentiality, integrity and availability of data and systems. Despite these protections, a major cyber incident could result in significant business disruption and expenses to repair security breaches or system damage and could lead to litigation, regulatory action, including fines, and an adverse effect on our reputation.
A severe drought could reduce the availability of water and restrict or prevent the operation of certain generating facilities. Other negative events such as those discussed above could also interrupt or limit electric generation or increase the cost of operating our facilities, which could have the effect of increasing the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us.
Further, a significant percentage of our energy is generated at co-owned facilities that are operated by Georgia Power and Southern Nuclear. We rely on these third parties for the continued operation of these facilities to avoid potential interruptions in service from these facilities. If these third parties are unable to operate these facilities, the cost of electric service we provide to our members, or the cost of replacement electric service, may increase. See “BUSINESS—OGLETHORPE POWER CORPORATION—Relationship with Georgia Power Company” and “Properties—Co-Owners of Plants” and “—Plant Agreements” for discussions of our relationship with Georgia Power and our co-owned facilities.
Advances in power generation and energy storage technologies, including decreasing renewable energy costs and the broad adoption of distributed generation technologies, in our members’ service territories could result in the cost of our electric service being less competitive.
Our business model is to provide our members with wholesale electric power at the lowest possible cost. A key element of this model is that generating power at central station power plants achieves economies of scale and produces power at a competitive cost. Renewable energy, distributed generation or energy storage technologies currently exist or are in development, such as large-scale batteries, fuel cells, micro turbines, windmills and solar cells, some of which are capable of producing or storing electric power at costs that are comparable with, or lower than, our cost of generating power. If these technologies were to develop sufficient economies of scale and be broadly adopted in our members’ service territories, it could adversely affect our ability to recover the fixed costs related to and the value of our generating facilities and significantly increase the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us.
Changes in fuel prices could have an adverse effect on our cost of electric service.
We are exposed to the risk of changing prices for fuels, including natural gas, coal and uranium. For 2019, our primary fuel price exposure was to natural gas, as natural gas expenses constituted 64% of our fuel costs for the year. We have taken steps to manage this exposure by entering into natural gas swap arrangements designed to manage potential fluctuations in
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our power rates due to changes in the price of natural gas. We have also entered into fixed or capped price contracts for some of our coal requirements. The operator of our nuclear plants manages price and supply risk through use of long-term fixed or capped price contracts with multiple vendors of uranium ore mining, conversion and enrichment services. However, these arrangements do not cover all of our and our members’ risk exposure to increases in the prices of fuels. Further, changes in the utilization of different generation resources may subject us to greater fuel price volatility. Despite the continued low prices for domestic natural gas prices, natural gas prices have historically been more volatile than other fuel sources and stable pricing cannot be assured. Further, the availability of shale gas and potential regulations affecting its accessibility and transport may have a material impact on the cost and supply of natural gas. Increases in fuel prices could significantly increase the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us.
If we were unable to obtain an adequate supply of fuel, our ability to operate our facilities could be limited.
We obtain our fuel supplies, including natural gas, coal and uranium, from a number of different suppliers. Any disruptions in our fuel supplies, including disruptions due to weather, environmental regulations, inadequate infrastructure, labor relations or other factors affecting our fuel suppliers, could result in us having insufficient levels of fuel supplies. For example, there are only a few facilities that fabricate fuel for our nuclear units and if there was an interruption in production at one of those facilities, it could impact our ability to obtain fuel for our nuclear generating facilities on a timely basis. Natural gas supplies are also subject to disruption due to natural disasters and similar events, infrastructure failure or may be unavailable due to significantly increased demand caused by exceptionally cold weather. Any failure to maintain an adequate inventory of fuel supplies could require us to operate other generating plants at a higher cost or require our members to purchase higher-cost energy from other sources and, as a result, affect our members’ ability to perform their contractual obligations to us.
We, the co-owners or the operating agent for our co-owned coal plants may retire one or more of our coal-fired generation units in advance of our currently assumed retirement dates which could result in rate recovery challenges.
We own or lease a 60% interest in Plant Scherer Units No. 1 and No. 2 and a 30% interest Plant Wansley Units No. 1 and No. 2 which together constitute 22% of our total summer planning reserve capacity. The percentage of gross energy generated by coal-fired resources we sell to our members has decreased from 45% in 2008 to 10% in 2019. This decrease was largely driven by other generation resources being more economical and our acquisition of additional natural gas-fired resources. Additional lower cost generation could further displace existing coal-fired generation which may make continued operation uneconomical.
In addition to these pressures, potential new environmental standards could require additional capital expenditures or operating costs that make continued operation of some of the units uneconomical. Some banking and insurance companies have also voluntarily implemented policies to limit lending to, investing in and insuring utilities that significantly rely on coal-fired generation assets. We are not aware that any of those policies have directly impacted us to date. Similar pressures on coal producers have also increased and could impact our price and supply of coal.
Early retirement of one or more coal units could require us to recover the undepreciated costs for the unit over a shorter period. The ultimate impact of any early retirement on us and our members would depend on several factors, including the proposed retirement date, our ability to recover costs after the retirement date, the price of any replacement energy and cannot be determined at this time. In order to mitigate the rate impact of any early retirement on our members, we would likely apply for regulatory accounting treatment to spread the early retirement costs over an extended period. These increased costs could affect our members’ ability to perform their contractual obligations to us.
The operational life of some of our generating facilities exposes us to potential costs to continue to meet efficiency, reliability and environmental compliance standards.
Many of our generating facilities were constructed more than 30 years ago and, even if maintained in accordance with good engineering practices, will require significant capital expenditures in order to maintain efficient and reliable operation. Potential operational issues associated with the age of the plants may lead to unscheduled outages, a generating facility being out of service for an extended period of time, or other service-related interruptions. Further, maintaining facility availability and compliance with applicable efficiency, reliability and environmental standards may require significant capital expenditures or operating reductions at certain of our facilities and we may determine to reduce or cease operations at those facilities in order to avoid such capital expenditures or to meet such standards. These expenditures and service interruptions could have the effect of increasing the cost of electric service we provide to our members and, as a result, could affect our members’ ability to perform their contractual obligations to us.
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Our ability to meet our financial obligations could be adversely affected if our members fail to perform their contractual obligations to us.
We depend primarily on revenue from our members under the wholesale power contracts to meet our financial obligations. Our members are our owners, and we do not control their operations or financial performance.
Under current Georgia law, our members generally have the exclusive right to provide retail electric service in their respective territories, subject to limited exceptions. 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 which could affect our members’ financial performance. Further, our members must forecast their load growth and power supply needs. If our members acquire more power supply resources than needed, whether from us or other suppliers, or fail to acquire sufficient resources, our members’ rates could increase excessively and affect their financial performance. Also, in times of weak economic conditions, sales by our members may not be sufficient to cover costs without rate increases, and our members may not collect all amounts billed to their consumers. Although each member has financial covenants to set rates to maintain certain margin levels and our members’ rates are not regulated by the Georgia Public Service Commission, pressure from their consumer members not to raise rates excessively could affect financial performance. Thus, we are exposed to the risk that one or more members could default in the performance of their obligations to us under the wholesale power contracts. Our ability to satisfy our financial obligations could be adversely affected if one or more of our members, particularly one of the larger members, defaulted on their payment obligations to us. Although the wholesale power contracts obligate non-defaulting members to pay the amount of any payment default pursuant to a pro rata step-up formula, there can be no guarantee that the non-defaulting members would be able to fulfill this obligation.
We are subject to the risk that counterparties may fail to perform their contractual obligations which could adversely affect us.
We routinely execute transactions with counterparties in the energy and financial services industries. These transactions include credit facilities, facility construction, co-owner agreements, contracts related to the market price and supply of natural gas and coal, and power sales and purchases. Many of these transactions expose us to the risk that our counterparty may fail to perform its contractual obligations. If a defaulting counterparty is in poor financial condition, we may not be able to recover damages for any breach of contract.
In the context of facility construction, a counterparty’s failure to perform its contractual obligations under the applicable agreement could impact the project cost and schedule and potentially project completion.
Regardless of our financial condition, investors’ ability to trade our debt securities may be limited by the absence of an active trading market and there is no assurance that any trading market will develop or continue to remain active.
Our debt securities are not listed on any national securities exchange or quoted on any automated quotation system although certain series of our debt securities may be included in a fixed income index. Various dealers have made a market in certain of our debt securities and at times certain of our debt securities have an active trading market; however, other of our debt securities have no active trading market. We have remarketing agreements in place for certain of our variable rate bonds and if a particular series of new debt securities is offered through underwriters, those underwriters may attempt to make a market in the debt securities. Dealers or underwriters have no obligation to make a market in any of our debt securities and may terminate any market-making activities at any time, for any reason, without notice. Further, removal from any index may have an adverse effect on the liquidity of the trading market, if any, for our debt securities removed from that index. As a result, we cannot provide any assurance as to the liquidity of any trading market for our debt securities, the ability of holders to sell their debt securities or the price at which holders will be able to sell their debt securities.
Even in an active trading market, future prices of our debt securities will depend on several factors, including prevailing interest rates, the then-current ratings assigned to the debt securities, the number of holders of the debt securities, the amount of our debt securities outstanding, the market for similar securities and our operating results.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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ITEM 2. PROPERTIES
Generating Facilities
The following table sets forth certain information with respect to our generating facilities, all of which are in commercial operation.
| Facilities | Type of Fuel | Percentage Interest | Our Share of Nameplate Capacity (megawatts) | Commercial Operation Date | License Expiration Date | |||||||||||||||||||||||||||
| Plant Hatch (near Baxley, Ga.) | ||||||||||||||||||||||||||||||||
| Unit No. 1 | Nuclear | 30 | 269.9 | 1975 | 2034 | |||||||||||||||||||||||||||
| Unit No. 2 | Nuclear | 30 | 268.8 | 1979 | 2038 | |||||||||||||||||||||||||||
| Plant Vogtle (near Waynesboro, Ga.) | ||||||||||||||||||||||||||||||||
| Unit No. 1 | Nuclear | 30 | 348.0 | 1987 | 2047 | |||||||||||||||||||||||||||
| Unit No. 2 | Nuclear | 30 | 348.0 | 1989 | 2049 | |||||||||||||||||||||||||||
| Plant Wansley (near Carrollton, Ga.) | ||||||||||||||||||||||||||||||||
| Unit No. 1 | Coal | 30 | 259.5 | 1976 | N/A | (1) | ||||||||||||||||||||||||||
| Unit No. 2 | Coal | 30 | 259.5 | 1978 | N/A | (1) | ||||||||||||||||||||||||||
| Combustion Turbine | Oil | 30 | 14.8 | 1980 | N/A | (1) | ||||||||||||||||||||||||||
| Plant Scherer (near Forsyth, Ga.) | ||||||||||||||||||||||||||||||||
| Unit No. 1 | Coal | 60 | 490.8 | 1982 | N/A | (1) | ||||||||||||||||||||||||||
| Unit No. 2 | Coal | 60 | 490.8 | 1984 | N/A | (1) | ||||||||||||||||||||||||||
| Rocky Mountain (near Rome, Ga.) | Pumped Storage Hydro | 74.61 | 632.5 | 1995 | 2026 | |||||||||||||||||||||||||||
| Doyle (near Monroe, Ga.) | Gas | 100 | 325.0 | 2000 | N/A | (1) | ||||||||||||||||||||||||||
| Talbot (near Columbus, Ga.) | ||||||||||||||||||||||||||||||||
| Units No. 1-4 | Gas | 100 | 412.0 | 2002 | N/A | (1) | ||||||||||||||||||||||||||
| Units No. 5-6 | Gas-Oil | 100 | 206.0 | 2003 | N/A | (1) | ||||||||||||||||||||||||||
| Chattahoochee (near Carrollton, Ga.) | Gas | 100 | 468.0 | 2003 | N/A | (1) | ||||||||||||||||||||||||||
| Hawk Road (near Franklin, Ga.) | Gas | 100 | 500.0 | 2001 | N/A | (1) | ||||||||||||||||||||||||||
| Hartwell (near Hartwell, Ga.) | Gas-Oil | 100 | 300.0 | 1994 | N/A | (1) | ||||||||||||||||||||||||||
| Smith (near Dalton, Ga.) | ||||||||||||||||||||||||||||||||
| Unit No. 1 | Gas | 100 | 630.0 | 2002 | N/A | (1) | ||||||||||||||||||||||||||
| Unit No. 2 | Gas | 100 | 620.0 | 2002 | N/A | (1) | ||||||||||||||||||||||||||
(1)Fossil-fuel fired units do not operate under operating licenses similar to those granted to nuclear units by the Nuclear Regulatory Commission and to hydroelectric plants by the Federal Energy Regulatory Commission.
33
Plant Performance
The following table sets forth certain operating performance information of each of our generating facilities:
Summer Planning Reserve Capacity(1) (Megawatts) | Equivalent Availability(2) | Capacity Factor(3) | |||||||||||||||||||||||||||||||||||||||
| Unit | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | |||||||||||||||||||||||||||||||||||
| Plant Hatch | |||||||||||||||||||||||||||||||||||||||||
| Unit No. 1 | 262.2 | 98 | % | 91 | % | 95 | % | 99 | % | 91 | % | 95 | % | ||||||||||||||||||||||||||||
| Unit No. 2 | 264.3 | 82 | 95 | 92 | 82 | 96 | 93 | ||||||||||||||||||||||||||||||||||
| Plant Vogtle | |||||||||||||||||||||||||||||||||||||||||
| Unit No. 1 | 344.5 | 100 | 93 | 92 | 102 | 96 | 93 | ||||||||||||||||||||||||||||||||||
| Unit No. 2 | 344.7 | 92 | 100 | 95 | 93 | 102 | 97 | ||||||||||||||||||||||||||||||||||
| Plant Wansley | |||||||||||||||||||||||||||||||||||||||||
| Unit No. 1 | 261.6 | 75 | 90 | 95 | 4 | 14 | 9 | ||||||||||||||||||||||||||||||||||
| Unit No. 2 | 261.6 | 93 | 91 | 95 | 7 | 8 | 4 | ||||||||||||||||||||||||||||||||||
Combustion Turbine(4) | 0 | 61 | 62 | 41 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||
| Plant Scherer | |||||||||||||||||||||||||||||||||||||||||
| Unit No. 1 | 515.0 | 81 | 84 | 71 | 13 | 39 | 23 | ||||||||||||||||||||||||||||||||||
| Unit No. 2 | 515.0 | 97 | 77 | 96 | 40 | 41 | 52 | ||||||||||||||||||||||||||||||||||
Rocky Mountain(5) | |||||||||||||||||||||||||||||||||||||||||
| Unit No. 1 | 272.3 | 88 | 78 | 97 | 16 | 13 | 18 | ||||||||||||||||||||||||||||||||||
| Unit No. 2 | 272.3 | 90 | 44 | 77 | 19 | 11 | 16 | ||||||||||||||||||||||||||||||||||
| Unit No. 3 | 272.3 | 93 | 82 | 78 | 15 | 17 | 17 | ||||||||||||||||||||||||||||||||||
Doyle(5) | 281.0 | 60 | 50 | 55 | 3 | 2 | 1 | ||||||||||||||||||||||||||||||||||