UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWASHINGTON, 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 December 31, | |||||||||
OR | |||||||||
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||||||
Registrant's telephone number, including area code: (770) 270-7600 Securities registered pursuant to Section 12(b) of the Act: Securities registered pursuant to Section 12(g) of the Act: None ☐ INFORMATION standards, and potential penalties for non-compliance; hazards; 2019. 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 Proceeds of advances made under the facility co-signed with Georgia System Operations. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES " 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. its affiliates. 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. 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." 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. November 2022, respectively. the current construction schedule or budget. Service Area and Competition 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. and other power supply resources owned by the members. 9 megawatts. contracts, with an additional 332 megawatts under construction. full compliance with every applicable requirement. impoundment. In 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. 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. 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.
Georgia58-1211925Georgia 58-1211925 (State or other jurisdiction of
incorporation or organization)(I.R.S. employer
identification no.)
30084-5336Tucker, Georgia30084-5336(Address of principal executive offices) (Zip Code) None None o ☐ No ý ☒ý☐ Noo☒ o ☒No ý☐ electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý☒ No o☐ý☒Large accelerated filer ☐ Accelerated filer ☐ ý(Do not check if asmaller reporting company)☒Smaller reporting company Emerging growth company ☐ o☐o☐Noý☒no0 authorized or outstanding equity securities.no0 authorized or outstanding equity securities.2017ITEM Page PART I PART II PART III PART IV iSTATEMENTSdecisions madeGeorgia Public Service Commission in the regulatory process related to the two additional Vogtle units at Plant Vogtle;•increasing debt caused by significant capital expenditures;•unanticipated changes in capital expenditures, operating expenses and liquidity needs;•actions by credit rating agencies;•commercial banking and financial market conditions;•iilitigation or legal and administrative proceedings and settlements;• andhazards.278299 employees.4.14.2 million people. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES."www.opc.com.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.nearly two-thirdsmore than half of their aggregate power requirements primarily from our fleet of generation assets but also with power purchased from other power suppliers. We provide this service pursuant to long-term, take-or-pay wholesale power contracts. The wholesale power contracts obligate our members jointly and severally to pay rates sufficient for us to recover all the costs of owning and operating our power supply business, including the payment of principal and interest on our indebtedness and to yield a minimum 1.10 margins for interest ratio under our first mortgage indenture. Our members satisfy all of their power requirements above their purchase obligations to us with purchases from other suppliers. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES –Member– Member Power Supply Resources."7,8437,863 megawatts of summer planning reserve capacity, which includes 728738 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– Member Power Supply ResourcesResources" –Smarr EMC" and"PROPERTIES and "PROPERTIES – Generating Facilities."2017,2019, two of our members, Jackson EMC and Cobb EMC, accounted for 14.7%14.4% and 14.3%13.8% of our total revenues, respectively. Each of our other members accounted for less than 10% of our total revenues in 2017.approved future resources, whether or not that member has elected to participate in the resource, that are approved by 75% of the members of our board of directors, 75% of our members and members representing 75% of our patronage capital. For resources so approved in which less thanIn the event a member defaults on all members participate, costs areor a portion of its payment obligation, the default amount is shared first among the participating members and ifin 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.2017,2019, we supplied energy that accounted for approximately 63%58% of the retail energy requirements of our members. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES –Member– Member Power Supply Resources." will2017,2019, our equity ratio was 9.8%9.4%.2017,2019, we had approximately $8.2$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.Congress has authorized the Rural Utilities Service to charge a fee to cover the cost of loan guarantees for baseload generation, if requested by a borrower. The Rural Utilities Service must establish a process to implement this authorization prior to making it available to borrowers. The President's budget for fiscal year 2019,2021, which begins October 2018,2020, proposes a loan program of $5.5 billion, the same as the current program level. Although Congress has historically rejected proposals to dramatically curtail or redirect the Rural Utilities Service loan program, there can be no assurance that it will continue to do so. Because of these factors,However, we cannot predict the amount or cost of Rural Utilities Service loans that may be available to us in the future.2017,2019, we had $2.5 billion of outstanding loans guaranteed by the Rural Utilities Service and secured under our first mortgage indenture.will behave been used to reimburse us for a portion of certain costs of construction relating to two additional nuclear units at Plant Vogtle that are eligible for financing under the Title XVII Loan Guarantee Program. Aggregate borrowingsloan guarantee program.facility may not exceed $3.1 billion of eligible project costs, and asterm loan facility.2017,2019, we had borrowed $1.7advanced $3.0 billion under this loan. Advances may not occur after December 31, 2020.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. Following the bankruptcy of Westinghouse in March 2017, the loan guarantee agreement was amended to restrict advances pending the satisfaction of certain conditions, including the Department of Energy'sapproval of Bechtel Agreement and a further amendment to the loan guarantee agreement to incorporate provisions relating to the Bechtel Agreement and other replacement agreements. While not assured, we expect to satisfy these conditions in the second quarter of 2018. Under this 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,significant dispositions of system assets, including In September 2017, the Department of Energy issued a conditional commitment to us for $1.6 billion of additional guaranteed funding under the loan guarantee agreement. This additional funding is subject to an amendment and restatement of the loan guarantee agreement and satisfaction of certain other conditions. The conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. While not assured, we expect to close on this additional loan in the second quarter of 2018.current statusterms of the loan guarantee agreement, including conditions to future advances and potential repayment over a five-year period, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION –Financial Condition-Financing Requirements – Department of Energy –Guaranteed Loan" andNOTENote 7a of Notes to Consolidated Financial Statements. For additional information on Vogtle Units No. 3 and No. 4, see "– OUR POWER SUPPLY RESOURCES –Future– Future Power Resources –Vogtle Units No. 3 and No. 4."–Members'– Members' Relationship with Georgia Transmission and Georgia System Operations." Georgia System Operations provides support services to us in the areas of accounts payable, payroll, auditing, human resources, campus services, telecommunications and information technology at cost. We currently have$13.1$11.8 million of loans outstanding to Georgia System Operations, primarily for the purpose of financing capital expenditures. Georgia System Operations has an additional $4.0$4.5 million that can be drawn under one of its loans with us.development and 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.728738 megawatts. We provide operations, financial and management services for Smarr EMC. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."towith Green Power EMCSeeFor 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."Since 1973, however,However, the Georgia Territorial Act has permittedpermits 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. While the competition for 900-kilowatt loads represents onlyThis limited competition in Georgia, this competition has given our members the opportunity to develop resources and strategies to operate in a more competitive market. We routinely consider, along with our members, a wide arraynot only on the relative greenhouse gas emissions from a supplier's sources but also onand the nature of the regulation. Some of our generation sources emit greenhouse gases but we also have generation sources thatwhile others emit no greenhouse gases. Some ofnone. Comparatively, our competitors usemay rely on sources that emit proportionately more or less greenhouse gases while the sourcesthan we do. Further, many of some competitors emit less. Further,our members' third-party suppliers to our members are relyingalso 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 our members would be affected byany greenhouse gas regulation of the greenhouse gas emissions of these suppliers.suppliers affects our members. We believe our and our members' diverse portfolios of generation facilities, including the diversity of third-party suppliers, would mitigate any impactimpacts on our and our members' competitiveness resulting from any regulation. See "REGULATION – Environmental –Carbon Dioxide Emissions and Climate Change" and "RISK FACTORS." Depending on Among other conditions, for members providing broadband services through an affiliate, the natureGeorgia 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 the generation business in Georgia, there could be reasons for the members to separate their physical distribution business from their energy business,a member or otherwise restructure their current businesses to operate more effectively.–Results– Results of Operations – Factors Affecting Results." While changing weather patterns, whether resulting from greenhouse gas emissions or otherwise, could, under certain circumstances, alter seasonal weather patterns, predictions of future changes in weather patterns are inherently speculative, and we cannot make accurate conclusions about seasonality related to changes in weather patterns. Our energy revenues recover energy costs as they are incurred and also fluctuate month to month. Capacity revenues reflect the recovery ofare based upon budgeted expenditures and are generally recognized and billed to our fixed costs, which do not vary significantly from month to month; therefore, capacity charges are billed and capacity revenues are recognizedmembers in substantially equal monthly amounts.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.2017,2019, we supplied approximately 63%58% of the retail energy requirements of our members.7,8437,863 megawatts of summer planning reserve capacity, including 728738 megawatts of Smarr EMC assets, which we manage. ThisOur generation portfolio includes our interests in units fueled by nuclear, coal, natural gas, oil and water.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.–Member– Member Power Supply Resources –Smarr EMC."purchase small amounts of energy from a "qualifying facility" under the Public Utility Regulatory Policies Act of 1978. Under a waiver order from the Federal Energy Regulatory Commission, we historically made all purchases the members would have otherwise been required to make under the Public Utility Regulatory Policies Actsupply financial and we were relieved of our obligation to sell certainmanagement services to "qualifying facilities" so long as the members make those sales. In 2017, our purchases from this qualifying facility provided less than 0.1% of the energy we supplied to our members. Under their wholesale power contracts, the members may now make such purchases instead of us. We managesupport Green Power EMC's purchase of energy from 119160 megawatts of renewable resources.resources, plus an additional 424 megawatts under contract to be constructed. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources – Under the terms of the EPC Agreement, the Co-owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments. Toshiba Corporation guaranteed certain payment obligations of Westinghouse under the EPC Agreement (the Toshiba Guarantee),including any liability of Westinghouse for abandonment of work. Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. On In March 29, 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. In connection with the bankruptcy filing, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with Westinghouse and WECTEC Staffing Services LLC to provide for a continuation 27, 2017, upon the effective date of the Services Agreement discussed below. Subsequent to Westinghouse's bankruptcy filing, a number of subcontractors to Westinghouse alleged non-payment by Westinghouse for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken actions to remove liens on the site filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against Westinghouse and the Co-owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and payment of other Westinghouse pre-petition accounts payable have been paid or accrued as of December 31, 2017. On June 9, 2017, Georgia Power and the other Co-owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (the Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee was $3.68 billion (the Guarantee Obligations), of which our proportionate share was $1.1 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, the Co-owners, certain affiliates of the Municipal Electric Authority of Georgia, and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (the Settlement Agreement Amendment). The Settlement Agreement Amendment provided that Toshiba's remaining scheduled payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of the Co-owners and certain affiliates of the Municipal Electric Authority of Georgia against Westinghouse, and the Co-owners surrendered certain letters of credit securing a portion of Westinghouse's potential obligations under the EPC Agreement. Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement which was amended and restated on July 20, 2017 (the Services Agreement), forpursuant to which Westinghouse to transition construction management of Vogtle Units No. 3is providing facility design and No. 4 to Southern Nuclearengineering services, procurement and to provide ongoing design, engineering,technical support and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved Westinghouse's motion seeking authorization to (i) enter into the Services Agreement, (ii) assumestaff augmentation on a time and assign to the Co-owners certain project-related contracts, (iii) join the Co-owners as counterparties to certain assumed project-related contracts, and (iv) reject the EPC Agreement.materials cost basis. The Services Agreement and Westinghouse's rejection of the EPC Agreement, became effective upon approval by the Department of Energy on July 27, 2017. The Services Agreementprovides that it will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days'days’ written notice. Effective 23, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, wherebypursuant to which Bechtel will serveserves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). Facility design and engineering remains the responsibility of Westinghouse under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will beis reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel'sBechtel’s performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, Pursuant to the loan guarantee agreement between usthe Department of Energy, we are required to obtain the Department of Energy's approval of the Bechtel Agreement prior to obtaining any further advances under the loan guarantee agreement. On November 2, 2017, the Co-owners entered into an amendment to their jointScheduleagreements for Vogtle Units No. 3 and No. 4 (as amended, the Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. 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 if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power 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 because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in Georgia Power's seventeenth Vogtle construction monitoring (VCM) report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Joint Ownership Agreements, the required approval of holders of ownership interestsinterest 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. On December 21, 2017, the Georgia Public Service Commission took a series of actions related to the construction of Vogtle Units No. 3 and No. 4 and issued its related order on January 11, 2018. Among other actions, the Public Service Commission (i) accepted Georgia Power's recommendation that construction of Vogtle Units No. 3 and No. 4 be completed, with Southern Nuclear Operating Company, Inc. serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Public Service Commission reserve the right to reconsider the decision to continue construction. Parties have filed two petitions with the Fulton County Superior Court appealing the Georgia Public Service Commission's January 11, 2018 order. Georgia Power has stated that it believes these appeals have no merit; however, an adverse outcome in one or both of these appeals could have a material impact on our financial condition and results of operations. We expect Vogtle Units No. 3 and No. 4 to be placed in service by November 2021 and November 2022, respectively. Our project budget for the additional Vogtle units is $7.0$7.5 billion, which includes capital costs, allowance for funds used during construction, our allocation of the project-level contingency and a contingency amount. This budget is net of the $1.1 billion of payments we received from Toshiba under the Guarantee Settlement Agreement.separate Oglethorpe-level contingency. As of December 31, 2017,2019, our total investment in the additional Vogtle units was approximately $2.9 billion, net of the payments received from Toshiba under the Guarantee Settlement Agreement. The payments from Toshiba were recorded as a reduction to the construction work in progress balance for the additional Vogtle units. In the event the Vogtle project is cancelled, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230 million. If the project is cancelled, we would seek regulatory accounting treatment to amortize our investment in the Vogtle project over a long-term period which would require the approval$4.9 billion. We and some of our board of directors andmembers have implemented various rate management programs to lessen the Rural Utilities Service. We have a $3.1 billion federal loan guarantee from the Department of Energy, under which we have advanced $1.7 billion as of December 31, 2017. Pursuant to the terms of the loan guarantee agreement, no further advances are permitted pending satisfaction of certain conditions, including approval of the Bechtel Agreement and an amendment to the loan guarantee agreement to incorporate provisions relating to the Bechtel Agreement and other replacement agreements. While not assured, we expect to satisfy these conditions in the second quarter of 2018. On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to $1.6 billion of additional guaranteed funding under the loan guarantee agreement. This conditional commitment expiresimpact on June 30, 2018, subject to any extension approved by the Department of Energy. Final approval and issuance of the additional loan guarantee by the Department of Energy cannot be assured and is subject to an amendment and restatement of the loan guarantee agreement and satisfaction of certain other conditions. For additional information regarding conditions for future advances, potential repayment over a five-year period, covenants and events of default under the loan guarantee agreement with the Department of Energy, see Note 7 of Notes to Consolidated Financial Statements. We have also financed an additional $1.4 billion of the capital costs of the Vogtle units through capital market debt issuances. For additional information regarding the financing of Vogtle Units No.3 and No.4, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –Financial Condition – Financing Activities – Department of Energy-Guaranteed Loan" and "Capital Requirements – Capital Expenditures." Under the Bipartisan Budget Act of 2018, we qualify for nuclear production tax credits related torates when Vogtle Units No. 3 and No. 4. We expect to receive these tax credits in accordance with4 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.ownership 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.are analyzing various optionsNo. 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 monetize these creditsmaintain 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 third party.backlog of activities and completion percentages below the April 2019 aggressive strategy targets.estimatebelieve the production levels and timeframes in this benchmark provide reasonable assurance that Units No. 3 and No. 4 will meet the nominal valueregulatory-approved in-service dates of our allocation of production tax credits will be approximately $660 millionNovember 2021 and will be earned for eight years post commercial operation.construction-related challenges includingwith management of contractors subcontractors, and vendors,vendors; subcontractor performance; supervision of craft labor and related craft labor productivity, particularly in the installation of electrical and availability,mechanical commodities, ability to attract and retain craft labor and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and installationthe initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures andor 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. AspectsWestinghouse AP1000 designconstruction site, including limiting exposure of individuals who are basedshowing 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 new technologies and commercial operation of this design has yet to be tested.resolutionsubmittal by Southern Nuclear of inspections, tests, analyses, and acceptance criteriadocumentation 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."RISK FACTORS"“RISK FACTORS” for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.4.14.2 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.20152017 through 2017,2019, and also shows the amount of their energy requirements that we supplied. From 20152017 through 2017,2019, peak demand of the members and their energy requirements have fluctuated based on various factors, including milder weather in 2015 and 2017. In 2016, the amount of energy we supplied to the members increased nearly 40%, primarily as a result of the use of Smith Energy Facility to meet the members' energy requirements, as well as an increase in total member requirements.Member Energy Requirements (MWh) 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
Member Energy Requirements (MWh) Member Peak
Demand (MW) Supplied by Oglethorpe(3) Total(1) Total(2) 2017 8,716 37,880,696 23,813,679 2016 9,194 39,668,000 25,522,852 2015 8,964 38,323,141 18,371,558 We supplied none of Flint's energy requirements in 2015 but began supplying energy to Flint in 2016. Also includes energy we supplied to our own facilities. Since 1973, thehas allowedallows 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. While the competition for 900-kilowatt loads represents onlyThis limited competition in Georgia, this competition has given our members and us the opportunity to develop resources and strategies to operate in an increasingly competitive market.–Competition.– Competition."–Wholesale– 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.2019,2021, which begins October 2018,2020, proposes a loan program level of $5.5 billion, the same as the current program level. Although Congress has historically rejected proposals to dramatically curtail or redirect the Rural Utilities Service loan program, there can be no assurance that it will continue to do so. Because of these factors,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."see"OGLETHORPEsee "OGLETHORPE POWER CORPORATION – Relationship with Georgia System Operations Corporation."2017,2019, we supplied approximately 63%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 Power2017,2019, the aggregate SEPA allocation to the members was 618529 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, 3735 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.728738 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.119160 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, 8 megawattsnine solar facilities with a total of solar facilities.53 to 2430 years.156266 megawatts from solar facilities under long-term contracts.and"OURand "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.variousa 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 broadlycomprehensively regulated.mayif 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 includeeven require the complete shutdown of individual generating units not in compliance.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 it is our intentwe intend to comply with all current and future regulations, we cannot provide assuranceguarantee that we will always be in compliance.see"MANAGEMENT'Ssee "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –Financial– Financial Condition –Capital Requirements –Capital Expenditures."concerns ofregulations adopted at the public, the scientific communityfederal and government officialsstate levels have resulted in legislation and regulation that has had and will continue to have a significant impact on the electric utility industry. The most significant environmental legislationregulations for us continuescontinue to be the requirements imposed under the Clean Air Act, which regulatesAct. 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-related actionsAct regulatory requirements that affect or may affect our business. Regulatory Reform. Through a series of Executive Orders, the Trump Administration is requiring many federal agencies, including EPA, to review their regulations and make recommendations regarding the repeal, replacement or modification of certain regulations. Regulations that (i) adversely affect jobs, (ii) are outdated, unnecessary or ineffective, (iii) impose costs exceeding benefits or (iv) interfere with regulatory reform initiatives and policies are to be identified for further action. Pursuant to an Executive Order entitled "Promoting Energy Independence and Economic Growth," EPA has undertaken a number of actions to reconsider and in some cases repeal existing regulations. Where appropriate, reference to such actions are made in the context of the specific regulatory programs discussed below. We cannot predict EPA's actions regarding these regulatory reforms or the effects from any litigation that may result from this extensive effort. common air pollutants: particulate matter, ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen dioxide and lead. EPA will periodicallyis required to review the variousexisting NAAQS every five years to determine whether any standards should be made more stringent. InPursuant to a review completed in 2015, EPA loweredtightened the NAAQS for ground-level ozone. In response to EPA's adoption of the 2015 eight-hour ozone andNAAQS, Georgia submitted its proposed ozone air quality designations recommendingand recommend that only eight counties in the Atlanta area be designated nonattainment, with"nonattainment" and the remainderother counties in Georgia be classified as attainment"attainment or unclassifiable." Nonattainment is defined as having air quality worse thanthat fails to meet the NAAQS as defined inminimum levels established by the Clean Air Act and amendments of 1990. Late in 2017, EPA concurred with Georgia's recommendations and plans to formally propose suchNAAQS. In 2018, the nonattainment designations for those eight counties in Georgia later this year. Once finalized, Georgiabecame effective.revise itsfollow in implementing the control measures and other applicable requirements necessary to achieve the 2015 NAAQS ozone standard through State Implementation Plan (SIP)Plans (SIPs). For Georgia, the SIP will establish control measures and other requirements to demonstrate attainment.Measures taken could affectthe major stationary sources located within the designated eight counties or sourcesand in surrounding counties if those emissions are deemed to contribute significantly to the nonattainment status of this new Atlanta ozone nonattainment area. In 2017, EPA redesignated to attainment all of the counties that were part of the 2008 eight-hour Atlanta ozone nonattainment area. Georgia must submit its SIP to EPA also took actionby August 3, 2021.2017 to designate nonattainment areas for other NAAQS, such as the 2010 one-hour SO2 NAAQS, where all countiesneighboring states. At this time, no determination has been made regarding whether emissions sources in Georgia except Floyd County were designated as attainment/unclassifiable, and the nitrogen dioxide NAAQS, where EPA proposed no further changesare significantly contributing to the standards. such an ozone nonattainment air quality problem.for theto reduce emissions and achieve current suite of NAAQS, the implementation ofambient air quality standards, new or revised NAAQS could lead to additional complianceemissions 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. Cross State Air Pollution Rule. To address the interstate transport of ozone and fine particulate matter, EPA finalized the Cross State Air Pollution Rule (CSAPR) in 2011, imposing cap and trade programs for sulfur dioxide and nitrogen oxides emissions on fossil fuel-fired electric generating units located in twenty-eight states, including Georgia. EPA has adopted specific trading programs to address these emissions and Georgia is subject to three distinct CSAPR trading programs. Currently, we believe that sufficient controls have been installed on our units, including the co-owned units at Plants Scherer and Wansley, such that compliance with the current CSAPR, including all allowance programs, can be maintained. Mercury and Air Toxics Standards and State Mercury Rule. In December 2011, EPA finalized its Mercury and Air Toxics Standards (MATS), which established maximum achievable control technology limits for certain hazardous air pollutants at coal and oil-fired electric generating units. For coal units, the rule sets stringent emission limits to control various hazardous air pollutants such as mercury, non-mercury metals and acid gases and work practice standards to control organics and dioxins. Our affected generating units, which include our co-owned units at Plants Wansley and Scherer, must comply with MATS. In 2015, the U.S. Supreme Court ruled that EPA must consider costs before finalizing MATS and remanded the rule back to EPA for further rulemaking consistent with its opinion. In 2016, EPA released a supplemental finding that it is appropriate and necessary to regulate hazardous air pollutants from coal and oil-fired electric generating units, and that MATS is reasonable. Cases challenging this determination are pending in the U.S. Circuit Court of Appeals for the District of Columbia Circuit, and have been delayed pending EPA reconsideration of the supplemental finding. We cannot predict the outcome of this rule or any related litigation concerning MATS, but even if MATS is ultimately overturned, we would still need to comply with Georgia's "multi-pollutant" rule which requires operation of existing controls at Plants Wansley and Scherer. Startup, Shut-down or Malfunction. In 2015, EPA published a rule requiring 36 states, including Georgia, to revise their SIPs relating to excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction (SSM). Georgia finalized a state rule and submitted a corresponding SIP revision to EPA prior to the applicable deadlines. However, Georgia's revised rule and SIP revision will not become effective unless EPA approves the SIP submittal, which has not occurred. EPA has delayed current litigation challenging the rule while it reconsiders these standards as part of its regulatory reform review. While EPA may withdraw or change the rule, we cannot predict the ultimate outcome of this rulemaking or any related litigation.controlsemission 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 thenew implementation approaches selectedadopted by EPA and Georgia could require significant capital expenditures and increased operating expenses at certain of our generating facilities, particularly Plants Scherer and Wansley. Several of the Obama Administration's actions to limit carbon dioxide emissions have been curtailed by the Trump Administration. Some of the actions that could potentially have a direct effect on our operations are summarized below. 10.910.2 million short tons in 2017, as compared to 12.9 million short tons in 2016.2019. AfterOn July 8, 2019, the U.S. Supreme Court ruled in 2007 that certain greenhouse gases, including carbon dioxide, are pollutants which EPA has the authority to regulate under the Clean Air Act, EPA determined that regulation was needed. Beginning in 2009, EPA issued a series of rules that apply the final Affordable Clean Air Act Prevention of Significant Deterioration and Title V permitting programsEnergy (ACE) rule to stationary source emissions of greenhouse gases. In 2015, EPA published a series of rules, known asrepeal the Clean Power Plan (CPP), which was one of the most significant regulatory actions to reduce greenhouse gas emissions. In the CPP, EPA established New Source Performance Standards (NSPS)and adopt a replacement rule for new, modified or reconstructed fossil fuel-fired electric generating units. For existing fossil fuel-fired electric generating units, EPA established guidelines for the states to follow in developing final NSPS for such units. Those guidelines became uniform national emission rates for existing units that states were required to incorporate into state rules and performance standards. A lynchpin of the CPP was EPA's interpretation that it could establish emissions guidelines beyond the fence line of regulated sources and require system-wide reductions inregulating carbon dioxide emissions from source ownersexisting 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 operators. In 2016,other factors when setting performance standards to limit carbon dioxide from affected units and to establish compliance requirements and deadlines.U.S. Supreme Court stayed the CPPACE rule are pending resolution of litigation challenging the CPP inbefore the U.S. Court of Appeals for the DistrictD.C. Circuit. The ultimate impact of Columbia Circuit includingthe 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 appealadditional improvements will be minor.Supreme Court. That litigation has been delayedNSR 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 pending reconsiderationrulemaking action in 2020.the CPP rule. In October 2017, EPA proposed a rule to repeal the CPP, in large part on the revised interpretation that emission guidelines for affected existing sources are limited to the steps source owners and operators can takecarbon dioxide could occur at the regulated source.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 December 2017,addition, EPA also issued an Advance Notice of Proposed Rulemaking seeking information on the steps existing sources could take that would be consistent withregulatory actions to require more stringent control requirements to reduce carbon dioxide emissions under its existing legal authority. At this revised interpretation. EPA may take other actions in the future to address the emissions of greenhouse gases from our units. For example, EPA may seek to revisit and perhaps reconsider its NSPS for new and modified fossil fuel-fired electric generating units. Wetime, we cannot predict the outcome of any legislative or regulatory changes agency actions, including but not limited toor the withdrawal or revisionresult of guidance, or executive orders related to climate change, nor can we predict the outcome or effect of possiblepotential litigation resulting fromchallenging any of these actions. In November 2015, the Paris Agreement was adopted at the United Nations 21st International Climate Change Conference. It established a non-binding universal framework for addressing greenhouse gas emissions based on nationally determined commitments as well as a process for increasing those commitments going forward. On June 1, 2017, President Trump announced that the U.S. would cease all participation in the 2015 Paris Agreement, stating that the accord would undermine the U.S. economy and put it at a permanent disadvantage. We are unable to determine the ultimate impact of this action on our operations or costs.publishedestablished a comprehensive regulatory program to manage the disposal of coal combustion residuals (CCR) rule to regulate CCRs from electric utilities as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act.Act (RCRA). The 2015 CCR rule containssets 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 March 2018 EPA published a proposed rule to update the 2015 CCR rule. A final rule is expected later in 2018. In 2015, the EPA also finalized a rule to revise the effluent limitations guidelines (ELG) that applyapplies to certain wastewater discharges from fossil fuel-fired steam electric power plants, including our co-owned Plants WansleyScherer and Scherer.postponed certainextended the ELG compliance dates relateddeadlines 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 effluent limitations guidelines. rule. and in response to EPA's CCR rulemaking, the Georgia Environmental Protection Division added specific provisions for(EPD) adopted new requirements to regulate CCR wastes to its existing solid waste management rules.wastes. These new rules containincorporated EPA's CCR rule requirements as well as furtherState-only requirements for managing CCR wastes in Georgia. The additionalThese State requirements were implemented and are administeredenforced through a state permit system. Citizen groups retain the authoritysystem 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. At this point,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 future changes to Georgia's CCR regulations including potential legislation or litigation initiatives.the effluent limitations guidelines.2015,2019, Georgia Power announced that it is preparing a scheduleceased sending CCR to close existingthe ash ponds at all of its Georgia coal-fired facilities, including at our co-owned Plants Scherer and Wansley. In 2016,Similarly, Georgia Power further announcedis in the final stages of completing a new wastewater treatment system that it would cease sendingwill 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 to allis now pending, we cannot predict whether there will be any future lawsuits on the requirements for closing these impoundments or remedying any impacts of its ash ponds inthe impoundments may be having on groundwater.within three years. It also announced that it wouldPower applied for CCR permits to close the ash ponds at Plants Scherer and Wansley in place using advanced engineering methods at Plants Wansley and Scherer, among other locations.methods. The initial closure planspermit applications Georgia Power filed with the Georgia Environmental Protection DivisionEPD 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 $173$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, preliminarycurrent estimates suggest that our capital expenditures to comply with the applicable CCR rulerequirements and effluent discharge limitations guidelines will be approximately $273$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 processprocesses of rule evaluation, compliance approach and design and construction implementation proceeds.proceed. The ultimate impacts associated with the federal and state CCR rules and the federal effluent discharge limitations, guidelines, any changes EPA may make to those rules,revised regulation or legislation at the state or federal level and any related litigation challenging such rules, or future legislation cannot be determined at this time. In 2008, the Georgia legislature adopted a comprehensive State Water Plan that lays out statewide policies, management practices and guidance for regional water planning in Georgia. In 2011, the Georgia Environmental Protection Division adopted regional water plans that were developed pursuant to the State Water Plan. Regional plans include resource assessments, estimates of current and future water needs and management practices. Updated draft regional water plans have been developed and were issued for public notice and comment in 2017. Georgia will consider the information contained in regional water plans (including any updated plans) when making water use permitting decisions under existing state law. The state water planning process may lead to new or revised regulations for water users in the future. Because power generation is generally dependent on water usage, the regional water plans and any future regulations or other enforceable requirements developed in connection with the State Water Plan may have substantial effects on the operations of our facilities or future facilities that we construct or acquire. The impacts of future regulations or revisions to regional water plans on our facilities or future facilities cannot be determined at this time.rule.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 states that it will pursueproposed a formal rulemaking to substantively re-evaluaterule 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 and may substantially revise that rule. Weincorporating the proposed rules was issued on the 2015 rule, any change to that rule or any litigation challenging that rule or any replacement rule at this time.to 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 resultsoperation of operations.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.causeeven force the complete shutdown of individual generating units not in compliance with these regulations.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.–Future– Future Power Resources –Plant Vogtle Units No. 3 and No. 4."
30% ownership interest. from the Federal Financing Bank and a related loan guarantee from the Department of Energy pursuant to 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. ” interests in these facilities expose us to various risks, including: ” 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. facilities could be limited. 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 Unit No. 1 Unit No. 2 Unit No. 1 Unit No. 2 Unit No. 1 Unit No. 2 Combustion Turbine Unit No. 1 Unit No. 2 Units No. 1-4 Units No. 5-6 Unit No. 1 Unit No. 2 Unit Plant Hatch Unit No. 1 Unit No. 2 Plant Vogtle Unit No. 1 Unit No. 2 Plant Wansley Unit No. 1 Unit No. 2 Combustion Turbine(4) Plant Scherer Unit No. 1 Unit No. 2 Rocky Mountain(5) Unit No. 1 Unit No. 2 Unit No. 3 Doyle(5) Talbot(5) Chattahoochee Hawk Road(5) Hartwell(5) Smith Unit No. 1 Unit No. 2 TOTAL Co-Owners of Plants Oglethorpe Georgia Power MEAG Dalton Total among Georgia Power, MEAG, equal to the percentage of its undivided interest which is owned or leased in such plant or unit. Georgia Power is required to furnish budgets for operating costs, fuel plans and scheduled maintenance plans. In the case of Scherer Units No. 1 and No. 2, the participants have limited rights to disapprove such budgets proposed by Georgia Power and to substitute alternative budgets. The Ownership Agreements and Operating Agreements provide that, should a participant fail to make any payment when due, among other things, such nonpaying participant's rights to output of capacity and energy would be suspended. STATEMENTS OF REVENUES AND EXPENSES DATA Operating revenues: Sales to Members Sales to non-Members Total operating revenues Operating expenses: Fuel Production Depreciation and amortization Purchased power Accretion Deferral of Hawk Road and Smith Energy Facilities effect on net margin Total operating expenses Operating margin Other income, net Net interest charges Net margin BALANCE SHEET DATA Electric plant, net: In service Nuclear fuel, at amortized cost Construction work in progress Total electric plant Total assets Capitalization: Long-term debt Obligations under capital leases Obligations under Rocky Mountain transactions Patronage capital and membership fees Accumulated other comprehensive (gain) loss Subtotal Less: long-term debt and capital leases due within one year Less: unamortized debt issuance costs Less: unamortized bond discounts on long-term debt Total capitalization Cash paid for property additions OTHER DATA Energy supply (megawatt-hours): Generated Purchased Available for sale Member revenues per kWh sold However, strategic financing and refinancing of capital investments with long-term debt through the Department of Energy and Rural Utilities Service loan guarantee programs, taxable and tax-exempt capital markets offerings and a continued low interest rate environment have enabled us to decrease our weighted average interest cost on long-term debt from 5.41% per year at December 31, 2009 to 3.96% per year at December 31, 2019. We will continue to actively manage our debt portfolio and utilize advantageous borrowing programs available to us as our ability to borrow at lower costs ultimately benefits our members and their customers as interest savings are reflected in our pass-through rate structure. retail distribution costs. related estimates and assumptions with the audit committee of our board of directors. pronouncements Notes to Consolidated Financial Statements. significant. participate. Variable costs are passed through to our members state agency or authority, including the Georgia Public Service Commission. arrangements, which account for a significant portion of the energy they purchase. In 2019, our energy generation and member sales were modestly higher than in 2018; primarily due to low gas prices resulting in more generation from our combined cycle and simple cycle gas resources. trend downward in 2019. In 2017. 2018. Capacity revenues Energy revenues Total kWh Sales Cents/kWh Member energy requirements supplied Capacity revenues Fuel Source Coal Nuclear Natural Gas: Combined Cycle Combustion Turbine Total fuel outages in a given year. Production costs decreased Financial Condition See "– through November 2023. See "– relationship with the Department of Energy and Rural Utilities Service. 2019. information regarding our plans related to these pollution control bonds. Unsecured Facilities: Syndicated Line among 13 banks led by CFC CFC Line of Credit(2) December 2018 JPMorgan Chase Line of Credit October 2018 Secured Facilities: CFC Term Loan(2) and backing up commercial paper. account. As of December 31, 2019, the amount of certified bondable additions and retired or defeased first mortgage indenture obligations available for the issuance of additional first mortgage indenture obligations was approximately $2.1 billion. In addition, as of December 31, 2019, we had over $348 million of property additions and certified progress payments under qualified engineering, procurement and construction contracts that, once certified in accordance with the first mortgage indenture, will be available for the issuance of additional first mortgage indenture obligations. All of the debt advanced under the loan guarantee agreement is secured ratably with all other debt under our first mortgage indenture. For additional information regarding 2018. All the pollution control revenue bonds are secured Capital Expenditures(1) (dollars in millions) Future Generation(2) Existing Generation(3) Environmental Compliance(4) Nuclear Fuel(5) General Plant Total We are currently subject to extensive environmental regulations and may be subject to future additional environmental regulations, including future implementation of existing laws and regulations. Since alternative legislative and regulatory environmental compliance programs continue to be debated on a state and national level, we cannot predict what capital costs may ultimately be required. Therefore, environmental expenditures included in the above table only include amounts related to budgeted projects to comply with existing and certain well-defined rules and regulations and do not include amounts related to compliance with other, less certain rules. Contractual Obligations (dollars in millions) Long-Term Debt: Principal(1) Interest(2) Capital Leases(3) Operating Leases Rocky Mtn.Lease Transaction(4) Chattahoochee O&M Agmts. Asset Retirement Obligations(5) Purchase Commitments(6) Total Long-term ratings: Rating outlook Short-term rating: Commercial paper rating specified levels, could result in increased interest rates. Also, borrowing rates, letter of credit fees and commitment fees in two of our repricing in February 2023. and 1.0% of our total debt classified as intermediate-term fixed rate. The remaining 90.4% of our debt was classified as long-term fixed rate. Notes to Consolidated Financial Statements. respectively. Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Operating revenues: Sales to Members Sales to non-Members Total operating revenues Operating expenses: Fuel Production Depreciation and amortization Purchased power Accretion Deferral of Hawk Road and Smith Energy Facilities effect on net margin Total operating expenses Operating margin Other income: Investment income Amortization of deferred gains Allowance for equity funds used during construction Other Total other income Interest charges: Interest expense Allowance for debt funds used during construction Amortization of debt discount and expense Net interest charges Net margin Net Margin Other comprehensive margin: Unrealized loss on available-for-sale securities Amounts reclassified to regulatory assets Total comprehensive margin Assets Electric plant: In service Less: Accumulated provision for depreciation Nuclear fuel, at amortized cost Construction work in progress Total electric plant Investments and funds: Nuclear decommissioning trust fund Investment in associated companies Long-term investments Restricted investments Other Total investments and funds Current assets: Cash and cash equivalents Restricted short-term investments Receivables Inventories, at average cost Prepayments and other current assets Total current assets Deferred charges and other assets: Regulatory assets Prepayments to Georgia Power Company Other Total deferred charges Total assets The accompanying notes are an integral part of these consolidated financial statements. Equity and Liabilities Capitalization: Patronage capital and membership fees Accumulated other comprehensive deficit Long-term debt Obligations under capital leases Other Total capitalization Current liabilities: Long-term debt and capital leases due within one year Short-term borrowings Accounts payable Accrued interest Member power bill prepayments, current Other current liabilities Total current liabilities Deferred credits and other liabilities: Asset retirement obligations Member power bill prepayments, non-current Contract retainage Regulatory liabilities Other Total deferred credits and other liabilities Total equity and liabilities Commitments and Contingencies (Notes 1, 7, 10, 11 and 12) Secured Long-term debt: First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.84% to 8.43% (average rate of 4.02% at December 31, 2017) due in quarterly installments through 2043 First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.51% to 3.87% (average rate of 3.36% at December 31, 2017) due in quarterly installments through 2044 First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.55% to 4.90% (average rate of 4.69% at December 31, 2017) due in quarterly installments through 2020 First mortgage bonds payable: • Series 2006 • Series 2007 • Series 2009A • Series 2009B • Series 2009 • Series 2010A • Series 2011A • Series 2012A • Series 2014A • Series 2016A First mortgage notes issued in connection with the sale of pollution control revenue bonds through the Development Authorities of Appling, Burke, Heard and Monroe Counties, Georgia: • Series 2003A Burke, Heard, Monroe and 2003B Burke • Series 2004 Burke and Monroe • Series 2005 Burke and Monroe • Series 2008A through 2008C Burke • Series 2008E Burke • Series 2009A Heard and Monroe, and 2009B Monroe • Series 2010A Burke and Monroe, and 2010B Burke • Series 2013A Appling, Burke and Monroe • Series 2017A Burke, Heard, Monroe and 2017B Burke • Series 2017C, D Burke • Series 2017E, F Burke CoBank, ACB notes payable: • Transmission first mortgage notes payable: variable, paid in full January 2017 • Transmission first mortgage notes payable: variable, paid in full January 2017 Total Secured Long-term debt Obligations under capital leases Obligation under Rocky Mountain transactions Patronage capital and membership fees Accumulated other comprehensive (deficit) Subtotal Less: long-term debt and capital leases due within one year Less: unamortized debt issuance costs Less: unamortized bond discounts on long-term debt Total capitalization Cash flows from operating activities: Net margin Adjustments to reconcile net margin to net cash provided by operating activities: Depreciation and amortization, including nuclear fuel Accretion cost Amortization of deferred gains Allowance for equity funds used during construction Deferred outage costs Deferral of Hawk Road and Smith Energy Facilities effect on net margin (Gain) loss on sale of investments Regulatory deferral of costs associated with nuclear decommissioning Other Change in operating assets and liabilities: Receivables Inventories Prepayments and other current assets Accounts payable Accrued interest Accrued and withheld taxes Other current liabilities Member power bill prepayments Total adjustments Net cash provided by operating activities Cash flows from investing activities: Property additions Guarantee settlement proceeds Activity in nuclear decommissioning trust fund – Purchases – Proceeds Increase in restricted investments Decrease (increase) in restricted short-term investments Activity in other long-term investments – Purchases – Proceeds Other Net cash used in investing activities Cash flows from financing activities: Long-term debt proceeds Long-term debt payments Increase (decrease) in short-term borrowings, net Other Net cash (used in) provided by financing activities Net increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period Supplemental cash flow information: Cash paid for – Interest (net of amounts capitalized) Supplemental disclosure of non-cash investing and financing activities: Change in asset retirement obligations Change in accrued property additions Interest paid-in-kind The accompanying notes are an integral part of these consolidated financial statements. Balance at December 31, 2014 Components of comprehensive margin in 2015 Net margin Unrealized loss on available-for-sale securities Total comprehensive margin Balance at December 31, 2015 Components of comprehensive margin in 2016 Net margin Unrealized loss on available-for-sale securities Total comprehensive margin Balance at December 31, 2016 Components of comprehensive margin in 2017 Net margin Amounts reclassified to regulatory assets Total comprehensive margin Balance at December 31, 2017 The accompanying notes are an integral part of these consolidated financial statements. 2017 each fiscal year. For the years members were as follows: Jackson EMC Cobb EMC Sawnee EMC We have a rate management program that allows us to expense and recover $88,486,000. Balance at December 31, 2016 Liabilities settled Accretion Change in cash flow estimates Balance at December 31, 2017 Balance at December 31, 2015 Liabilities settled Accretion Change in cash flow estimates Balance at December 31, 2016 the estimated costs of decommissioning co-owned nuclear facilities 2015 site study Expected start date of decommissioning Estimated costs based on site study in 2015 dollars: Radiated structures Spent fuel management Non-radiated structures Total estimated site study costs We have established funds to comply with the Nuclear Regulatory Commission regulations regarding the decommissioning of our nuclear plants. See Note 1i for information regarding the nuclear decommissioning funds. a diversified mix of approximately 64% equity and 36% fixed income securities in 2019 and 60% equity and 40% fixed income External Trust Funds: Equity Debt Other Total Internal Funds: Equity Debt Total External Trust Funds: Equity Debt Other Total Internal Funds: Equity Debt Total Steam production Nuclear production Hydro production Other production Transmission General l. Cash and cash equivalents 1q. will be applied in the future to reduce revenues required to be recovered from members. Regulatory Assets: Premium and loss on reacquired debt(a) Amortization on capital leases(b) Outage costs(c) Asset Retirement Obligations – Ashpond and other(k) Depreciation expense(d) Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(e) Interest rate options cost(f) Deferral of effects on net margin – Smith Energy Facility(g) Other regulatory assets(l) Total Regulatory Assets Regulatory Liabilities: Accumulated retirement costs for other obligations(h) Deferral of effects on net margin – Hawk Road Energy Facility(g) Major maintenance reserve(i) Amortization on capital leases(b) Deferred debt service adder(j) Asset retirement obligations – Nuclear(k) Other regulatory liabilities(l) Total Regulatory Liabilities Net regulatory assets Capital credits from associated companies (Note 4) Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs Miscellaneous other Total t. January 1, 2019. For additional information, see Note 6. adopted earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. significant. financial instruments are those whose fair value is based on significant unobservable inputs. Nuclear decommissioning trust funds: Domestic equity International equity trust Corporate bonds and debt US Treasury securities Mortgage backed securities Domestic mutual funds Municipal bonds Federal agency securities Other Long-term investments: International equity trust Corporate bonds and debt US Treasury securities Mortgage backed securities Dometic mutual funds Federal agency securities Other Natural gas swaps Nuclear decommissioning trust funds: Domestic equity International equity trust Corporate bonds and debt US Treasury securities Mortgage backed securities Municipal bonds Federal agency securities Other Long-term investments: International equity trust Corporate bonds and debt US Treasury securities Mortgage backed securities Domestic mutual funds Federal agency securities Other Natural gas swaps The Level 2 investments above in corporate bonds and debt, federal agency mortgage backed securities, and Long-term debt The estimated fair value of long-term debt is classified as Level 2 and is Realized gains and losses on natural gas swaps are included in fuel expense within our consolidated statements of revenues and expenses and, therefore, net margins within our consolidated statements of cash flows. Year 2018 2019 2020 2021 2022 Total The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at December 31, Assets Natural gas swaps Natural gas swaps Liabilities Natural gas swaps Natural gas swaps The following table presents the realized gains and (losses) on derivative instruments recognized in margin for the years ended December 31, Consolidated 2017 2016 2015 Natural Gas Swaps Natural Gas Swaps Total The following table presents the unrealized Natural Gas Swaps Natural Gas Swaps Interest Rate Options Total 4. Investments: 2017 Equity Debt Other Total 2016 Equity Debt Other Total $148,638,000 were in an unrealized loss position for less than one year. Due within one year Due after one year through five years Due after five years through ten years Due after ten years Total The following table summarizes the realized gains and losses and proceeds from sales of securities for the years ended December 31, Gross realized gains Gross realized losses Proceeds from sales Investment in associated companies National Rural Utilities Cooperative Finance Corporation (CFC) CT Parts, LLC Georgia Transmission Corporation Georgia System Operations Corporation Other Total The CFC investments consist of capital term certificates required in connection with our membership in CFC and a voluntary investment in CFC member capital securities. Accordingly, there is no market for these investments. The investment in Georgia Transmission represents capital credits. The investment in Georgia System Operations represents loan advances. Repayments of these advances are due by December 2024. $36,555,000. interest in Rocky Mountain to the owner trust, the owner trust has several options it can elect, including: Statutory federal income tax rate Patronage exclusion AMT credit monetization Other Effective income tax rate Deferred tax assets Net operating losses Tax credits (alternative minimum tax and other) Accounting for Rocky Mountain transactions Other assets Deferred tax assets Less: Valuation allowance Net deferred tax assets Deferred tax liabilities Depreciation Accounting for Rocky Mountain transactions Other liabilities Deferred tax liabilities Net deferred tax liabilities Less: Patronage exclusion Net deferred taxes Expiration Date 2018 2019 2020 Year Ending December 31, 2018 2019 2020 2021 2022 2023-2031 Total minimum lease payments Less: Amount representing interest Present value of net minimum lease payments Less: Current portion Long-term balance FFB FMBs PCBs(1) CFC Capital Leases Total FFB FMBs PCBs CFC CoBank We use the effective interest rate method to amortize debt issuance costs and debt discounts as well as the straight-line method when the results approximate those of the effective interest rate method. Unamortized debt issuance costs and debt discounts are being amortized to expense over the life of the respective debt issues. Department of Energy agreed to guarantee our obligations under At December 31, 2019, we had advanced all amounts available under the Original FFB Note. We were unable to advance $43,721,079 of the amount designated for capitalized interest under the Original FFB Note due to the timing of our borrowings and lower than expected interest rates. Eligible Project Costs and (viii) if either the Services Agreement or the Bechtel Agreement (each, as described in Note 8) are terminated, or rejected in bankruptcy proceedings, the Department of Energy has approved the replacement agreement. If we receive proceeds from an event of condemnation relating to Vogtle Units No. 3 and No. 4, such proceeds must be applied to immediately prepay outstanding borrowings under the Facility. The weighted average interest rate on short-term borrowings at December 31, Plant In-service(1) Owned property Vogtle Units No. 1 & No. 2 Vogtle Units No. 3 & No. 4 Hatch Units No. 1 & No. 2 Wansley Units No. 1 & No. 2 Scherer Unit No. 1 Doyle(Combustion Turbine - 100% ownership) Rocky Mountain Units No. 1, No. 2 & No. 3 Hartwell(Combustion Turbine - 100% ownership) Hawk Road(Combustion Turbine - 100% ownership) Talbot(Combustion Turbine - 100% ownership) Chattahoochee(Combined cycle - 100% ownership) Smith(Combined cycle - 100% ownership) Wansley(Combustion Turbine – 30% ownership) Transmission plant Other Property under capital lease: Scherer Unit No. 2(Fossil – 60% leasehold) Total in-service Construction work in progress Vogtle Units No. 3 & No. 4(2) Environmental and other generation improvements Other Total construction work in progress 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. April 2019 aggressive strategy targets. November 2022, respectively. the current construction schedule or budget. November 1, 2023. Georgia Power, on behalf of all the co-owners has purchased a builders' risk property insurance policy from NEIL for Vogtle Units No. 3 and No. 4. This policy provides $42 million. 2018 2019 2020 Thereafter To supply a portion of the fuel requirements to our co-owned generating units, Georgia Power, on our behalf for coal and Southern Nuclear on our behalf for nuclear fuel, $80,000,000. 2018 2019 2020 2021 2022 Thereafter 12. Contingencies and Regulatory Matters: 2017 Operating revenues Operating margin Net margin 2016 Operating revenues Operating margin Net margin The negative net margins in the fourth quarter of served by the member. After the nominating committee nominates a candidate for a director position, the candidate must be elected by a majority vote of all of our member representatives, voting on an unweighted, one-member, one-vote basis. If the nominated candidate fails to receive a majority of the vote, the nominating committee must nominate another candidate and the member representatives will vote on Mr. Smith co-founded and served as the Executive Director of the Committee of Chief Risk Officers. From 1997 to 2002, Mr. Smith held multiple positions at Mirant Corporation, most recently as Vice President and Global Risk Officer. From 1994 to 1997, he was Manager of Planning and Evaluation for Vastar Resources and prior to that he worked at ARCO in various positions from 1983 to 1994. Mr. Smith has a Bachelor's degree in Business Law and a Masters of Business Administration in Finance from Louisiana State University. Mr. Smith is on the board of directors for both the SERC Reliability Corporation and Association of Edison Illuminating Companies. Mr. Smith is also on the board of directors of the Georgia Chamber of Commerce, the Georgia Energy and Industrial Construction Consortium and for ACES Power Marketing. Lori K. Holt is our Senior Vice President, Fuels & Co-owned Assets and has served in that capacity since January 2017. Ms. Holt joined us in 2009 as Vice President of Fuels and Energy. From 2002 to 2009, Ms. Holt was Managing Director of Business Development for ACES. Prior to joining ACES, she was involved with power plant development for Panda Power Funds. Ms. Holt graduated from the University of Louisville with a Bachelor of Science in Business Administration degree. Management. Association in 2017 and 2018. directors since March 2016, and his present term will expire in March Commerce. Corporation since May 2002. He is also the Secretary of Georgia Energy Cooperative. Nichols. Mr. Millwood is the chairman of the compensation committee. executive officers is consistent with the coverage we provide to our employees generally. performance objectives that are used to determine performance pay amounts. He and our vice president, human resources present these procedures and reducing workplace hazards for both our employees and contractors. oversight involvement, understanding of the project status and project issues, and timeliness and usefulness of project communications to our members and our board of directors. Our president and chief executive officer will assign a score based on his assessment of the overall effectiveness of our management of the project and submit the score to the construction committee of our board of directors for approval. Other components measure construction progress at the Vogtle project as well as construction projects that we directly oversee, and we measure success based on completion in a timely manner and within project budget. Total Michael L. Smith Michael W. Price Elizabeth B. Higgins William F. Ussery James D. Messersmith Our employment agreement with Mr. Smith extends through December 31, be payable to Mr. Smith in the circumstances described above is
Fred McWhorter
Danny Nichols during 2019. Mr. Crenshaw's and Mr. Simonton's service on this committee ended May 7, 2019. Summary Compensation Table For an explanation of the criteria and formula used to determine the awards listed above, please refer to "– Compensation Discussion and Analysis –Assessment of Performance of The following table sets forth contributions for the fiscal year ended December 31, 2019. During committee is charged with monitoring compliance with this policy and making recommendations to the board of directors regarding this policy. Certain actions or relationships that might give rise to a conflict of interest are reviewed and approved by our board of directors. Financial Statement Schedulesmanagement'smanagement’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. development and construction of Vogtle Units No. 3 and No. 4 could have a material impact on our financial condition and results of operations.Further, no nuclear plants have reached commercial operation using advanced designs, such as the Westinghouse AP1000 design, and therefore estimating the total cost of construction and the related schedule is inherently uncertain. We also 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.project budget for the additionalour 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 contingency amount, is $7.0 billion and we expectseparate Oglethorpe-level contingency. As of December 31, 2019, our total investment in the additional Vogtle Unitsunits was approximately $4.9 billion. The regulatory-approved in-service dates for Vogtle Unit No. 3 and No. 4 to be placed in service byare November 2021 and November 2022, respectively. Our $7.0 billion budget is net of payments we received from Toshiba under the Guarantee Settlement Agreement. Certain events have materially delayed the original commercial operation dates and increased the original project budget. The most significant of these relate to Westinghouse's filing for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code and its subsequent rejection of the substantially fixed price EPC Agreement. On January 11, 2018, the Georgia Public Service Commission entered an order regarding a series of actions related to Vogtle Units No. 3 and No. 4 that the Public Service Commission approved on December 21, 2017. Among other actions, the Public Service Commission (i) accepted Georgia Power's recommendation that construction of Vogtle Units No. 3 and No. 4 be completed, with Southern Nuclear serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain assumptions upon which Georgia Power's recommendations were based do not materialize, both the Public Service Commission and Georgia Power reserve the right to reconsider the decision to continue construction. Parties have filed two petitions in Fulton County Superior Court for judicial review of the Public Service Commission's January 11, 2018 order. Georgia Power has stated that it believes these appeals have no merit; however, an adverse outcome in one or both of these appeals could have a material impact on our financial condition and results of operations. As construction continues, we remain subject to construction risks and no longer have the benefit of the substantially fixed price EPC Agreement which means that we all 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:loss of access to intellectual property rights necessary to construct or operate the project;•shortages and/or inconsistent quality of equipment, materials and labor;
increases in our cost of debt financing as a result of changes in market interest rates or as a result of construction schedule delays;•unforeseen liens on the project;•permits, approvals and other regulatory matters;•unanticipated increases in the costs of materials;• On November 2, 2017,Co-owners amendedcurrent 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 Joint Ownership Agreementsrisk 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 andprovide that holdersdetermine what impact, if any, suspected or actual cases may have on the current construction schedule or budget.at least 90%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 ownership interestsproject. The project-level contingency is separate and in addition to our Oglethorpe-level contingency.voteimprove 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 continuebelieve 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.uponcosts exceed the occurrence of certain adverse events. As we are a 30% ownerEAC in the Vogtle project, we, along withnineteenth 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 Municipal Electricity Authorityevent 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 all needhave a one-time option to determinetender a portion of its ownership interest to move forwardGeorgia 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 upon the occurrence of any of those adverse events. In the event the Co-owners determine not to proceed with the project following such an event, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230 million. As of December 31, 2017, our total investment in the additional Vogtle units was approximately $2.9 billion, net of payments we received from Toshiba under the Guarantee Settlement Agreement. If the project is cancelled, we would seek regulatory accounting treatment to amortize our investment in the Vogtle project overexchange for a long-term period which would require the approvalportion of our board of directors and the Rural Utilities Service.construction-related challenges includingwith management of contractors subcontractors and vendors,vendors; subcontractor performance; supervision of craft labor and related craft labor productivity, particularly in the installation of electrical and availability,mechanical commodities, ability to attract and retain craft labor and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and installationthe initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures andor 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. Aspects of the Westinghouse AP1000 design are based on new technologies and commercial operation of this design has yet to be tested. also been technical and procedural challenges to the construction and licensing of these unitsVogtle Units No. 3 and additional challengesNo. 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 operatingresolutionsubmittal by Southern Nuclear of inspections, tests, analyses, and acceptance criteriadocumentation 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, as construction proceeds, 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.fund up to $3.1which we funded $3.0 billion of eligible project costs through 2020.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, 2017,2019, we had advanced $1.7no 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 under this loan. of additional long-term funding in the capital markets through 2023.thisthe 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. We are currently unable to make advances from the remaining $1.4 billion of committed funds under our loan guarantee agreement with the Department of Energy and will not be able to make additional advances until we enter into an amendment to the loan guarantee agreement. While not assured, we expect to satisfy these conditions in the second quarter of 2018. Prolonged inability to access funding pursuant to the Department of Energy loan guarantee agreement may constrain our liquidity and lead us to finance certain expenditures through alternative resources, likely at a higher interest rate. 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 thisthe 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 We have received a conditional commitment from the Department of Energy for approximately $1.6 billion of additional loan guarantees for eligible project costs. This conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. Final approval and issuance of the additional loan guarantee by the Department of Energy cannot be assured and is subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions. See Note 7a of Notes to Consolidated Financial Statements for additional information about the terms of the loan guarantee agreement and related conditions.couldwould 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.lenders'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:Our capital expenditures, particularly in relation to the additional units under construction at Plant Vogtle, are projected to be significant and will continue to increase our debt, which is constraining certain of our financial metrics and may also adversely affect our credit ratings which would likely increase our borrowing costs and could decrease our access to capital. In order to meet the energy needs of our members, we are in the midst of a multi-year capital spending plan to fund our participation in the construction of Vogtle Units No. 3 and No. 4. Our current project budget for the additional Vogtle units is $7.0 billion, and our investment as of December 31, 2017 was $2.9 billion, net of payments received from Toshiba under the Guarantee Settlement Agreement. As we have financed generation assets in the past, we are relying on external funding to finance this project. As of December 31, 2017, we had $8.2 billion of debt outstanding, an increase of $3.9 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 $11.5 billion. In addition to the increase in absolute dollars, our debt has been increasing as a percentage of our total capitalization, which has constrained our equity ratio. Furthermore, our debt service payment obligations have increased, which has affected certain other financial metrics. Increased debt and the related impacts on our financial metrics could negatively impact our credit ratings. Any downgrade in our credit ratings would likely increase our borrowing costs and could decrease our access to the credit and capital markets. Beginning in 2009, in order to increase financial coverage during a period of generation expansion, our board of directors approved budgets to achieve margins for interest ratios greater than the minimum 1.10 margins for interest ratio required under our first mortgage indenture. We have achieved the board-approved margins for interest ratio each year, and for 2018 our board of directors again approved a margins for interest ratio of 1.14.futurenew 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.2017,2019, we have spent approximately $1.1 billion on capital expenditures at our facilities to achieve and maintain compliance with Georgia's "multi-pollutant rule"Georgia’s “multi-pollutant rule” and EPA'sEPA’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 $80$239 million in 2017 on capital expenditures related to the$196$102 million more in the near future.including those relating to greenhouse gas emissions, including carbon dioxide,at the federal or renewable or clean energystate level may create new requirements and operational hurdles. More stringent or new standards maycould require us to modify the design or operation of existing facilities and could result in significant increases in the cost of electricity or decreases in the amount of energy (due to operational constraints) provided to our members. Two examplesExamples of current and potential regulations are discussed below. The EPA has determined that carbon dioxide and other greenhouse gases are regulated pollutants underthe Clean Air Act. As a result of this determination, in October 2015publishedissued the final rules regarding emissions of carbon dioxide from certain fossil fuel-fired electric generating units. One of the rules, referred to as the "Clean Power Plan," established guidelines for states to develop plans to limit emissions of carbon dioxide from certain existing fossil fuel-fired electric generating units. The guidelines and standards set forth in theAffordable Clean Power Plan could impose future operational restrictions and substantial costs on our coal-fired units. In February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan pending the resolution of litigation challenging the rule. In October 2017, the EPA proposed aEnergy (ACE) rule to rescind the Clean Power Plan and the related guidelines and in December 2017, EPA published an advance notice of proposed rulemaking regarding a replacement rule forreplace the Clean Power Plan. ItThe 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 likely that any actioncurrently 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.EPA to rescind all or part of the Clean Power Plan will be challenged. If the Clean Power Plan is not ultimately rescinded and survives litigation challenging the rule, we anticipate that some of the policy approaches it sets forth could have significant negative consequences for the economy and electric system in Georgia and the nation. In the event that the Clean Power Plan is rescinded,states, we expect that efforts to limit thegreenhouse gas emissions, of greenhouse gases, 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.Georgia Power has announced that ash ponds at each of its Georgia coal-fired facilities, including our co-owned facilities, will cease receiving new coal ash by early 2019 and that closure activities forTo comply with this rule, the ash ponds at Plants Wansley and Scherer are initiallyceased 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 continuehave proposed such a plan to review the ultimate costGeorgia 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 this rule onPlants Scherer and Wansley are instead required to construct lined coal ash disposal facilities, our co-owned coal facilities.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 estimate our total cost for compliance withhave 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 approximately $273$325 million to $350 million. Expenditures for the settlement of capital costs plus an additional $173 million of costs associated with related asset retirement obligation liabilities."BUSINESS –REGULATION – “BUSINESS —REGULATION—Environmental."18%17% of our total gross generating capacity and 42%43% of our energy generated during 2017.2019. Our ownership are collecting for and 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 and liabilities could exceed the amount of these funds available and we would have to collect additional revenue from our members to pay the excessunfunded costs."BUSINESS –OUR“BUSINESS—OUR POWER SUPPLY RESOURCES – RESOURCES—Future Power Resources –Resources—Plant Vogtle Units No. 3 and No. 4."organizations'organizations’ mandatory reliability and record keeping standards, including mandatory cyber security standards;influenzasthe current coronavirus (COVID-19) outbreak, or similar occurrences."BUSINESS –OGLETHORPE“BUSINESS—OGLETHORPE POWER CORPORATION – CORPORATION—Relationship with Georgia Power Company"Company” and "PROPERTIES – “Properties—Co-Owners of Plants"Plants” and "– “—Plant Agreements"Agreements” for discussions of our relationship with Georgia Power and our co-owned facilities.members'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 recent depression incontinued 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.We may not be ablewhich could limit our ability to operate our facilities.members'members’ ability to perform their contractual obligations to us.TableContentsChangesour coal-fired generation units in power generation and energy storage technologies, including the broad adoptionadvance of distributed generation technologies in our members' service territories,currently assumed retirement dates which could result in the costrate recovery challenges.electric service being less competitive. Our business model istotal summer planning reserve capacity. The percentage of gross energy generated by coal-fired resources we sell to provide our members with wholesale electric power at the lowest possible cost. A key elementhas 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 this model is that generating power at central station power plants achieves economies of scale and produces power at a competitive cost. Distributedadditional natural gas-fired resources. Additional lower cost generation could further displace existing coal-fired generation which may make continued operation uneconomical.energy storage technologies currently exist or are in development, such as fuel cells, micro turbines, windmills and solar cells, that may be capable of producing or storing electric power atoperating 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 comparable with,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.lower than,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 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 affectmembers would depend on several factors, including the proposed retirement date, our ability to recover costs after the fixed costs relatedretirement date, the price of any replacement energy and cannot be determined at this time. In order to andmitigate the valuerate impact of our generating facilities and significantly increase the cost of electric service we provide toany early retirement on our members, andwe would likely apply for regulatory accounting treatment to spread the early retirement costs over an extended period. These increased costs could affect theirour members’ ability to perform their contractual obligations to us.members'members’ ability to perform their contractual obligations to us.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, contracts related to the market price and supplymembers'members’ service territories which could affect our members'members’ financial performance. Further, our members must forecast their load growthmembers'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'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.investors'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.Facilities Type of
FuelPercentage
InterestOur Share of
Nameplate
Capacity
(megawatts)Commercial
Operation
DateLicense
Expiration
DatePlant 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 Unit No. 2 Coal 30 259.5 1978 N/A Combustion Turbine Oil 30 14.8 1980 N/A Plant Scherer (near Forsyth, Ga.) Unit No. 1 Coal 60 490.8 1982 N/A Unit No. 2 Coal 60 490.8 1984 N/A 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 Talbot (near Columbus, Ga.) Units No. 1-4 Gas 100 412.0 2002 N/A Units No. 5-6 Gas-Oil 100 206.0 2003 N/A Chattahoochee (near Carrollton, Ga.) Gas 100 468.0 2003 N/A Hawk Road (near Franklin, Ga.) Gas 100 500.0 2001 N/A Hartwell (near Hartwell, Ga.) Gas-Oil 100 300.0 1994 N/A Smith (near Dalton, Ga.) Unit No. 1 Gas 100 630.0 2002 N/A Unit No. 2 Gas 100 620.0 2002 N/A Facilities Type of
Fuel Percentage
Interest Our Share of
Nameplate
Capacity
(MW) Commercial
Operation Date License
Expiration Date Plant Hatch (near Baxley, Ga.) Nuclear 30 269.9 1975 2034 Nuclear 30 268.8 1979 2038
Plant Vogtle (near Waynesboro, Ga.)
Nuclear 30 348.0 1987 2047 Nuclear 30 348.0 1989 2049
Plant Wansley (near Carrollton, Ga.)
Coal 30 259.5 1976 N/A (1) Coal 30 259.5 1978 N/A (1) Oil 30 14.8 1980 N/A (1)
Plant Scherer (near Forsyth, Ga.)
Coal 60 490.8 1982 N/A (1) 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.)
Gas 100 412.0 2002 N/A (1) 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.)
Gas 100 630.0 2002 N/A (1) Gas 100 620.0 2002 N/A (1) 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 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 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 17 281.0 60 50 55 3 2 1 682.3 79 75 77 8 8 5 Chattahoochee 466.0 94 79 91 80 65 82 486.9 54 68 83 11 11 10 305.5 84 75 80 13 6 3 Smith Unit No. 1 658.6 75 43 86 53 29 57 Unit No. 2 658.6 81 90 86 61 67 59 TOTAL 7,124.7 Summer
Planning
Reserve
Capacity(1) Equivalent
Availability(2) Capacity Factor(3) (Megawatts) 2017 2016 2015 2017 2016 2015 262.2 95 % 90 % 98 % 95 % 91 % 99 % 264.3 92 98 89 93 98 90
344.5 92 100 90 93 102 91 344.7 95 94 99 97 95 100
261.6 95 96 81 9 11 3 261.6 95 79 97 4 5 2 0 41 39 61 0 0 0
515.0 71 99 82 23 55 55 515.0 96 85 97 52 48 60
272.3 97 25 88 18 6 18 272.3 77 97 95 16 24 18 272.3 78 99 74 17 16 10
341.0
55
69
82
1
4
1
682.3
77
77
76
5
11 ��
6
458.0
91
83
89
82
74
69
486.9
83
69
74
10
18
7
301.1
80
57
81
3
1
1
630.0 86 89 79 57 60 45 630.0 86 90 83 59 56 30 7,115.1 20182020 capacity reserve planning. For 2015 and beyond, the plants operated by us and Siemens exclude periods when units are derated due to events classified under NERC guidelines as "Outside Management Control." and market prices relative to the cost of coal purchased for Plant Wansley, it has been dispatched at lower levels in recent years.see"MANAGEMENT'Ssee "MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –Results– Results of Operations –Operating Expenses."28, 2018,29, 2020, we had a 44-day69-day coal supply at Plant Wansley based on continuous operation. Plant Wansley burns bituminous coal purchased primarily from coal mines in the Illinois Basin.28, 2018,29, 2020, our coal stockpile at Plant Scherer contained a 39-day67-day supply based on continuous operation. Plant Scherer burns sub-bituminous coal purchased from coal mines in the Powder River Basin in Wyoming.PlantPlants Wansley and Plant Scherer, but use Georgia Power as our agent for fuel procurement. We currently lease approximately 1,200 rail cars720 railcars to transport coal to these two facilities. We are assessing our future railcar needs and evaluating our leasing options. long-term firm and short-term firm and non-firm contracts. See "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK – Commodity Price Risk."the Municipal Electric Authority of Georgia,MEAG, the City of Dalton and us, and Rocky Mountain is co-owned by Georgia Power and us. Each co-owner owns or leases undivided interests in the amounts shown in the following table, which excludes the Plant Wansley combustion turbine. We are the operating agent for Rocky Mountain. Georgia Power is the operating agent for each of the other plants.Nuclear Coal-Fired Pumped
StoragePlant Hatch Plant Wansley Plant Scherer Units
No. 1 & No. 2Rocky Mountain Total % % % % % Oglethorpe 30.0 539 30.0 1,356 30.0 519 60.0 982 74.6 633 4,029 Georgia Power 50.1 900 45.7 2,066 53.5 926 8.4 137 25.4 215 4,244 MEAG 17.7 318 22.7 1,026 15.1 261 30.2 494 — — 2,099 Dalton 2.2 39 1.6 72 1.4 24 1.4 23 — — 158 Total 100.0 1,796 100.0 4,520 100.0 1,730 100.0 1,636 100.0 848 10,530 Nuclear Coal-Fired Pumped Storage
Plant Hatch
Plant Vogtle
Plant Wansley Plant Scherer Units No. 1 & No. 2
Rocky Mountain
Total % MW(1) % MW(1) % MW(1) % MW(1) % MW(1) MW(1) 30.0 539 30.0 696 30.0 519 60.0 982 74.6 633 3,369 50.1 900 45.7 1,060 53.5 926 8.4 137 25.4 215 3,238 17.7 318 22.7 527 15.1 261 30.2 494 – – 1,600 2.2 39 1.6 37 1.4 24 1.4 23 – – 123 100.0 1,796 100.0 2,320 100.0 1,730 100.0 1,636 100.0 848 8,330 the Municipal Electric Authority of GeorgiaMEAG and two municipalities. Georgia Power is the largest supplier of electric energy in the State of Georgia. See"BUSINESSSee "BUSINESS – OGLETHORPE POWER CORPORATION – Relationship with Georgia Power Company." Georgia Power is subject to the informational requirements of the Exchange Act, and, in accordance therewith, files reports and other information with the SEC. Power, is a state-chartered, municipal joint-action agency that provides capacity and energy to its membership of 49 municipal electric utilities, including 48 cities and one county in the State of Georgia. MEAG Power has wholesale take-or-pay power sales contracts with each of its 49 participants that extend to June 2054. The participants are located in 39 of Georgia's 159 counties and collectively serve approximately 311,000 electric consumers (meters). MEAG Power is Georgia's third largest power supplier behind Georgia Power and us. It presently serves more than 65,000 residential, commercial and industrial electric customers. Power and the City of Dalton. We are a party to four Purchase and Ownership Participation Agreements (Ownership Agreements) under which we acquired from Georgia Power a 30% undivided interest in each of Plants Hatch, Wansley and Vogtle, a 60% undivided interest in Scherer Units No. 1 and No. 2 and a 30% undivided interest in those facilities at Plant Scherer intended to be used in common by Scherer Units No. 1, No. 2, No. 3 and No. 4 (the Scherer Common Facilities). We have also entered into four Operating Agreements (Operating Agreements) relating to the operation and maintenance of Plants Hatch, Wansley, Vogtle and Scherer, respectively. The Ownership Agreements and Operating Agreements relating to Plants Hatch and Wansley are two-party agreements between Georgia Power and us. The Ownership Agreements and Operating Agreements relating to Plants Vogtle and Scherer are agreements Power, the City of Dalton and us. The parties to each Ownership Agreement and Operating Agreement are referred to as "participants" with respect to each such agreement.iswill remain in the process of being extendedeffect until 2041. The co-owners anticipate extending the term prior to expiration. The Operating Agreement for Scherer Units No. 1 and No. 2 will remain in effect with respect to Scherer Units No. 1 and No. 2 until 2022 and 2024, respectively. Upon termination of each Operating Agreement, following any extension agreed to by the parties, Georgia Power will retain such powers as are necessary in connection with the disposition of the property of the applicable plant, and the rights and obligations of the parties shall continue with respect to actions and expenses taken or incurred in connection with such disposition. Power and the City of Dalton entered into amendments to the Operating Agreement for Plant Vogtle and the Nuclear Managing Board Agreement, and entered into an Ownership Agreement that governs participation in Vogtle Units No. 3 and No. 4. Pursuant to this ownership agreement, Georgia Power has designated Southern Nuclear as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services. See "BUSINESS – OUR POWER SUPPLY RESOURCES –Future– Future Power Resources –Plant Vogtle Units No. 3 and No. 4" for a discussion of recent amendments to our ownership agreements related to Vogtle Units No. 3 and No. 4.Patronage Capital Litigation In 2014, two lawsuits were filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission, and certain of our member distribution cooperatives. The plaintiffs, current and former consumer-members of those member distribution cooperatives, challenged the defendants' patronage capital distribution practices, claiming, among other things, the defendants failed to retire patronage capitalon an alleged required, regular schedule and, therefore, had inappropriately retained patronage capital owed to current and former consumer-members. In May 2016, the Superior Court issued a final order dismissing all of the plaintiffs' claims against us, Georgia Transmission, and the defendant member distribution cooperatives in both cases with prejudice. The plaintiffs in both cases appealed the Superior Court's decision to the Georgia Court of Appeals. On June 9, 2017, the Georgia Court of Appeals upheld the Superior Court's decision to dismiss on all counts both of these cases. The plaintiffs did not further appeal these dismissals to the Georgia Supreme Court and the appeal period has since expired, ending this litigation.2017,2019, has been derived from our audited financial statements. This data should be read in conjunction with"MANAGEMENT'Swith "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and the"FINANCIALthe "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA."(dollars in thousands) 2019 2018 2017 2016 2015 STATEMENTS OF REVENUES AND EXPENSES DATA Operating revenues: Sales to Members $ 1,429,852 $ 1,479,379 $ 1,433,830 $ 1,506,807 $ 1,219,052 Sales to non-Members 440 734 366 424 130,773 Total operating revenues $ 1,430,292 $ 1,480,113 $ 1,434,196 $ 1,507,231 $ 1,349,825 Operating expenses: Fuel $ 440,214 $ 502,904 $ 473,184 $ 513,258 $ 441,738 Production 410,328 417,391 401,374 434,306 457,264 Depreciation and amortization 243,512 233,284 224,098 217,534 168,920 Purchased power 68,556 63,468 59,996 54,108 56,925 Accretion 50,473 38,090 36,674 32,361 26,108 Deferral of Hawk Road and Smith Energy Facilities effect on net margin — — — — (58,588) Total operating expenses $ 1,213,083 $ 1,255,137 $ 1,195,326 $ 1,251,567 $ 1,092,367 Operating margin 217,209 224,976 238,870 255,664 257,458 Other income, net 64,189 68,262 64,985 56,903 52,030 Net interest charges (226,937) (242,039) (252,578) (262,222) (261,147) Net margin $ 54,461 $ 51,199 $ 51,277 $ 50,345 $ 48,341 BALANCE SHEET DATA Electric plant, net: In service $ 4,679,690 $ 4,739,565 $ 4,584,075 $ 4,671,500 $ 4,670,310 Nuclear fuel, at amortized cost 359,270 358,358 358,562 377,653 373,145 Construction work in progress 4,816,896 3,866,042 2,935,868 3,228,214 2,868,669 Total electric plant $ 9,855,856 $ 8,963,965 $ 7,878,505 $ 8,277,367 $ 7,912,124 Total assets $ 12,990,113 $ 12,183,268 $ 10,928,139 $ 10,701,113 $ 10,059,783 Capitalization: Long-term debt $ 9,726,428 $ 9,347,307 $ 8,232,703 $ 8,304,523 $ 7,575,027 Obligations under finance leases 81,730 87,191 94,358 98,531 100,456 Obligations under Rocky Mountain transactions 25,196 21,428 20,051 18,765 17,561 Patronage capital and membership fees 1,016,747 962,286 911,087 859,810 809,465 Accumulated other comprehensive (gain) loss — — — (370) 58 Subtotal $ 10,850,101 $ 10,418,212 $ 9,258,199 $ 9,281,259 $ 8,502,567 Less: long-term debt and finance leases due within one year (217,440) (522,289) (216,694) (316,861) (189,840) Less: unamortized debt issuance costs (100,680) (92,377) (87,802) (93,133) (93,651) Less: unamortized bond discounts on long-term debt (10,542) (10,954) (7,811) (8,128) (4,337) (dollars in thousands) 2017 2016 2015 2014 2013 $ 1,433,830 $ 1,506,807 $ 1,219,052 $ 1,314,869 $ 1,166,618 366 424 130,773 93,294 78,758 1,434,196 1,507,231 1,349,825 1,408,163 1,245,376 473,184 513,258 441,738 515,729 442,425 401,374 434,306 457,264 428,801 369,730 224,098 217,534 168,920 166,247 158,375 59,996 54,108 56,925 71,799 56,084 36,674 32,361 26,108 24,616 22,900 – – (58,588 ) (58,426 ) (35,662 ) 1,195,326 1,251,567 1,092,367 1,148,766 1,013,852 238,870 255,664 257,458 259,397 231,524 64,985 56,903 52,030 46,371 43,433 (252,578 ) (262,222 ) (261,147 ) (259,133 ) (233,477 ) $ 51,277 $ 50,345 $ 48,341 $ 46,635 $ 41,480 $ 4,584,075 $ 4,671,500 $ 4,670,310 $ 4,582,551 $ 4,434,728 358,562 377,653 373,145 369,529 341,012 2,935,868 �� 3,228,214 2,868,669 2,374,392 2,212,224 $ 7,878,505 $ 8,277,367 $ 7,912,124 $ 7,326,472 $ 6,987,964 $ 10,928,139 $ 10,701,113 $ 10,059,783 $ 9,448,820 $ 9,048,453 $ 8,232,703 $ 8,304,523 $ 7,575,027 $ 7,256,995 $ 6,954,293 94,358 98,531 100,456 121,731 140,212 20,051 18,765 17,561 16,434 15,379 911,087 859,810 809,465 761,124 714,489 – (370 ) 58 468 (549 ) 9,258,199 9,281,259 8,502,567 8,156,752 7,823,824 (216,694 ) (316,861 ) (189,840 ) (160,754 ) (152,153 ) (87,802 ) (93,133 ) (93,651 ) (97,423 ) (46,759 ) (7,811 ) (8,128 ) (4,337 ) (4,516 ) (3,103 ) $ 8,945,892 $ 8,863,137 $ 8,214,739 $ 7,894,059 $ 7,621,809 $ 1,019,695 $ 613,019 $ 495,426 $ 534,171 $ 628,216 24,028,841 25,918,782 22,408,932 21,699,553 20,648,325 143,546 49,945 142,150 400,699 198,272 24,172,387 25,968,727 22,551,082 22,100,252 20,846,597 6.02¢ 5.90¢ 6.64¢ 6.52¢ 6.29¢ Total capitalization $ 10,521,439 $ 9,792,592 $ 8,945,892 $ 8,863,137 $ 8,214,739 Cash paid for property additions $ 1,255,188 $ 1,185,367 $ 1,019,695 $ 613,019 $ 495,426 OTHER DATA Energy supply (megawatt-hours): Generated 23,384,897 23,299,117 24,028,841 25,918,782 22,408,932 Purchased 85,542 129,334 143,546 49,945 142,150 Available for sale 23,470,439 23,428,451 24,172,387 25,968,727 22,551,082 Member revenues per kWh sold 6.16 ¢ 6.43 ¢ 6.02 ¢ 5.90 ¢ 6.64 ¢ primarily derived from sales to our members pursuant to take-or-pay wholesale power contracts that extend through 2050. These contracts obligate our members jointly and severally to pay all of our costs and expenses associated with owning and operating our power supply business. To that end, our rate structure provides for a pass-through of actual energy costs. Charges for fixed costs, including capacity, other non-energy charges, debt service obligations and the margin required to meet our budgeted margins for interest ratio are carefully managed throughout the year to ensure that we collect sufficient capacity-related revenues. Our rate structure provides us with the ability to manage our revenues to assure full recovery of our costs and has enabled us consistently to meet our financial obligations since our formation in 1974.2017remainhad another successful year in 2019 as we continue to be well positioned, both financially and operationally, to fulfill our obligations to our members, bondholders and creditors. Once again in 2017,As expected, our revenues were more than sufficient to recover all of our costs and to satisfy all of our debt service obligations and financial covenants. Specifically, we recorded a net margin of $51.3$54.5 million in 2017,2019, which achieved the 1.14 margins for interest ratio approved by our board of directors and exceeded the 1.10 margins for interest ratio required to meet the rate covenant under our first mortgage indenture. Since 2009, With the net margins we have targeted higher margins than necessary to meet our margins for interest ratio covenant of 1.10. We believe this is prudent due to significant capital expenditures and increased debt to fund those capital expenditures, most notably related to the construction of Vogtle Units No. 3 and No. 4. We have achieved our targeted marginscollected in each of these years and, as a result,2019, our patronage capital has increased significantly, from $535.8 million at December 31, 2008 to $911.1 million at December 31, 2017.surpassed $1.0 billion. For 2018,2020, we are again targeting a margins for interest ratio of 1.14, effectively increasing our annual margins by 40% over the minimum required level. We anticipate that we will continue to target a 1.14 margins for interest ratio through the remainder of the Vogtle Units No. 3 and No. 4 construction period.more than doubled to $10.9 billion atsignificantly increased. At December 31, 2017 from $5.02019, our total assets were $13.0 billion at December 31, 2008. Similarly, ourand total long-term debt including capital leases, has increased to $8.2 billion from $3.6 billion during the same period.was $9.7 billion. During the remainder of the Vogtle construction period, we expect that our assets and long-term debt and patronage capital will each continue to increase. We and the other Co-owners of Plant Vogtle successfully navigated a very challenging year with regards to the development and4. The year began with significant uncertainty regarding the financial viability of Westinghouse and is parent company, Toshiba. Then, in March 2017, Westinghouse filed for bankruptcy protection and this uncertainty spread to the future of Vogtle Units No. 3 and No. 4. Throughout the remainder of 2017, we actively engaged with Georgia Power, as our agent, and the other Co-owners to vigorously pursue our contractual remedies against Westinghouse and Toshiba and actively engaged with our members to evaluate our options regarding the additional Vogtle units. Following a comprehensive schedule, cost-to-complete and cancellation assessment of the Vogtle units, we, along with the other Co-owners, recommended proceeding with the project. In August 2017, Georgia Power included this recommendation in its construction monitoring report to the Georgia Public Service Commission. In a December 21, 2017 decision, the Georgia Public Service Commission approved the continuation of Vogtle Units No. 3 and No. 4. The Westinghouse bankruptcy led to significant changes in the parties managing the construction of the Vogtle units. Southern Nuclear is now construction manager, Bechtel is the primary contractor and Westinghouse is providing design services under a new Services Agreement. Over recent months, this new team has achieved increased productivity measures at the project site compared to the prior contractors, and weare optimistic that this improved performance will continue. Importantly, Toshiba honored its parent guarantee of Westinghouse's EPC Agreement and paid the Co-owners the entire $3.68 billion due under the Guarantee Settlement Agreement in late 2017. Our proportionate share of these payments was $1.1 billion which we are utilizing to cover our costs related to the Vogtle project. We expect Vogtle Units No. 3 and No. 4 continues to be placed in service by November 2021 and November 2022, respectively.a primary focus area. Our projectcurrent budget for the additional Vogtleour 30% ownership interest in these units is $7.0$7.5 billion, which includes capital costs, allowance for funds used during construction, our allocation of the project-level contingency and a contingency amount. This budget is net of the $1.1 billion of payments we received from Toshiba.separate Oglethorpe-level contingency. As of December 31, 2017,2019, our total investment in the additional Vogtle units was approximately $2.9 billion, net$4.9 billion. The Georgia Public Service Commission approved in-service dates for Vogtle Units No. 3 and No. 4 are November 2021 and November 2022, respectively.paymentsconstruction on an aggressive schedule in order to maintain margin to the regulatory-approved in-service dates. We recognize that the aggressive schedule will be difficult to achieve and that existing performance levels will need to improve in order to do so; however, our primary goal is to achieve the regulatory-approved in-service dates. In February 2020, Southern Nuclear 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 assurances that Unit No. 3 and Unit No. 4 will meet the regulatory-approved in-service dates of November 2021 and November 2022, respectively.from Toshiba. We have a $3.1 billion federal loan guarantee from the Department of Energy underpursuant to which we have advanced $1.7borrowed over $3.0 billion as ofat December 31, 2017. Our ability to request further advances under this loan is on hold pending an amendment to the loan guarantee agreement. In September 2017,2019. On March 22, 2019, we and the Department of Energy issued a conditional commitment to us for up to $1.6 billion in additional guaranteed loans under the loan guarantee agreement. Although not assured, we expect to amendexecuted an amended and restate therestated loan guarantee agreement in the second quarter of 2018 which will allow us to resume advances under the original $3.1 billion loan guarantee and serve as the primary definitive agreement for thefinance an additional $1.6 billion commitment. Weof eligible project costs. In total, we expect that these Department of Energy-guaranteed loans will provide an aggregate amount of nearly $4.7over $4.6 billion of long-term financing at lower interest rates than our alternative sources of financings. We anticipate the net present value of the savings from these loans will be over $500 million, which will reduce the long-term costs of these units. Separately, as a resultunits for our consumers. When combined, the $4.6 billion of funding guaranteed by the Bipartisan Budget ActDepartment of 2018,Energy and the $1.9 billion of debt we qualifyhave raised in the capital markets represent long-term financing for nuclear production tax credits related tomore than 85% of our $7.5 billion project budget.4. We are reviewing various options to monetize these tax credits. We estimate that the nominal value of these tax credits will be approximately $660 million which we will receive over time after the units begin operating. We are grateful to the supporters of these tax credits, as the credits will reduce our members' costs related to the operation of the new Vogtle units and benefit the electric consumers they serve. Upon completion, these units4 will have an aggregate generating capacity of approximately 2,200 megawatts and our 30% undivided interest will entitle us to approximately 660 megawatts of carbon-free, baseload generating capacity. Once complete, weWe expect Vogtle Units No. 3 and No. 4these units to be valuable assets for us and our members over the next 60 to 80 years and to contribute to our diverse pool of generation resources. For additional information regarding Vogtle Units No. 3 and No. 4 and related financing activities, see "BUSINESS“BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources – " "MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION –” “– Financial Condition – Financing Activities – Department of Energy-Guaranteed Loan"Loans” and "– “– Capital Requirements – Capital Expenditures"” and Note 7a of Notes to Consolidated Financial Statements. Onestanding is our strong liquidity position.standing. This liquidity is comprised of a diversified, cost-effective mix of cash (including short-term investments), committed lines of credit and commercial paper. Our primary sourceIn December 2019, we extended the term of liquidity is aour $1.2 billion unsecured credit facility that extends through March 2020December 2024. This credit facility is our primary source of liquidity and which supports our $1.0 billion commercial paper program. We have another $400 million available through additional secured and unsecured credit facilities. Onepossible.possible and, in 2020, we will continue to seek ways to improve the reliability of our generating facilities. Our Operational Excellence program strives to achieve safety, reliability and compliance in a cost effective manner. Many of the generation facilities we operate rank in the top quartile of similar plants in one or more key performance indicators, including start reliability, peak season availability and forced outages. Achieving operational excellence results in the most reliable, efficient and lowest cost power supply for our members; therefore, effective asset management will always be one of our top priorities.Environmental Regulations A key componenteffective asset managementthe dispatch of our generation assets is maintaining compliance with all applicable environmental regulatory standards. Although the short-term pressuresthat there has been a significant decrease in coal-fired generation. The percentage of energy from coal generation that we facesupply to our members has decreased from environmental legislation45% in 2008 to 10% in 2019. The two primary drivers of this shift in generation were our acquisition of additional natural gas-fired resources and regulations have decreased since the beginning of 2017, environmental regulationsa significant fall in natural gas prices. As we look ahead, we continue to present challengesconsider the role that coal-fired generation resources play in our overall portfolio and the ability to usprovide reliable and cost-effective generation for our members. As an electric cooperative that operates on a not-for-profit basis, our compliance costs are ultimately borne by our members' electricity consumers. Greenhouse gas and carbon dioxide emissions have been onemost prominent areas for environmental regulations overVogtle project, we and some of our members have voluntarily implemented various rate management programs to smooth out the past several years. Since the beginning of 2017, the Trump administration has taken a number of actions to reduce or rescind a number of federal environmental regulations, including those related to greenhouse gas emissions. Most notably, in October 2017, the EPA proposed a rule to rescind the Clean Power Plan. We are encouraged by this action and have previously stated our belief that the Clean Power Plan is significantly flawed and could have significant negative consequences for the economy and electric systems of Georgia and nationwide. Even if the Clean Power Plan is ultimately rescinded, we anticipate that efforts to reduce greenhouse gas emissions, in particular carbon dioxide, will continue. Although we cannot predict the form or timing of any such laws or regulations, we believe that we are well-situated to effectively manage such challenges and that our diverse asset base, along with our investment in additional carbon-free generation atimpact on rates when Vogtle Units No. 3 and No. 4 positions us wellreach commercial operation. Over the last five years, our average wholesale power rate to continue to meet our members' needs. Further, our members continuehas been at or below the mid-six cents per kilowatt-hour range. Based on current assumptions, we anticipate our average wholesale power rate to pursue potential renewable generation opportunities and invest where they deem appropriateincrease to the mid-to-high seven cents per kilowatt-hour range in 2023, the first full year we expect both new Vogtle units to be operational.meetsoften the demandsimpact of full integration of the new Vogtle units’ costs into rates. In 2023 to 2025, the first few full years after expected commercial operation of the Vogtle units, we will apply a portion of the additional amounts collected to participating members’ bills, which we expect to reduce the rate impact to those members by approximately one-third of a cent each year, from the mid-to-high seven cents per kilowatt-hour range to the low-to-mid seven cents per kilowatt-hour range. The impact of the program will gradually decrease through 2027, its final year. Further, because we only supply around 60% of our members’ wholesale power requirements, the ultimate rate impact on the retail consumers may be further mitigated as our members’ rates are blended with their member consumerssupplemental power supply sources, transmission and prepare for potential future limitations on greenhouse gas emissions.2018 We20204.14.2 million people they serve and believe we are well positioned to do so. As discussed above, there are certain risks and challenges that we must continue to address, most notably related to Vogtle Units No. 3 and No. 4. However, as we manage our risks, we intend to keep doing what we have done so successfully for the last 4446 years, including, among other things:diversityand diverse portfolio of generating resources, including nuclear, natural gas, coal and hydro and continuing the efficient and cost-effective operation of these resources;2017,2019, our regulatory assets and regulatory liabilities totaled $585.1$763.5 million and $251.6$364.2 million, respectively. While we do not currently foresee any events such as competition or other factors that would make it not probable that we will recover these costs from our members as future revenues through rates under our wholesale power contracts, if such an event were to occur, we could no longer apply the provisions of accounting for regulated operations, which would require us to eliminate all regulatory assets and regulatory liabilities that had been recognized as a charge or credit to our statement of revenues and expenses and begin recognizing assets and liabilities in a manner similar to other businesses in general. In addition, we would be required to determine any impairment to other assets, including plants, and write-down those assets, if impaired, to their fair values.2017,2019, our nuclear decommissioning and coal ash related asset retirement obligation totaled $548.6obligations were $697.4 million whichand $329.3 million, respectively. Our asset retirement obligations represent an estimate of the present value of anticipated retirement costs. For additional detail regarding our asset retirement obligations, see Note 1h of Notes to Consolidated Financial Statements. These obligations represented approximately 75%96% of our total asset retirement obligations. Our remaining asset retirement obligations relate to non-nuclear retirement obligations such as those related to our share of coal facilities.results.costs. In addition, these estimates are dependent on subjective factors, including the selection of cost escalation and discount rates, which we consider to be a critical assumption.assumptions. Our current estimates are based upon studies that were performed in 2015.2018. For ratemaking purposes, we record decommissioning costs over the expected service life of each unit. The impact on measurements of asset retirement obligations using different assumptions in the future may be significant.New Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expectsentitledcritical estimates, in exchange forparticular those goods and services. The standard is effective for us for the annual reporting period beginning after December 15, 2017 using eithercoal ash ponds. Cost studies are periodically performed to provide site-specific "base year" estimates that determine the nature and timing of planned decommissioning costs. These cost studies are based on relevant information available at the time they are performed; however, estimates of the following transition methods: (i) a full retrospective approach reflectingamount and timing of future cash flows for extended periods are by nature highly uncertain and may vary significantly from actual costs. Critical assumptions include coal ash pond closure strategy, including water treatment requirements, and the applicationvolume of coal ash in the standardponds. In addition, these estimates are dependent on other subjective factors, such as estimates of costs to perform the decommissioning and post-closure activities, timing of expenditures, and the selection of cost escalation and discount rates. Our current estimates are based upon studies that were performed in each prior reporting period with2019. For ratemaking purposes, we are applying regulated operations accounting to the optiondecommissioning costs and currently expect to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). We have completed our evaluation of the new revenue standard and adopted the amendments within the new standard effective January 1, 2018. There was no cumulative impact upon adoption.recover ash pond closure costs over approximately 12 years. The adoption of this standard is not expected to have a material impact on an annual basis, to our revenue recognition based on our existing contracts with customers. Our evaluation process included, but was not limited to, identifyingcontracts within the scope of Topic 606, reviewing and documenting ourfor these contracts and assessing the applicability of the variable consideration guidance. The vast majority of our revenue is derived from substantially identical wholesale power contracts that we have with each of our 38 members. We expect the pattern of revenue recognition pursuant to our wholesale power contracts will remain unchanged on an annual basis under the new revenue standard. Historically, our Board has approved budget adjustments, typically at year end but may be made throughout the year, that affect our annual revenue requirement. As a result, at the end of each reporting period we will determine whether the variable consideration cumulatively received from our Members exceeds the consideration to which we expect to be entitled on an annual basis. We will recognize a refund liability for the consideration which we expect to refund to our Members, if such excess consideration received would result in a significant reversal in the cumulative revenues recognized. In January 2016, the FASB issued "Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities." The amendments in this update address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Certain provisions within this update can be adopted early. Certain provisions within this update should be applied by means of a cumulative effect adjustment to the balance sheet of the fiscal year of adoption and certain provisions should be applied prospectively. One of the provisions in this standard requires our equity investments, except those accounted for under the equity method of accounting or those that result in consolidation of our subsidiary, to be measured at fair value with changes in fair value recognized in net income. None of the other provisions in this standard will have any impact to our consolidated financial statements. Effective December 31, 2017, we adopted regulatory accounting treatment with respect to unrealized gains and/or losses on our equity investments. Upon applying regulatory accounting treatment, unrealized gains on our equity investments will be recorded as a regulatory liability and, conversely, unrealized losses on our equity investments will be recorded as a regulatory asset, at the end of each reporting period. As of December 31, 2017, we recorded $0.6 million of unrealized losses on our equity investments as a regulatory asset. Effective January 1, 2018, we adopted the amendments within this standard. The adoption of this standard will have no impact to our consolidated financial statements due to our regulatory accounting treatment for unrealized gains and/or losses on our equity investments."Leases“Leases (Topic 842)."” The new leases standard requires a dual approach for lessee accounting under which a lessee would accountaccounts for leases as finance leases or operating leases. BothAccounting for both finance leases and operating leases will resultresults in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognizerecognizes interest expense and amortization of the ROU asset and for operating leases the lessee would recognizerecognizes a straight-line total lease expense. Quantitative and qualitative disclosures are required for significant judgments made by management. The new lease standard does not substantially change lessor accounting. TheWe adopted the new leases standard is effective for us on a modified retrospective approach for annual reporting periods beginning after December 15, 2018, and interim periods therein. Early adoption is permitted. We are currently evaluating the future impactJanuary 1, 2019. For additional information, see Note 6 of this standard on our consolidated financial statements."Financial Instruments – ‘‘Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments."’’ The amendments in this update replace the current incurred loss impairment methodology with a methodology that reflects expected credit losses. The new credit losses standard is effective for us prospectively for annual reporting periods beginning after December 15, 2019, and interim periods therein. The amendments in this update can be adopted earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted.statements. In August 2016,statements, however, we do not anticipate the FASB issued "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments." The amendments in this standard provide specific guidance on eight cash flow classification issues relating to how certain cash receipts and cash payments are presented and classified in the statement of cash flows, thereby reducing the current and potential future diversity in practice. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periodstherein. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments shouldimpact will be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. The amendments should be applied using a retrospective transition method to each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. As permitted, on October 1, 2017, we early adopted these amendments and applied their provisions retrospectively. The adoption of this standard had no impact on our consolidated financial statements as the amendments did not change how we present and classify the eight identified cash flow classification issues within our consolidated statement of cash flows. In November 2016, the FASB issued "Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)." The amendments in this standard require the statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows. The new standard is effective for us on a retrospective basis for annual reporting periods beginning after December 15, 2017, and interim periods therein. Early adoption is permitted, including adoption in an interim period. As permitted, on October 1, 2017, we early adopted these amendments and applied their provisions retrospectively. The adoption of this standard had no impact on our consolidated financial statements as we did not have any restricted cash balances in 2017 and 2016.We supplyOur primary source of revenue is the sale of capacity and energy to our members for a portion of their energy requirements which is our primary source of revenues.requirements. We may also sell capacity and energy to non-members. Capacity revenues are the revenues we receive for providing electric service whether or not our generation and purchased power resources are dispatched to produce electricity. Energy revenues are the revenues we receive by selling electricity whichthat we generate or purchase.We do not provide our members with all of their energy requirements; however, our energyEnergy sales to our members fluctuate from period to period based on several factors, including fuel costs, weather and otherrights and byrights. In addition, as we do not provide our members with all of their energy requirements, energy sales may also fluctuate based on our members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.participate, and variable as energy charges based on the amount of energy supplied to each member.2018.2020. As our capital requirements continue to evolve, our board will continue to evaluate the level of margin coverage and may choose to change the targeted margins for interest ratio in the future, although not below 1.10.2017,2019, we had $911.1 million$1.0 billion in patronage capital and membership fees. Our equity ratio, calculated pursuant to our first mortgage indenture as patronage capital and membership fees divided by total9.8%9.4% and 9.3%9.2% at December 31, 20172019 and December 31, 2016,2018, respectively.Lenders – Rural Utilities Service.Lenders." Currently, our rates are not subject to the approval of any other federal orturbines,turbine plants, two combined cycle natural gas-fired plants, a plant that burns bituminous coal, a plant that burns sub-bituminous coal, two nuclear plants and a pumped storage hydroelectric plant. Until the beginning of 2016, two of our facilities were not generally used to serve member load. Smith, a 1,250-megawatt combined cycle natural gas-fired plant we acquired in 2011, was used prior to 2016 extensively for off-system sales. Additionally, one of our simple cycle natural gas-fired plants, Hawk Road, was utilized solely to serve seven of our members or for off-system sales until the beginning of 2016. These two facilities were acquired on favorable terms with the knowledge that our members generally would not require the energy generation until 2016. During this time, the effect on net margin of the revenues and expenses at Smith and Hawk Road were deferred, and when we began dispatching these units to serve member load in 2016, we began recovering the net effect of these deferrals from our members. Starting in 2016, we began dispatching Smith exclusively to serve member load, and therefore member kilowatt-hour sales increased significantly, non-member sales substantially ended, and the average cost of energy sold to members decreased significantly. When we began dispatching Smith to serve member load, we experienced an increase in overall generation from Smith since member energy requirements have been a more consistent source of demand than general market demand. Additionally, in 2016, we began charging members to recover both the current fixed costs and the previously deferred net costs of Smith which, along with the increased generation from Smith, resulted in significantly increased sales revenues from members. This included higher energy charges due to a greater number of kilowatt-hours of energy that we generated and sold to members from Smith as well as increased member capacity revenues from Smith to recover fixed operating costs, depreciation and interest on the initial acquisition costs, as well as the amortization of previously deferred fixed costs of Smith. Although these capacity revenues increased, the increase in kilowatt-hours of energy sold to members was greater than the increase in total cost of the additional member sales from Smith, so the average cost of energy we sold to our members was significantly lower in 2017 and 2016 compared with 2015.Our members' energy demandThis is a function of weather, economic activity, residential use patterns and the relative cost and availability of our members' third party supplyresources. Since naturalresources. Natural gas prices have remainedwere relatively low in the last three years, the amount of coal-fired generation we sold2017 and 2018, and continued to members has decreased each year from 2015 through 2017.additionadditioturbinesturbine units are less efficient and thus burn more gas perturbines are dispatched less frequentlyturbine units have a higher dispatch cost than our combined cycle units and are typically used to generate energy only during periods of higher electricity demand, such as on hot summer days.days. In 2016, we dispatched our combustion turbines more frequently due to higher and more frequent incidences of peak demand driven by a relatively hot summer. Therefore, the2019, generation from our combustion turbinesturbine units was the second highest on record primarily due to a hot summer with more frequent instances of peak demand as well an extended outage at one of our combined cycle units.2016 was significantly higher than2018 and 14% in both 2017 and 2015. In 2017, because we dispatched these higher-heat-rate peaking units less frequently, our average fuel cost per kilowatt hour generated was lower in 2017 than in 2016.Summer in 2016The summer of 2019 was relatively hotwarm and as a result, memberin August our members experienced their peak demand for the year. Although the winter of 2019 was relatively mild, warm summer weather extended into late September and energy requirements, and therefore,October, which contributed to the increase in energy sales in 2019 compared to our members were higher in 2016 compared with 2017 and 2015. The higher 2016 energy sales also contributed to higher fuel costs and, consequently, higher operating expenses in 2016 than in 2017 or 2015.alsogenerally increased. As discussed under "– Financial Condition – Capital Resources – Capital Expenditures," we expect significant capital expenditures to continue through the completion of the additional units at Plant Vogtle.2016 and 2015 was $51.3$54.5 million, $50.3$51.2 million and $48.3$51.3 million, respectively. These amounts produced a margins for interest ratio of 1.14 in each of 2017, 20162019, 2018 and 2015.2017. For additional information on our margin requirement, see "– Summary of Cooperative Operations – Rate Regulation."electricity, andelectricity. These revenues are designed to recover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Energy revenues are earned by sellingthe sales of electricity to our members, which involves generatinggenerated or purchasing electricitypurchased for our members. Energy revenues recover the variable costs of our business, including fuel, purchased energy and variable operation and maintenance expense.(in thousands) 2019 vs. 2018 2018 vs. 2017 2019 2018 2017 % Change % Change Capacity revenues $ 942,057 $ 927,419 $ 912,421 1.6 % 1.6 % Energy revenues 487,795 551,960 521,409 (11.6) % 5.9 % Total $ 1,429,852 $ 1,479,379 $ 1,433,830 (3.3) % 3.2 % kWh Sales 23,225,861 23,011,079 23,813,679 0.9 % (3.4) % Cents/kWh 6.16 6.43 6.02 (4.2) % 6.8 % Member energy requirements supplied 58 % 57 % 63 % 1.8 % (9.5) % (in thousands) 2017 vs. 2016 2016 vs. 2015 2017 2016 2015 % Change % Change $ 862,511 $ 896,412 $ 772,069 (3.8 )% 16.1 % 571,319 610,395 446,983 (6.4 )% 36.6 % $ 1,433,830 $ 1,506,807 $ 1,219,052 (4.8 )% 23.6 % 23,813,679 25,522,852 18,371,558 (6.7 )% 38.9 % 6.02 5.90 6.64 2.0 % (11.1 )% 63 % 64 % 48 % (1.6 )% 33.3 % declined 3.8%increased slightly in 2017 as2019 compared to 20162018 due primarily as a result of a decrease in fixed production costs andto the recovery of suchdepreciation and accretion expenses. The increase in capacity revenues in 2018 compared to 2017 was primarily due to the recovery of fixed production costs. For a discussion of depreciation and accretion expense and production costs, see "– Operating Expenses.Expenses." Beginning in 2016, we began dispatching Smith and Hawk Road to serve member load. Consequently, capacity revenues increased 16.1% in 2016 compared to 2015 as a result of the recovery of fixed costs at these plants. Prior to 2016, our members did not require the energy generation from Smith and Hawk Road and the effects of the revenues and expenses from these resources on net margin were deferred.6.4%11.6% decrease in energy revenues from members in 20172019 compared to 20162018 was primarily due to a decrease in generation for member sales andresult of a decrease in total fuel costs. Slightly offsettingexpense. Offsetting the decrease was an increase in revenues related to purchased power energy. Energy revenues increased in 2016 compared to 2015 primarily due to ana slight increase in generation for member sales assales. The 5.9% increase in energy revenues from members in 2018 compared to 2017 was primarily a result of Smith and Hawk Road being utilizedan increase in total fuel expense, offset by our members. The average energy revenue per kilowatt-hour from sales to members decreased 11.1%a decline in 2016 compared to 2015. Our members' ability to schedule these additional natural gas-fired facilities, which provided an economical source of energy due to low natural gas prices, significantly increased our kilowatt-hour sales to our members and allowed us to provide a larger percentage of our member's load requirements in 2016. Slightly offsetting the increase was a decrease in revenues related to purchased power energy.generation for member sales. For a discussion of fuel costs and purchased power costs,expense, see "– Sales to Non-members. Prior to 2016, sales to non-members consisted primarily of energy sales at Smith. Non-member sales were insignificant in 2016 and 2017 as we began scheduling Smith for our members and opportunities for sales to non-members were greatly reduced.4.5%3.4% in 20172019 compared to 20162018 primarily due to a decline in fuel costs, offset by an increase in depreciation and increased 14.6%accretion. The increase in 20162018 compared to 2015. The decrease in 2017 compared to 2016 was primarily due to lowerincreased fuel and production costs. The increase in 2016 compared to 2015 was primarily due to an increase in fuel costs, depreciation, and the end of deferral of the effect of Smith and Hawk Road on net margins in 2015.Cost Generation Cents per kWh (dollars in thousands) (kWh in thousands) Fuel Source 2019 2018 2017 2019 vs.
2018
%
Change2018 vs.
2017
%
Change2019 2018 2017 2019 vs.
2018
%
Change2018 vs.
2017
%
Change2019 2018 2017 2019 vs.
2018
%
Change2018 vs.
2017
%
ChangeCoal $ 80,706 $ 119,459 $ 103,007 (32.4) % 16.0 % 2,592,023 4,062,982 3,605,093 (36.2) % 12.7 % 3.11 2.94 2.86 5.9 % 2.8 % Nuclear 79,893 85,949 90,520 (7.0) % (5.0) % 10,061,609 10,314,928 10,110,190 (2.5) % 2.0 % 0.79 0.83 0.90 (4.8) % (7.8) % Natural Gas: Combined Cycle 225,816 240,122 239,472 (6.0) % 0.3 % 9,649,561 8,047,494 9,823,035 19.9 % (18.1) % 2.34 2.98 2.44 (21.5) % 22.1 % Combustion Turbine 53,799 57,374 40,185 (6.2) % 42.8 % 1,562,895 1,271,542 966,548 22.9 % 31.6 % 3.44 4.51 4.16 (23.7) % 8.4 % $ 440,214 $ 502,904 $ 473,184 (12.5) % 6.3 % 23,866,088 23,696,946 24,504,866 0.7 % (3.3) % 1.84 2.12 1.93 (13.2) % 9.8 % Cost Generation Cents per kWh (dollars in thousands) (kWh in thousands) 2017 2016 2015 2017 vs.
2016
%
Change 2016 vs.
2015
%
Change 2017 2016 2015 2017 vs.
2016
%
Change 2016 vs.
2015
%
Change 2017 2016 2015 2017 vs.
2016
%
Change 2016 vs.
2015
%
Change $ 103,007 $ 141,773 $ 142,113 (27.3% ) (0.2% ) 3,605,093 4,800,836 5,013,312 (24.9% ) (4.2% ) 2.86 2.95 2.83 (3.1% ) 4.2% 90,520 83,751 78,762 8.1% 6.3% 10,110,190 10,344,201 10,151,539 (2.3% ) 1.9% 0.90 0.81 0.78 11.1% 3.8% 239,472 221,851 182,818 7.9% 21.4% 9,823,035 8,916,272 6,890,245 10.2% 29.4% 2.44 2.49 2.65 (2.0% ) (6.0% ) 40,185 65,883 38,045 (39.0% ) 73.2% 966,548 1,743,795 789,041 (44.6% ) 121.0% 4.16 3.78 4.82 10.1% (21.6% ) $ 473,184 $ 513,258 $ 441,738 (7.8% ) 16.2% 24,504,866 25,805,104 22,844,137 (5.0% ) 13.0% 1.93 1.99 1.93 (3.0% ) 3.1% costsexpense decreased in 20172019 compared to 2016 as a result of a 7.8% decrease in generation and a shift in generation to the relatively more economical natural gas-fired combined cycle units. The decrease and shift in generation were due in part to more moderate weather in 2017, in particular the summer months, and an extended major maintenance outage at Scherer Unit 1. As a result of these factors, generation at our relatively more expensive combustion turbine and coal-fired plants decreased by 44.6% and 24.9%, respectfully. Partially offsetting the decrease was an 8.1% increase in nuclear fuel costs largely due to spent fuel storage costs incurred during 2017. Total fuel costs increased in 2016 compared to 20152018 primarily as a result of a 39% increase in generation at our natural gas-fired plants. The effect of increased generation on fuel cost was partially moderated by lower average natural gas prices during the first half of 2016. A combination of the lower natural gas prices and the ability of our membersmilder winter weather. These factors also contributed to schedule Smith and Hawk Roada shift in 2016 were the primary contributorsgeneration from coal-fired plants to the increase in total generation. Also contributing to increased fuel costs in 2016 was a $7.1 million reduction in fuel expense in 2015 associated with the recovery of spent nuclear fuel storage costs from the U.S. Department of Energy. The exclusion of the credit would have resulted in (i) 2015 nuclear fuel costs of $85.8 million, a 2.4% decrease in 2016 compared to 2015 and (ii) a 4.2% decrease in the average cost per kilowatt-hour generation in 2016 compared to 2015. Changesmore economical natural gas-fired plants. Included in total fuel costs are also impacted byexpense were $9.1 million of losses in 2019 and $5.1 million of gains in 2018 incurred for the amountsettlement of realized gains and losses incurred for natural gas financial hedging contracts utilized for managingwe utilize to manage our exposure to fluctuations in market prices. Total generation increased slightly in 2019.During 2017, we realizedIn addition to the natural gas consumed being more expensive, the higher cost contributed to a net gainshift in generation to oil and coal-fired units.$2.1 million. In 2016 and 2015, we realized net losses of $17.3 million and $19.9 million, respectively.7.6%1.7% in 20172019 compared to 20162018 and 5.0%increased 4.0% in 20162018 compared to 2015.2017. The decrease in 20172019 was primarily due to a declinereduction in planned majorfixed and variable maintenance costs at Hartwell and lowerdriven by outages during the prior year. The increase in 2018 was primarily a result of fixed maintenance costs associated with planned and unplanned maintenance outages at Smith. The decrease in 2016 was primarily due to higher planned major maintenance costs at Smithcertain natural gas-fired plants.Hawk Road in 2015 than 2016. Depreciationamortization expense increased slightly$10.2 million or 4.4% in 2017 and 28.8% in 20162019 compared to 2015. The increase in depreciation expense in 2016 compared to 2015 was2018 primarily due to the adoptionimpact of new depreciation rates for our co-owned nuclear and decommissioning cost studies performed at the end of the 2018 and coal ash related additions placed in service at our coal-fired plants. The new depreciation rates were higher thanprevious rates largelyimpact of nuclear and coal ash pond decommissioning cost studies performed at the end of 2018. For 2018 compared 2017, there was a slight increase in accretion expense.capital additions for environmental controls and costs associated with interim retirements. Also contributing tolosses realized on the 2016 increase was the completion in 2015retirement of the amortization of a deferred liability related to the Hawk Road acquisition, the start of the amortization of the deferred asset related to the effect of Smith on net margins, and ancertain leasehold improvements. The 5.0% increase in depreciation associated with certain asset retirement obligations. The deferral of the Hawk Road and Smith effect on net margin ceased as of December 31, 2015. The deferred amounts are being amortized, which began in 2016, over the remaining lives of the plants. The amortization is recorded as a component of depreciation and amortization expense.Other Income Investment income increased 8.6% in 20172018 compared to 2016 and 27.8% in 2016 compared to 2015. The increase in 2017 was due to higher investment balances and an increase in the investment income associated with nuclear decommissioning. The increase2016 was primarily related to an increase in investment income associated with nuclear decommissioning. We use the accounting provision for regulated operations for our nuclear decommissioning transactions,2019 and record a regulatory asset or liability to reflect the difference in the timing of recognition of decommissioning expenses for financial statement purposes compared to the expense recovered for ratemaking purposes. As a result of this treatment, nuclear decommissioning related investment income increased $1.9 million in 2017 and $9.1 million in 2016, which equaled the increase in nuclear decommissioning expense for the periods. The increase in nuclear decommissioning expense was driven by an increase in cash flow estimates made pursuant to nuclear decommissioning studies completed in late 2015.Interest Charges The increases in interest expense in 2017 and 2016 as compared to the respective prior years were2018 primarily due to increased debt issued to finance the construction of Vogtle Units No. 3 and No. 4. We expect4 project, offset by lower fixed interest rates on long-termcertain refinanced debt.continue to increase in future years as we issue additional debt to finance the construction ofincreased borrowings for Vogtle Units No. 3 and No. 4.4 construction expenditures.2017,2019, we achieved a 1.14 margins for interest ratio which produced a net margin of $51.3$54.5 million. This net margin increased our total patronage capital (our equity) and membership fees to $911.1 million$1.0 billion at December 31, 2017.2019. Our 20182020 budget again targets a 1.14 margins for interest ratio.increased from 9.3%was 9.4% at December 31, 2016 to 9.8%2019 and 9.2% at December 31, 2017.2018. We anticipate that our equity ratio will remain around its current level during the remainder of the Vogtle construction period; however, the absolute level of patronage capital will continue to increase.2017,2019, with $1.6$1.5 billion of unrestricted available liquidity, including $397.7$448.6 million of cash and cash equivalents. We issued commercial paper throughout the year to provide interim financing for the Plant Vogtle construction and for other purposes at a very low cost. The average cost of funds on the $190.6$282.4 million of commercial paper outstanding at December 31, 20172019 was 1.58%2.1%.slightly to $10.9$13.0 billion at December 31, 20172019 from $10.7$12.2 billion at December 31, 2016.2018. For the past several years, our total assets have shown significant increases due to increases in construction work in progress in connection with the additional nuclear units under construction at Plant Vogtle. However, total assets increased only slightly in 2017 due to a decrease in construction work in progress following our receipt of guaranty settlement payments from Toshiba, totaling approximately $1.1 billion, during the fourth quarter of 2017. The receipt of the guaranty settlement payments also reduced our investment to-date on the project, from $3.9 billion at September 30, 2017 to $2.9 billion at December 31, 2017.20172019 totaled $1.0$1.3 billion. These additions include costs related to the construction of the new Vogtle units, environmental control facilities being installed at coal-fired Plants Scherer and Wansley, normal additions and replacements to existing generation facilities and purchases of nuclear fuel.decreaseincrease in long-term debt and capitalfinance leases of $76$373.7 million at December 31, 20172019 compared to December 31, 2016.2018. The weighted average interest rate on the $8.2$9.7 billion of long-term debt outstanding at December 31, 20172019 was 4.17%3.96%.providesprovided funding for $3.1over $3.0 billion of the cost to construct our 30% undivided interest in the two new nuclear units at Plant Vogtle. We are currently restricted from receiving further advances under this loan pending the completion of certain conditions whichexpect to occur in the second quarter of 2018. In September 2017,and the Department of Energy issued a conditional commitment to us forexecuted an amended and restated loan guarantee agreement that increased the guarantee amount by $1.6 billion. We may draw the additional $1.6 billion of additional guaranteed funding under the loan guarantee agreement. This additional funding is subject to an amendment and restatement of the Loan Guaranty Agreement and satisfaction of certain other conditions. The conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. While not assured, we expect to close on this loan in the second quarter of 2018. See "–Financing Activities" and Note 7 in Notes to Consolidated Financial Statements for additional information regarding the status of this loan.markets, and ifmarkets. If the Rural Utilities Service loan program were to be curtailed or eliminated inor if we are unable to draw the future,full amount of the Department of Energy-guaranteed loan, we believe we are well positioned to continue to access capital market financings.Lenders."TableLenders" for further discussion of Contents See"– Capital Requirements – Capital Expenditures" for more detailed information regarding our estimated capital expenditures. See "–Financing Activities" for more detailed information regarding our financing plans.2017,2019, we had $1.6$1.5 billion of unrestricted available liquidity to meet short-term cash needs and liquidity requirements, consisting of $397.7$448.6 million of cash and cash equivalents and $1.2$1.1 billion of unused and available committed credit arrangements.$471.3$351.4 million in 2017,2019, and averaged $339.6$437.5 million per year for the three-year period 20152017 through 2017.anticipate renewingare currently in discussions with our banks to increase the threeamount of bank credit facilities we have available in order to fund the re-purchase of $212.8 million of pollution control bonds that are setsubject to expire in 2018 asmandatory tender on April 1, 2020. See "– Financing Activities – Bond Financings" for more detailed in the table below.2017,2019, we had $1.6 billion of committed credit arrangements in place and $1.2$1.1 billion available under these facilities. The four separate facilitiescredit facilities. These are reflected in the table below:Committed Credit Facilities (dollars in millions) Authorize
AmountAvailable
12/31/2019Expiration
DateUnsecured Facilities: Syndicated Line among 12 banks led by CFC $ 1,210 $ 792 December 2024 110 110 December 2023 JPMorgan Chase Line of Credit 150 34 October 2021 Secured Facilities: 250 140 December 2023 Committed Credit Facilities (dollars in millions) Authorize
Amount Available
12/31/2017 Expiration
Date $ 1,210 $ 884 (1) March 2020
110
110
150
34
(3)
250 140 December 2018 12/31/17, $190.6December 31, 2019, $282.4 million was dedicated to support outstanding commercial paper and $135.5$136 million related to letters of credit issued to support variable rate demand bonds.12/31/17,December 31, 2019, $113.7 million related to letters of credit issued to support variable rate demand bonds and $2.2 million related to letters of credit issued to post collateral to third parties.to support up to $1.0 billion of commercial paper and to issueissuing letters of credit to third parties.2017.2019. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw for working capital needs. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under our committed credit facilities for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue. The majority of our outstanding letters of credit are for the purpose of providing credit enhancement on variable rate demand bonds.our expensescosts related to the construction of Vogtle Units No. 3 and No. 4 which we repay with the proceeds from long-term funding sources. Due to issues stemming fromOur loan guaranteed by the bankruptcy of Westinghouse, we were restricted from borrowing under our Department of Energy-guaranteed loanEnergy is our preferred source of long-term financing for most of 2017. Instead, we used a portion of the payments we received in late 2017 from Toshiba to pay down commercial paper issuedeligible costs for the Vogtle construction,Units No. 3 and a majority of the paper issued for that purpose was retired by January 2018.No. 4. See "–Financing Activities" and Note 7a in Notes to Consolidated Financial Statements for additional information regarding the status of the Department of Energy-guaranteed loan.2017,2019, we borrowed $22.1$115.4 million under various Rural Utilities Service-guaranteed loans for general and environmental improvements. TwoThree of our line of credit facilities contain similar financial covenants that require us to maintain minimum patronage capital levels. Currently, we are required to maintain minimum patronage capital of $675$750 million. As of December 31, 2017,2019, our patronage capital balance was $911.1 million.$1.0 billion. These agreements contain an additional covenant that limits our secured indebtedness and our unsecured indebtedness, both as defined in the credit agreements, to $12$14 billion and $4 billion, respectively. At December 31, 2017,2019, we had $8.2$9.7 billion of secured indebtedness outstanding and $190.6$282.4 million of unsecured indebtedness outstanding.2017,2019, we had 159 members participating in the program and a balance of $209.5$211.5 million remaining to be applied against future power bills.20172019 we had $883.0$533.6 million of restricted liquidity in connection with deposits made into a Rural Utilities Service Cushion of Credit Account. Deposits intoThe Farm Bill passed by Congress in December 2018 modified the Cushion of Credit Account are voluntaryprogram. The program no longer accepts deposits and the interest rate earned on existing deposits will change over time. Existing deposits will continue to earn a rate of interest of 5% per annum. The fundsuntil October 1, 2020, at which point deposits will earn 4% until October 1, 2021, at which point deposits will earn the 1-year floating Treasury rate. Funds in the account, including interest thereon, can only be applied to debt service on Rural Utilities Service-guaranteed Federal Financing Bank notes. From timeWe will determine when to time, we may deposit additionalapply the remaining funds intoin the Cushion of Credit Account.2017,2019, we had only one financial agreement in place containing a liquidity covenant. This covenant is in connection with the Rocky Mountain lease transaction and requires us to maintain minimum liquidity of $50 million at all times during the term of the lease. We had sufficient liquidity to meet this covenant in 20172019 and expect to have sufficient liquidity to meet this covenant in 2018.2020. For a discussion of the Rocky Mountain lease transaction, see Note 4 of Notes to Consolidated Financial Statements.2017,2019, we had $8.2$9.7 billion of outstanding debt secured equally and ratably under our first mortgage indenture, a decreasean increase of $71.8$815.7 million from December 31, 2016.2018. 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.Loan.Loans. In 2014, we entered intoobtained a loan guarantee agreement withfrom the Federal Financing Bank that is guaranteed by the Department of Energy that we expect will fund $3.1provided funding for over $3.0 billion of the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. The loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by the Department of Energy. At December 31, 2017, we had borrowed $1.7 billion, including capitalized interest under this loan and we had the capacity to fund an additional $918 million under the facility based on the amount of eligible project costs already incurred. Our last advance under this loan was in December 2016. Following the bankruptcy of Westinghouse in March 2017, the loan guarantee agreement was amended to restrict advances pending the satisfaction of certain conditions, including the Department of Energy's approval of the Bechtel Agreement and a further amendment to the loan guarantee agreement to incorporate provisions related to the Bechtel Agreement and other replacement agreements. While not assured, we expect to satisfy these conditions in the second quarter of 2018. In September 2017,two new nuclear units at Plant Vogtle.issued a conditional commitment to us forexecuted an amended and restated loan guarantee agreement that increased the guarantee amount by $1.6 billionbillion. As of additional guaranteed fundingDecember 31, 2019, we had drawn all amounts available under the original loan and the outstanding amount under the loan guarantee agreement. Thiswas $3.0 billion. We were unable to advance $43.7 million designated for capitalized interest under the original loan due to timing of borrowing needs and lower than expected interest rates. We expect to begin drawing down the additional funding is subjectloan funds beginning in mid-2020. The additional $1.6 billion may be drawn through November 2023.an amendment and restatementfund over $4.6 billion of the loan guarantee agreement, completioncost to construct the new Vogtle units. When combined, the $4.6 billion of due diligencefunding guaranteed by the Department of Energy receiptand the $1.9 billion of any necessary regulatory approvals and satisfactiondebt we have raised in the capital markets represent long-term financing for more than 85% of certain other conditions and final approval and issuance of the additional loan guarantee cannot be assured. The conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy.our $7.5 billion project budget. We expect to close on this facility in the second quarter of 2018. If closed, our aggregate Department of Energy loanraise long-term financing for the Vogtle expansion project will increaseremaining amounts, up to nearly $4.7 billion.$1.0 billion based on our current budget, in the capital markets.this loan,these loans, see Note 77a of Notes to Consolidated Financial Statements. At December 31, 2017, we had funded in the aggregate approximately $3.1 billion of our Vogtle project cost. In addition to the Department of Energy funding, we have issued $1.4 billion of first mortgage bonds to finance the portion of the Vogtle expansion that will not be funded by the Department of Energy. Depending on the final Vogtle project cost and the final amount advanced under the Department of Energy-guaranteed loan, there may be a need for additional capital market financing.twoone approved Rural Utilities Service-guaranteed loansloan totaling $678$448.3 million that are in various stages of being drawn down, with $481has $28 million remaining to be advanced. The two loans includeWe also have a $448conditional commitment on a Ruralloan thatwhich we closedexpect to begin advancing in January 2018 to fund general and environmental improvements.early 2021. As of December 31, 2017,2019, we had $2.5 billion of debt outstanding under various Rural Utilities Service-guaranteed loans, a decrease of $124.4$50.8 million from December 31, 2016. In October 2017, On April 1, 2020, $212.8 million of Series 2013 term-rate pollution control revenue bonds that were issued on our behalf by the Development Authorities of Appling, Burke Heard and Monroe Countiescounties are subject to mandatory tender. In light of the current difficult market conditions brought about by the coronavirus pandemic, we expect to purchase these bonds for our own account until they can be remarketed. We are in Georgia issued, ondiscussions with our behalf, $122.6 million of variable rate pollution control revenue bonds. The bonds were directly purchased by a bankbanks and the proceeds were usedwe expect to repay outstanding commercial paper that we issued in January 2017 in connection withincrease the redemption of a like amount of bank credit facilities we have available in order to maintain our remaining auction rate pollution control revenuestrong liquidity position when we buy-in these bonds. In December 2017, the Development Authority of Burke County, Georgia issued, on our behalf, $399.8 million of variable rate pollution control revenue bonds, which were directly purchased by two banks and the proceeds were used to defease various series of pollution control revenue bonds issued in 2008 that became callable on January 1, 2018. On February 1, 2018, the bank held bonds were remarketed to investors, with $200 million of the bonds converted to a fixed rate mode and the remaining $199.8 million converted to term rate modes.ratably with all other debt under our first mortgage indenture.20182020 through 2020.2022. Actual expenditures may vary from the estimates listed in the table because of factors such as changes in business conditions, design changes and rework required by regulatory bodies, delays in obtaining necessary regulatory approvals, construction delays, changing environmental requirements, and changes in cost of capital, equipment, material and labor.(dollars in millions) 2020 2021 2022 Total $ 1,166 $ 757 $ 532 $ 2,455 168 106 112 386 22 37 30 89 90 105 119 314 General Plant 5 5 4 14 Total $ 1,451 $ 1,010 $ 797 $ 3,258 2018 2019 2020 Total $ 918 $ 1,007 $ 810 $ 2,735 134 111 113 358 114 43 30 187 79 69 78 226 10 10 9 29 $ 1,255 $ 1,240 $ 1,040 $ 3,535 No.4. In addition to the amounts reflected in the table above, we have budgeted approximately $1.3 billion to complete construction of Vogtle Units No. 3 and No. 4 beyond the years shown in the table. For4.thisthe Vogtle project, see "BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources – Plant Vogtle Units No. 3 and No. 4" and "–Financing Activities."–Environmental.– Environmental."2017,2019, our contractual obligations for the periods indicated.Contractual Obligations (dollars in millions) 2020 2021-
20222023-
2024Beyond
2024Total Long-Term Debt: $ 211 $ 440 $ 866 $ 8,209 $ 9,726 381 741 704 4,547 6,373 15 30 30 55 130 Operating Leases 1 1 1 1 4 — — — 36 36 Maintenance Agreements 54 29 33 219 335 6 53 75 3,454 3,588 132 192 135 813 1,272 Total $ 800 $ 1,486 $ 1,844 $ 17,334 $ 21,464 2018 2019-
2020 2021-
2022 Beyond
2022 Total $ 210 $ 891 $ 379 $ 6,866 $ 8,346 306 572 604 4,042 5,524 22 30 23 93 168 5 4 – – 9 – – – 36 36 19 3 – – 22 11 18 46 2,912 2,987 138 189 163 816 1,306 $ 711 $ 1,707 $ 1,215 $ 14,765 $ 18,838 ifat the later of (i) maturity date of the credit support facilities forbacking the Series 2009 and Series 2010 pollution control bonds were drawn uponor at the mandatory redemption date of the Series 2017 A and became payable in accordance with their terms, such as would occur ifSeries 2017B pollution control bonds or, (ii) at the maturity of an alternative back-up facility we currently have available to refinance draws on the credit facilities. We currently maintain a $1.21 billion syndicated bank credit facility providingwith a maturity date of December 2024 which backs the support were not renewed or extended at its expiration date. These amounts equal $18.7 million in 2018, $37.4 million in 2019, $170.9 million in 2020Series 2010 pollution control bonds and $18.7 million in 2021. We anticipate extendingwould be available as an alternative back-up credit facility for the Series 2009 and Series 2017 pollution control bonds noted above. As such, December 2024 is the designated maturity date for all of these credit facilities before their expirations.pollution control bonds. The nominal maturities of the Series 2009 and Series 2010 pollution control bonds range from 2030 through 2038.LIBOR and SIFMA interest rate curves as of February 2018. Our RatingsS&PMoody'sFitch Long-term ratings:S&P Moody's Fitch Senior secured rating BBB+ A-Baa1 Baa1A-BBB+BBB+ A-Baa2 Baa2N/R(2)BBB+Negative NegativeStable StableStableNegativeA-2 A-2P-2 P-2F2 F1
unsecured, however, pricing of our $1.2 billion syndicated line of credit is determined based on our unsecured or issuer ratings.unsecured.(2)N/R indicates no rating assigned for this category.2017,2019, our maximum potential collateral requirements were as follows:a total of $54$58 million at a senior secured level of BBB-/Baa3,a total of $83$107 million at a senior secured level of BB+/Ba1 or below, anda total of a total of $60$68 million at a senior unsecured or issuer rating level of BB+/Ba1 or below.ourcredit agreements and pollution control bond agreements contain provisions based on our ratings that, upon a credit rating downgrade belowlinelines of credit agreements are based on credit ratings and could increase if our ratings are lowered. None of these covenants and provisions, however, would result in acceleration of any debt due to credit rating downgrades. At December 31, 2017, we wererelatedrelating to a portion of our $959debt. We categorize our debt as variable rate, which is debt that is subject to a change in interest rates within the next year, intermediate-term fixed rate debt, which is debt that is not subject to a change in interest rates within the next year, but is subject to a change in interest rates within the next five years, or long-term fixed rate debt, which is debt that is not subject to a change in interest rates within the next five years. At December 31, 2019, we had $863.4 million of variable rate debt, which includes $190.6$99.8 million of intermediate-term fixed rate debt, and the remainder of our debt was long-term fixed rate debt. Our $863.4 million of variable rate debt at December 31, 2019, included $282.4 million of commercial paper outstanding (which typically has maturities of between 1 and 90 days) and $768$581.0 million of pollution control bond debt (including variable rate demand bonds and indexed variable rate bonds, which are both subject to repricing weekly, and indexed variableterm rate bonds)debt subject to remarketing and repricing on April 1, 2020). On February 1, 2018, we converted the interest rate mode on $399.8Our $99.8 million of pollution control bonds from a variableintermediate-term fixed rate mode into fixed interestdebt at December 31, 2019 consisted of one series of term rate modes, including both fixeddebt subject to maturityremarketing and fixed for a term of five or seven years. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition –Financing Activities –Bond Financings."2017,2019, the weighted average interest rate on thisour variable rate debt excluding the $399.8 million in pollution control bonds that was subsequently converted to fixed rates, was 1.85%2.15%. If, during 2018,2020, interest rates on this debt changed a hypothetical 100 basis points on the respective repricing dates and remained at that level for the remainder of the year, annual interest expense would change by approximately $6$8 million.2017, excluding the $399.8 million in pollution control bonds that was subsequently converted to fixed rates,2019, we had 6.63%8.6% of our total debt, including commercial paper, in aclassified as variable rate mode.Commission (see Note 1 of Notes to Consolidated Financial Statements).Commission. We also maintain an internal reserve for decommissioning (included in "Long-term investments" on the balanceTable For further discussion on our nuclear decommissioning trust funds, see Note 1 of Contents20172019 would result in a loss of value to the funds of approximately $34$39.8 million. For further discussion on our nuclear decommissioning trust funds, see Note 1 of Notes to Consolidated Financial Statements.Coalwillare expected to provide fixed prices for up to 87%91% and 12% of our remaining 20182020 forecasted coal requirements at Plants Scherer. We currently do not have any fixed price contracts for PlantScherer and Wansley, and will utilize the spot market to meet its coal requirements. approximately 18 of our members have elected to participate in our natural gas hedging program. This program layers in fixed prices for a portion of our forecasted natural gas requirements over a rolling time horizon of up to five and a half years. Natural gas swap arrangements are used for hedging under this program. Under our swap agreements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment. The fair value of the swaps at December 31, 20172019 was a net liability of approximately $6.3$32.3 million, which represents the net amount we would have paid if the swaps had been terminated as of that date. As of December 31, 2017,2019, approximately 35%31% of our 20182020 total system forecasted natural gas requirements were hedged under swap arrangements. A hypothetical 10% decline in the market price of natural gas would have resulted in a decrease of approximately $23.2$19.2 million to the fair value of our natural gas swap agreements. Additional members may elect to participate in our natural gas hedging program, and participating members may choose to discontinue their active participation in this program at any time.PagePage (Deficit)(Deficit) Margin For the Years Ended December 31, 2017, 2016,2019, 2018, and 20152017, 20162019, 2018 and 2015
2017#VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! #VALUE! (dollars in thousands) 2019 2018 2017 Operating revenues: Sales to Members $ 1,429,852 $ 1,479,379 $ 1,433,830 Sales to non-Members 440 734 366 Total operating revenues 1,430,292 1,480,113 1,434,196 Operating expenses: Fuel $ 440,214 $ 502,904 $ 473,184 Production 410,328 417,391 401,374 Depreciation and amortization 243,512 233,284 224,098 Purchased power 68,556 63,468 59,996 Accretion 50,473 38,090 36,674 Total operating expenses $ 1,213,083 $ 1,255,137 $ 1,195,326 Operating margin $ 217,209 $ 224,976 $ 238,870 Other income: Investment income $ 59,182 $ 60,055 $ 56,122 Amortization of deferred gains 1,788 1,788 1,788 Allowance for equity funds used during construction 771 1,006 784 Other 2,448 5,413 6,291 Total other income $ 64,189 $ 68,262 $ 64,985 Interest charges: Interest expense $ 403,244 $ 381,242 $ 374,345 Allowance for debt funds used during construction (187,954) (151,643) (134,319) Amortization of debt discount and expense 11,647 12,440 12,552 Net interest charges $ 226,937 $ 242,039 $ 252,578 Net margin $ 54,461 $ 51,199 $ 51,277 (dollars in thousands) 2017 2016 2015 $ 1,433,830 $ 1,506,807 $ 1,219,052 366 424 130,773
1,434,196
1,507,231
1,349,825
473,184 513,258 441,738 401,374 434,306 457,264 224,098 217,534 168,920 59,996 54,108 56,925 36,674 32,361 26,108 – – (58,588 ) 1,195,326 1,251,567 1,092,367 238,870 255,664 257,458
56,122 51,656 40,424 1,788 1,788 1,788 784 788 675 6,291 2,671 9,143 64,985 56,903 52,030
374,345 366,892 354,269 (134,319 ) (116,634 ) (108,667 ) 12,552 11,964 15,545 252,578 262,222 261,147
$
51,277
$
50,345
$
48,341 2017, 20162019, 2018 and 20152017(dollars in thousands) 2019 2018 2017 Net Margin $ 54,461 $ 51,199 $ 51,277 Other comprehensive margin: Amounts reclassified to regulatory assets — — 370 Total comprehensive margin $ 54,461 $ 51,199 $ 51,647 (dollars in thousands) 2017 2016 2015
$
51,277
$
50,345
$
48,341 – (428 ) (410 ) 370 – –
$
51,647
$
49,917
$
47,931 20172019 and 2016
2018(dollars in thousands) 2019 2018 Assets Electric plant: In service $ 9,209,983 $ 8,981,238 Right-of-use assets--finance leases 302,732 302,732 Less: Accumulated provision for depreciation (4,833,025) (4,544,405) 4,679,690 4,739,565 Nuclear fuel, at amortized cost 359,270 358,358 Construction work in progress 4,816,896 3,866,042 Total electric plant 9,855,856 8,963,965 Investments and funds: Nuclear decommissioning trust fund 511,339 420,818 Investment in associated companies 73,318 77,037 Long-term investments 254,864 164,125 Restricted investments 461,757 503,158 Other 26,422 24,259 Total investments and funds 1,327,700 1,189,397 Current assets: Cash and cash equivalents 448,612 752,618 Restricted short-term investments 71,833 150,000 Receivables 166,429 153,647 Inventories, at average cost 277,729 259,087 Prepayments and other current assets 9,862 8,098 Total current assets 974,465 1,323,450 Deferred charges and other assets: Regulatory assets 763,512 655,063 Prepayments to Georgia Power Company 48,052 29,459 Other 20,528 21,934 Total deferred charges 832,092 706,456 Total assets $ 12,990,113 $ 12,183,268 (dollars in thousands) 2017 2016
$ 8,886,407 $ 8,786,839 (4,302,332 ) (4,115,339 ) 4,584,075 4,671,500
358,562
377,653 2,935,868 3,228,214 7,878,505 8,277,367
445,055 386,029 74,981 72,783 140,622 99,874 653,585 221,122 22,562 20,730 1,336,805 800,538
397,695 366,290 229,324 247,006 156,781 155,042 266,219 259,831 18,884 32,919 1,068,903 1,061,088
585,084 545,387 45,575 3,948 13,267 12,785 643,926 562,120 $ 10,928,139 $ 10,701,113
6320172019 and 2016
2018(dollars in thousands) 2019 2018 Equity and Liabilities Capitalization: Patronage capital and membership fees $ 1,016,747 $ 962,286 Long-term debt 9,403,847 8,727,148 Obligations under finance leases 75,649 81,730 Other 25,196 21,428 Total capitalization 10,521,439 9,792,592 Current liabilities: Long-term debt and finance leases due within one year 217,440 522,289 Short-term borrowings 282,370 — Accounts payable 165,049 206,577 Accrued interest 65,895 60,971 Member power bill prepayments, current 77,066 224,957 Other current liabilities 49,443 49,465 Total current liabilities 857,263 1,064,259 Deferred credits and other liabilities: Asset retirement obligations 1,070,640 1,017,563 Member power bill prepayments, non-current 134,396 54,750 Regulatory liabilities 364,241 218,998 Other 42,134 35,106 Total deferred credits and other liabilities 1,611,411 1,326,417 Total equity and liabilities $ 12,990,113 $ 12,183,268 Commitments and Contingencies (Notes 1, 7, 10, 11 and 12) (dollars in thousands) 2017 2016
$ 911,087 $ 859,810 – (370 )
7,927,562
7,892,836 87,192 92,096 20,051 18,765 8,945,892 8,863,137
216,694 316,861 190,626 102,168 212,868 73,801 79,510 93,634 6,171 176,988 55,136 59,979 761,005 823,431
734,997 698,051 203,615 48,115 – 40,008 251,649 197,748 30,981 30,623 1,221,242 1,014,545 $ 10,928,139 $ 10,701,113
6420172019 and 2016
2018(dollars in thousands) 2019 2018 Secured Long-term debt: First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.84% to 8.43% (average rate of 3.85% at December 31, 2019) due in quarterly installments through 2046 $ 2,526,867 $ 2,577,699 First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.51% to 3.87% (average rate of 3.37% at December 31, 2019) due in quarterly installments through 2044 3,013,348 1,794,723 First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.75% to 4.90% (average rate of 4.79% at December 31, 2019) due in quarterly installments through 2020 391 1,426 First mortgage bonds payable: 300,000 300,000 500,000 500,000 — 350,000 400,000 400,000 5,052 6,062 450,000 450,000 300,000 300,000 250,000 250,000 250,000 250,000 250,000 250,000 500,000 500,000 First mortgage notes issued in connection with the sale of pollution control revenue bonds through the Development Authorities of Appling, Burke, Heard and Monroe Counties, Georgia: 112,055 112,055 133,550 133,550 212,760 212,760 122,620 122,620 200,000 200,000 100,000 100,000 99,785 99,785 Total Secured Long-term debt $ 9,726,428 $ 8,910,680 Unsecured debt: Commercial paper refinanced on a long-term basis — 436,627 Total Long-term debt $ 9,726,428 $ 9,347,307 Obligations under finance leases 81,730 87,191 Obligation under Rocky Mountain transactions 25,196 21,428 Patronage capital and membership fees 1,016,747 962,286 Subtotal $ 10,850,101 $ 10,418,212 Less: long-term debt and finance leases due within one year (217,440) (522,289) Less: unamortized debt issuance costs (100,680) (92,377) Less: unamortized bond discounts on long-term debt (10,542) (10,954) Total capitalization $ 10,521,439 $ 9,792,592 (dollars in thousands) 2017 2016
$
2,456,864
$
2,581,281
1,735,586
1,678,442 2,411 3,347
First Mortgage Bonds, 5.534%, due 2031 through 2035 300,000 300,000
First Mortgage Bonds, 6.191%, due 2024 through 2031 500,000 500,000
First Mortgage Bonds, 6.10%, due 2019 350,000 350,000
First Mortgage Bonds, 5.95%, due 2039 400,000 400,000
Clean renewable energy bond, 1.81%, due 2024 7,072 8,083
First Mortgage Bonds, 5.375% due 2040 450,000 450,000
First Mortgage Bonds, 5.25% due 2050 300,000 300,000
First Mortgage Bonds, 4.20% due 2042 250,000 250,000
First Mortgage Bonds, 4.55% due 2044 250,000 250,000
First Mortgage Bonds, 4.25% due 2046 250,000 250,000
Auction rate bonds, fully redeemed January 2017 – 95,230
Auction rate bonds, fully redeemed January 2017 – 11,525
Auction rate bonds, fully redeemed January 2017 – 15,865
Fixed rate bonds, 5.30% to 5.70%, fully defeased December 2017 – 255,035
Fixed rate bonds, 7.00%, fully defeased December 2017 – 144,750
Weekly rate bonds, 1.65% to 1.75%, due 2030 through 2038 112,055 112,055
Weekly rate bonds, 1.70% to 1.72%, due 2036 through 2037 133,550 133,550
Term rate bonds, 2.40% through April 1, 2020, due 2038 through 2040 212,760 212,760
Indexed put bonds–weekly reset, 2.56% due 2040 through 2045 122,620 –
Indexed put bonds–monthly reset, 1.69% due 2041 through 2045 200,000 –
Indexed put bonds–weekly reset, 2.56% due 2041 through 2045 199,785 –
– 419 – 2,181 $ 8,232,703 $ 8,304,523 94,358 98,531 20,051 18,765 911,087 859,810 – (370 ) 9,258,199 9,281,259 (216,694 ) (316,861 ) (87,802 ) (93,133 ) (7,811 ) (8,128 ) $ 8,945,892 $ 8,863,137
652017, 20162019, 2018 and 2015
2017(dollars in thousands) 2019 2018 2017 Cash flows from operating activities: Net margin $ 54,461 $ 51,199 $ 51,277 Adjustments to reconcile net margin to net cash provided by operating activities: Depreciation and amortization, including nuclear fuel $ 377,853 $ 371,234 $ 374,411 Accretion cost 50,473 38,090 36,674 Amortization of deferred gains (1,788) (1,788) (1,788) Allowance for equity funds used during construction (771) (1,006) (784) Deferred outage costs (34,505) (31,863) (40,644) (Gain) loss on sale of investments (6,058) 4,871 (18,614) Regulatory deferral of costs associated with nuclear decommissioning (23,982) (26,511) (2,605) Other (1,097) (5,676) (9,240) Change in operating assets and liabilities: Receivables 24,251 8,424 (1,182) Inventories (18,597) 5,487 (6,388) Prepayments and other current assets (1,992) 4,544 614 Accounts payable (27,668) 1,360 129,187 Accrued interest 4,924 (18,539) (14,124) Accrued and withheld taxes 2,943 (21,351) (1,531) Other current liabilities (24,069) 25,723 (8,646) Member power bill prepayments (68,245) 69,921 (15,317) Other 45,228 15,578 — Total adjustments $ 296,900 $ 438,498 $ 420,023 Net cash provided by operating activities $ 351,361 $ 489,697 $ 471,300 Cash flows from investing activities: Property additions $ (1,255,188) $ (1,185,367) $ (1,019,695) Guarantee settlement proceeds — — 1,104,000 Activity in nuclear decommissioning trust fund – Purchases (374,338) (457,909) (450,113) – Proceeds 365,871 449,895 442,989 Decrease (increase) in restricted investments 119,568 229,751 (414,781) Activity in other long-term investments – Purchases (251,077) (207,670) (108,704) – Proceeds 178,172 176,717 78,356 Other (21,493) 9,144 (43,056) Net cash used in investing activities $ (1,238,485) $ (985,439) $ (411,004) Cash flows from financing activities: Long-term debt proceeds $ 1,266,950 $ 813,028 $ 544,503 Long-term debt payments (523,691) (201,354) (677,641) (Decrease) increase in short-term borrowings, net (154,257) 246,001 88,458 Other (5,884) (7,010) 15,789 Net cash provided by (used in) financing activities 583,118 850,665 (28,891) Net (decrease) increase in cash and cash equivalents $ (304,006) $ 354,923 $ 31,405 Cash and cash equivalents at beginning of period 752,618 397,695 366,290 Cash and cash equivalents at end of period $ 448,612 $ 752,618 $ 397,695 Supplemental cash flow information: Cash paid for – Interest (net of amounts capitalized) $ 208,892 $ 245,085 $ 251,186 Supplemental disclosure of non-cash investing and financing activities: Change in asset retirement obligations $ 5,282 $ 248,608 $ 2,414 Accrued property additions at end of period $ 94,492 $ 121,557 $ 134,082 Interest paid-in-kind $ 67,028 $ 59,137 $ 57,144 (dollars in thousands) 2017 2016 2015 $ 51,277 $ 50,345 $ 48,341 374,411 362,716 313,320 36,674 32,361 26,108 (1,788 ) (1,788 ) (1,788 ) (784 ) (788 ) (675 ) (40,644 ) (40,599 ) (40,803 ) – – (58,588 ) (18,614 ) 96 (34,464 ) (2,605 ) (20,440 ) 21,532 (9,240 ) (7,286 ) (8,353 ) (1,182 ) (24,578 ) (98 ) (6,388 ) 23,947 (28,403 ) 614 (2,172 ) (4,317 ) 129,187 (76,495 ) (37,155 ) (14,124 ) 34,804 (11 ) (1,531 ) 1,102 3,731 (8,646 ) (11,937 ) 2,805 (15,317 ) 6,155 20,994 420,023 275,098 173,835 471,300 325,443 222,176 (1,019,695 ) (613,019 ) (495,426 ) 1,104,000 – – (450,113 ) (395,506 ) (558,568 ) 442,989 389,011 553,654 (432,463 ) (86,432 ) (16,301 ) 17,682 6,198 (6,076 ) (108,704 ) (61,200 ) (89,263 ) 78,356 50,529 86,563 (43,056 ) 13,554 (13,068 ) (411,004 ) (696,865 ) (538,485 ) 544,503 790,385 423,637 (677,641 ) (114,702 ) (162,903 ) 88,458 (159,310 ) 27,109 15,789 8,301 4,113 (28,891 ) 524,674 291,956 31,405 153,252 (24,353 ) 366,290 213,038 237,391 $ 397,695 $ 366,290 $ 213,038 $ 251,186 $ 212,574 $ 240,817 $ 2,414 $ 63,011 $ 144,161 $ (28,457 ) $ (50,775 ) $ 119,775 $ 57,144 $ 47,814 $ 36,021
66PATRONAGE CAPITAL AND MEMBERSHIP FEES ANDACCUMULATED OTHER COMPREHENSIVE (DEFICIT) MARGIN
CASH FLOWS2017, 20162019, 2018 and 2015
2017(dollars in thousands) Patronage
Capital and
Membership
FeesAccumulated
Other
Comprehensive
(Deficit) MarginTotal Balance at December 31, 2016 $ 859,810 $ (370) $ 859,440 Components of comprehensive margin in 2017: Net margin 51,277 — 51,277 Amounts reclassified to regulatory assets — 370 370 Total comprehensive margin $ 51,647 Balance at December 31, 2017 $ 911,087 $ — $ 911,087 Components of comprehensive margin in 2018: ��Net margin 51,199 — 51,199 Total comprehensive margin $ 51,199 Balance at December 31, 2018 $ 962,286 $ — $ 962,286 Components of comprehensive margin in 2019: Net margin 54,461 — 54,461 Total comprehensive margin in 2019 $ 54,461 Balance at December 31, 2019 $ 1,016,747 $ — $ 1,016,747 (dollars in thousands) Patronage
Capital and
Membership
Fees Accumulated
Other
Comprehensive
(Deficit) Margin Total $ 761,124 $ 468 $ 761,592
48,341 – 48,341 – (410 ) (410 ) 47,931
$
809,465
$
58
$
809,523
50,345 – 50,345 – (428 ) (428 ) 49,917
$
859,810
$
(370
)
$
859,440
51,277 – 51,277 – 370 370 51,647
$
911,087
$
–
$
911,087
672017, 20162019, 2018 and 20157,1157,125 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 728738 megawatts of summer planning reserve capacity. In addition, we supply financial and management services to Green Power EMC, which purchases energy from renewable energy facilities totaling 119160 megawatts of capacity, including 86127 megawatts sourced by solar energy. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. Our members in turn distribute energy on a retail basis to approximately 4.14.2 million people.20172019 and 20162018 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2017.2019. Examples of estimates used include items related to our asset retirement obligations and revenue recognition. Accounting for asset retirement and environmental obligations requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. In the absence of quoted market prices, we estimate the fair value of our asset retirement obligations using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using a credit-adjusted risk-free rate. Estimating the amount and timing of future expenditures includes, among other things, making projections of when assets will be retired and ultimately decommissioned, the amount of decommissioning costs, and how costs will escalate with inflation. Actual results could differ from those estimates. Certain fair value hierarchy disclosures have been revised to conform to the current period classification. Securities previously classified as "US Treasury and government agency securities" under Level 1 in the fair value hierarchy totaling $37,884,000 as of December 31, 2016 in the fair value table of Note 2 are now presented under Level 2 as "Mortgage backed securities" and "Federal agency securities." These changes do not impact the investment portfolio or the fair value of the assets that are recorded in the financial statements.2017, 20162019, 2018 and 2015,2017, we achieved a margins for interest ratio of 1.14.OperatingRevenue recognition Electricity are derived primarily from wholesale power contracts we have with each of our 38 members. These contracts, which extend to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. While not significant, we also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments.whenby us upon transfer of control of promised services to our members and non-members in an amount that reflects the consideration we expect to receive in exchange for those services. Capacity and energy are distinct and we account for them as separate performance obligations. The obligations to provide capacity and energy are provided. Operating revenues from sales to members consist primarilysatisfied over time as the customer simultaneously receives and consumes the benefit of electricity sales pursuant to long-term wholesale power contracts which we maintain with eachthese services. Both performance obligations are provided directly by us and not through a third party.members. These wholesale power contracts obligate each membermembers is obligated to pay us for capacity and energy furnishedwe furnish under its wholesale power contract in accordance with rates we establish. Capacity revenues recoverWe review our rates periodically but are required to do so at least once every year. Revenues from our members are derived through a cost-plus rate structure which is set forth as a formula in the rate schedule to the wholesale power contracts. The formulary rate provides for the pass-through of our (i) fixed costs (net of any income from other sources) plus a targeted margin as capacity revenues and (ii) variable costs as energy revenues from our members. Power purchase and sale agreements between us and non-members obligate each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices mutually agreed upon. Margins produced from non-member sales are included in our rate schedule formula and reduce revenue requirements from our members.chargedrecognized and billed to our members in equal monthly installments over the course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. CapacityNon-member capacity revenues, if any, are typically billed and recognized in equal monthly installments over the term of the contract.an annual budget and, notwithstanding budget adjustmentsour avoided cost of borrowing. For additional information regarding our member prepayment program, see Note 1p.meetdeliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our targeted margin, are recorded in approximately equal amounts throughoutmembers based upon the year. Energy revenues recover variable costs such as fuel, incurred to generate or purchase electricitythat energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members’ service territories, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned orrecordedrequired under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2019 and 2018, our board approved, and we achieved, a targeted margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that energyrevenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual energyfixed costs incurred. Priorand targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to 2016, operatingdetermine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. As of December 31, 2019 and December 31, 2018, we recognized refund liabilities totaling $14,989,000 and $30,870,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from salesnon-members.non-members consisted primarily of energy sales at Smith.(dollars in thousands) 2019 2018 2017 Capacity revenues $ 942,057 $ 927,419 $ 912,421 Energy revenues 487,795 551,960 521,409 Total $ 1,429,852 $ 1,479,379 $ 1,433,830 2019 2018 2017 Jackson EMC 14.4 % 14.1 % 14.7 % Cobb EMC 13.8 % 13.9 % 14.3 % 2016were insignificant.2015: 2017 2016 2015 14.7 % 14.3 % 9.7 % 14.3 % 13.7 % 13.1 % n/a 10.5 % 10.4 % certaininterest costs on a current basis that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual basis. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under this program, amounts billed to participating members in 2019, 2018 and 2017 2016were $14,943,000, $12,229,000 and 2015 were $11,000,000, $16,096,000 and $7,630,000, respectively. The cumulative amount billed since inception of the program totaled $54,087,000. Prior$81,259,000.2016, members also subscribed to the Smith program, which allowed for the accelerated recovery of deferred net costs related to Smith. The Smith program ceased as of December 31, 2015 when the plant became available for scheduling torecover future expense on a current basis from our members. In general, the program allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The amountprogram is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. Under this program, amounts billed to participating members underduring 2019 and 2018 were $73,051,000 and $15,435,000, respectively. Funds collected through this program in 2015 was $17,745,000are invested and held until applied to members’ bills. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income on the funds$58,922,000.electricitycapacity and energy sales to our members. These receivables are recorded at the invoiced amount and do not bear interest. Our members are required through the wholesale power contracts to reimburse us for all costs, plus a margin requirement. Member receivablesReceivables from contracts with our members at December 31, 2019, 2018 and 2017 were $142,946,000, $122,888,000 and 2016 were $126,211,000, respectively. Payment is received the following month in which capacity and $136,552,000, respectively. energy are billed. Estimated energy charges are billed based on the amount of energy supplied during the month and are adjusted when actual costs are available, generally the following month.2017, 20162019, 2018 and 20152017 amounted to $79,893,000, $85,949,000, and $90,520,000, $83,751,000, and $78,762,000, respectively. On December 14, 2014,Court of Federal Claims issued a judgmentGovernment in favor of Georgia Power, as agent for the co-owners, to recover spent nuclear fuel storage costs at Plants Hatch and Vogtle Units No. 1 and No. 2 covering the period of 2005 through 2010. Our ownership share of the $36,474,000 total award was $10,949,000, which was received in April 2015. The effects of the award were recorded during the first quarter of 2015 and resulted in a $7,320,000 reduction in total operating expenses, including reductions to fuel expense and production costs, as well as a $3,629,000 reduction to plant in service. On October 10, 2017, Georgia Power, as agent for the co-owners filed a separate claim2014 (as amended) seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering athe period from January 1, 2011 through December 31, 2014. On June 12, 2019, the U.S. Court of Federal Claims granted Georgia Power’s motion for summary judgement on damages not disputed by the U.S. Government and awarded the undisputed damages to Georgia Power. In addition, Georgia Power previously filed a separate claim to cover periods January 1, 2011 through December 31, 2013 which was subsequently amended and extended through December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. NoNaN amounts were recognized in the financial statements as of December 31, 20172019 for this claim.these additional claims. The final outcome of these matters cannot be determined at this time.facilities.facilities and coal ash ponds. In addition, we have retirement obligations related to coal ash ponds, gypsum cells, powder activated carbon cells, landfill sites and asbestos removal. Under the accounting provision for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognition of the costs related to nuclear and coal ash related decommissioning for financial statement purposes and for ratemaking purposes.20152018 and 2016,2019, respectively.Asset Retirement Obligationsasset retirement obligations included in the consolidated balance sheets for the years 20172019 and 2016.(dollars in thousands) Nuclear Coal Ash Pond Other Total Balance at December 31, 2018 $ 658,956 $ 326,248 $ 32,359 1,017,563 Liabilities settled — (3,380) (1,158) (4,538) Accretion 38,485 10,494 1,494 50,473 Deferred accretion — 1,860 — 1,860 Change in cash flow estimates — (5,958) 11,240 5,282 Balance at December 31, 2019 $ 697,441 $ 329,264 $ 43,935 $ 1,070,640 (dollars in thousands) Nuclear Coal Ash
Pond Other Total $ 517,565 $ 156,465 $ 24,021 $ 698,051 (17 ) (943 ) (1,185 ) (2,145 ) 31,026 4,629 1,019 36,674 – 1,604 813 2,417 $ 548,574 $ 161,755 $ 24,668 $ 734,997 (dollars in thousands) Nuclear Coal Ash Pond Other Total Balance at December 31, 2017 $ 548,574 $ 161,755 $ 24,668 $ 734,997 Liabilities settled (1,686) (1,596) (1,398) (4,680) Accretion 32,857 4,238 995 38,090 Change in cash flow estimates 79,211 161,851 8,094 249,156 Balance at December 31, 2018 $ 658,956 $ 326,248 $ 32,359 $ 1,017,563 (dollars in thousands) Nuclear Coal Ash
Pond Other Total $ 488,458 $ 93,622 $ 20,150 $ 602,230 – (553 ) (707 ) (1,260 ) 29,107 2,215 1,039 32,361 – 61,181 3,539 64,720 $ 517,565 $ 156,465 $ 24,021 $ 698,051 The estimated costsOur most recent assessment of decommissioning are based on the most current study performednuclear asset obligation, which occurred in 2015.2018 resulted in a $79,211,000 increase in the obligation for nuclear decommissioning. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.5%. The2.8% for the Hatch units and 2.7% for Vogtle Units 1 & 2. That increase in the cash flow estimates in 2015 was primarily attributable to securitygeneral inflation, labor costs, volume of low-level radioactive waste disposal costs and inflation,spent fuel management, among other factors. Our portion ofwereare as follows:(dollars in thousands) 2018 site study Hatch
Unit No. 1Hatch
Unit No. 2Vogtle
Unit No. 1Vogtle
Unit No. 2Expected start date of decommissioning 2034 2038 2047 2049 Estimated costs based on site study in 2018 dollars: Radiated structures $ 209,000 $ 231,000 $ 188,000 $ 206,000 Spent fuel management 54,000 49,000 55,000 51,000 Non-radiated structures 14,000 19,000 23,000 29,000 Total estimated site study costs $ 277,000 $ 299,000 $ 266,000 $ 286,000 (dollars in thousands) Hatch
Unit No. 1 Hatch
Unit No. 2 Vogtle
Unit No. 1 Vogtle
Unit No. 2 2034 2038 2047 2049 $ 193,000 $ 213,000 $ 178,000 $ 195,000 49,000 47,000 49,000 47,000 16,000 22,000 26,000 33,000 $ 258,000 $ 282,000 $ 253,000 $ 275,000 Ash Pond. On April 17, 2015 the Environmental Protection Agency published its final coalCombustion Residuals. Coal combustion residuals (CCR) rule which regulates CCRs as non-hazardous materials under Subtitle Dare subject to Federal and State regulations. Our obligations associated with CCR are primarily for the closure of coal ash ponds. During 2019 and 2018, assessments of the Resource Conservation and Recovery Act. The rule took effect on October 19, 2015. Our most current assessment of the final CCR rulecoal ash pond asset retirement obligation resulted in a $1,604,000 change5,958,000 decrease and a $161,303,000 increase in cash flow estimatesthe obligation for coal ash pond decommissioning.decommissioning, respectively. Estimates are based on various assumptions including, but not limited to, closure and post-closure cost estimates, timing of expenditures, escalation factors, discount rates and methods for complying with the CCR rule.regulations. The 2017 and 2016 increasessignificant increase in cash flow estimates werein 2018 was primarily attributed to an increase in the refinement of site specific closure cost estimates.strategies and the associated costs, including water treatment requirements, and the estimated amount of coal ash to be consolidated. Additional adjustments to the asset retirement obligations are expected periodically due to potential changes in estimates and assumptions.we continuea regulatory asset. As this difference is attributable to assess the impactassociated expenses being greater than amounts collected through rates, this difference is recorded as a deferral of expense in our consolidated statements of revenues and expenses. Unrealized gains and losses, if any, of the rule, including potential changes, onassociated decommissioning fund are recorded directly to the regulatory asset in accordance with our estimates and assumptions. Other.ratemaking treatment.20172019 and 2016, no2018, 0 additional amounts were contributed to the external trust funds. These funds are managed by unrelated third party investment managers with the discretion to buy, sell and invest pursuant to investment objectives and restrictions set forth in agreements entered into between us and the investment managers. We record the investment securities held in the nuclear decommissioning trust fund which are classified as available-for-sale, at fair value, as disclosed in Note 2. Because day-to-day investment decisions are made by third party investment managers, the ability to hold investments in unrealized loss positions is outside our control.20172019 and 2016,2018, we contributed $4,750,000 into the internal funds.20172019 and December 31, 2016.2018. The funds arewere invested insecurities for both 2017 and 2016.2019 External Trust Funds: (dollars in thousands) Cost
12/31/2018Purchases Net Proceeds(1) Unrealized Gain(Loss) Fair Value 12/31/2019 Equity $ 207,313 $ 11,950 $ (6,678) $ 119,263 $ 331,848 Debt 166,023 361,844 (353,222) 5,548 180,193 Other 115 544 (1,361) — (702) $ 373,451 $ 374,338 $ (361,261) $ 124,811 $ 511,339 2017 12.31.16
Cost Purchases Net
Proceeds(1) Unrealized
Gain(Loss) 12.31.17
Fair Value $ 200,595 $ 61,406 $ (44,607 ) $ 76,221 $ 293,615 148,011 388,609 (384,199 ) 170 $ 152,591 351 98 (1,600 ) – $ (1,151 ) $ 348,957 $ 450,113 $ (430,406 ) $ 76,391 $ 445,055 12.31.16
Cost Purchases Net
Proceeds(1) Unrealized
Gain(Loss) 12.31.17
Fair Value $ 38,798 $ – $ 4,900 $ 11,669 $ 55,367 26,207 73,153 (65,820 ) – $ 33,540 $ 65,005 $ 73,153 $ (60,920 ) $ 11,669 $ 88,907 and dividends contributions and fees of $31,939,680.2019 Internal Funds: (dollars in thousands) Cost
12/31/2018Purchases Net
Proceeds(1)Unrealized
Gain(Loss)Fair Value
12/31/2019Equity $ 44,295 $ — $ 2,767 $ 19,578 $ 66,640 Debt 38,382 140,997 (135,033) 1,161 45,507 $ 82,677 $ 140,997 $ (132,266) $ 20,739 $ 112,147 2016 12.31.15
Cost Purchases Net
Proceeds(2) Unrealized
Gain(Loss) 12.31.16
Fair Value $ 198,265 $ 46,865 $ (43,395 ) $ 38,749 $ 240,484 144,187 347,383 (343,040 ) (1,675 ) $ 146,855 187 1,258 (2,754 ) (1 ) $ (1,310 ) $ 342,639 $ 395,506 $ (389,189 ) $ 37,073 $ 386,029 12.31.15
Cost Purchases Net
Proceeds(2) Unrealized
Gain(Loss) 12.31.16
Fair Value $ 33,513 $ – $ 5,285 $ 7,263 $ 46,061 25,539 42,783 (42,115 ) (211 ) $ 25,996 $ 59,052 $ 42,783 $ (36,830 ) $ 7,052 $ 72,057
$8,732,000.(2)and dividends, contributions and fees of $12,270,144.2018 External Trust Funds: (dollars in thousands) Cost
12/31/2017Purchases Net
Proceeds(1)Unrealized
Gain(Loss)Fair Value
12/31/2018Equity $ 203,622 $ 12,186 $ (7,789) $ 49,475 $ 257,494 Debt 164,901 445,353 (443,712) (2,108) 164,434 Other 141 370 (1,621) — (1,110) $ 368,664 $ 457,909 $ (453,122) $ 47,367 $ 420,818 2018 Internal Funds: (dollars in thousands) Cost
12/31/2017Purchases Net
Proceeds(1)Unrealized
Gain(Loss)Fair Value
12/31/2018Equity $ 43,698 $ — $ 596 $ 6,373 $ 50,667 Debt 33,540 161,454 (156,611) (246) 38,137 $ 77,238 $ 161,454 $ (156,015) $ 6,127 $ 88,804 6.4%7.9% in the last ten years and 6.3% since inception in 1990. Based on current funding and cost study estimates, we expect the current balances and anticipated investment earnings of our decommissioning fund assets to be sufficient to meet all of our future nuclear decommissioning costs. Notwithstanding the above assumption, our management believes that any increaseincreases in cost estimates of decommissioning can be recovered in future rates.2017 and 2016 depreciation rates for steam and nuclear production in the table below reflect revised rates from depreciation rate studies completed in 2015. Site specific depreciation studies are performed every five years. Annual weighted average depreciation rates in effect in 2017, 20162019, 2018, and 20152017 were as follows:Range of
Useful Life in
years*2019 2018 2017 Steam production 49-65 2.61 % 2.57 % 2.91 % Nuclear production 37-60 1.94 % 1.92 % 1.96 % Hydro production 50 2.00 % 2.00 % 2.00 % Other production 30-35 2.61 % 2.61 % 2.58 % Transmission 36 2.75 % 2.75 % 2.75 % General 3-50 2.00-33.33% 2.00-33.33% 2.00-33.33% Range of
Useful Life in
years* 2017 2016 2015 49-65 2.91 % 2.84 % 1.93 % 37-60 1.96 % 1.96 % 1.55 % 50 2.00 % 2.00 % 2.00 % 27-33 2.58 % 2.55 % 2.38 % 36 2.75 % 2.75 % 2.75 % 3-50 2.00-33.33 % 2.00-33.33 % 2.00-33.33 %
2019.2017.2016was $237,447,000, $227,213,000, and 2015 was $218,027,000, $211,282,000, and $180,866,000, respectively.ended2019, 2018 and 2017, 2016 and 2015, the allowance for funds used during construction rates were 4.30%, 4.25% and 4.45%, 4.61% and 4.73%, respectively.plus cost of removal, less salvage of such property, is charged to the accumulated provision for depreciation. Cost of removal, less salvage, is charged to a regulatory liability, accumulated retirement costs for other assets. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to expense, including certain major maintenance costs at our natural gas-fired plants.on depositcurrently earn interest at a rate of 5% per annum. As of October 1, 2020, deposits will earn interest at 4% per annum and beginning October 1, 2021, the rates will be set at the 1-year floating treasury rate. The program no longer allows additional funds to be deposited into the account. At December 31, 20172019 and 2016,2018, we had restricted investments totaling $882,909,000$533,590,000 and $468,179,000,$653,158,000, respectively, of which $653,585,000$461,757,000 and $221,122,000,$503,158,000, respectively, were classified as long-term. The funds on deposit with the Rural Utilities Service in the Cushion of Credit Account are held by the U.S. Treasury, acting through the Federal Financing Bank.20172019 and December 31, 2016,2018, fossil fuels inventories were $54,050,000$74,257,000 and $57,289,000,$48,709,000, respectively. Inventories for spare parts at 20172019 and 20162018 were $212,169,000$203,472,000 and $202,542,000,$210,379,000, respectively.January 2023,December 2024, with the majority of the balance scheduled to be credited by the end of 2019. During 2016,2023.connection with the Vogtle Units No. 3Note 1h and No. 4 construction project, we were accruing long-term contract retainage amounts for substantial and mechanical milestones. As a result of a settlement agreement entered into by Georgia Power Company and the Co-owners and Toshibaregulatory liabilities in June 2017, these contract retainage amounts were reversed. For more information regarding the Vogtle construction project, see Note 8.members, whichmembers. These contracts extend through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that(dollars in thousands) 2019 2018 Regulatory Assets: Premium and loss on reacquired debt(a) $ 40,067 $ 46,315 Amortization on financing leases(b) 35,433 34,918 Outage costs(c) 34,367 36,352 Asset retirement obligations – Ashpond and other(k) 245,932 137,835 Asset retirement obligations – Nuclear(k) — 7,031 Depreciation expense(d) 39,820 41,244 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(e) 53,466 51,549 Interest rate options cost(f) 121,938 116,960 Deferral of effects on net margin – Smith Energy Facility(g) 154,564 160,509 Other regulatory assets(m) 37,925 22,350 Total Regulatory Assets $ 763,512 $ 655,063 Regulatory Liabilities: Accumulated retirement costs for other obligations(h) $ 12,692 $ 13,873 Deferral of effects on net margin – Hawk Road Energy Facility(g) 18,485 19,101 Major maintenance reserve(i) 50,144 45,547 Amortization on financing leases(b) 14,256 17,156 Deferred debt service adder(j) 114,453 105,192 Asset retirement obligations – Nuclear(k) 61,516 — Revenue deferral plan(l) 90,066 15,670 Other regulatory liabilities(m) 2,629 2,459 Total Regulatory Liabilities $ 364,241 $ 218,998 Net regulatory assets $ 399,271 $ 436,065 (dollars in thousands) 2017 2016 $ 52,989 $ 55,084 33,846 32,274 40,525 39,986 68,289 33,747 42,667 44,091 48,702 43,444 112,102 107,394 166,454 172,399 19,510 16,968 585,084 545,387
$ 12,813 $ 9,829 19,553 20,163 47,087 28,379 20,055 23,084 95,695 86,082 53,571 11,766 2,875 18,445 251,649 197,748 $ 333,435 $ 347,639 2624 years.andversus financial statement purposes related to capitalfinance lease payments and the aggregate of the amortization of the asset and interest on the obligation.to Vogtle Units No. 3costs, including interest and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units.net loss associated with the change in fair value and expired cost ofpremiums paid to purchase interest rate options purchasedused to hedge interest rates on certain borrowings, related tocarrying costs and other incidentals associated with construction of Vogtle Units No.3No. 3 and No.4 construction.No. 4. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loanwhen Vogtle Unit 3 goes in-service, which is financing a portion of the construction project.thedecommissioning costs of decommissioning and ashpond remediation for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for ratemaking purposes.3230 years and the amortization periods of other regulatory liabilities range up to 97 years.ownowned facilities. For 2017, 2016,2019, 2018, and 2015,2017, we incurred expenses from Georgia Transmission of $37,156,000, $30,428,000 and $28,410,000, $27,399,000, and $28,172,000, respectively.2017, 2016,2019, 2018, and 2015,2017, we incurred expenses from Georgia Systems Operations of $26,730,000, $25,578,000, and $25,597,000, $23,994,000, and $22,616,000, respectively. The components ofincome within the Consolidated Statement of Revenues and Expenses were as follows: (dollars in thousands) 2017 2016 2015 $ 1,531 $ 1,679 $ 1,859
6,816
6,553
6,278
(2,056
)
(5,561
)
1,006 $ 6,291 $ 2,671 $ 9,143 NewRecently issued or adopted accounting pronouncementsMay 2014,February 2016, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for us for the annual reporting period beginning after December 15, 2017 using either of the following transition methods: (i) a full retrospective approach reflecting the application ofthe standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). We have completed our evaluation of the new revenue standard and adopted the amendments within the new standard effective January 1, 2018. There was no cumulative impact upon adoption. The adoption of this standard is not expected to have a material impact, on an annual basis, to our revenue recognition based on our existing contracts with customers. Our evaluation process included, but was not limited to, identifying contracts within the scope of Topic 606, reviewing and documenting our accounting for these contracts and assessing the applicability of the variable consideration guidance. The vast majority of our revenue is derived from substantially identical wholesale power contracts that we have with each of our 38 members. We expect the pattern of revenue recognition pursuant to our wholesale power contracts will remain unchanged on an annual basis under the new revenue standard. Historically, our Board has approved budget adjustments, typically at year end but may be made throughout the year, that affect our annual revenue requirement. As a result, at the end of each reporting period we will determine whether the variable consideration cumulatively received from our Members exceeds the consideration to which we expect to be entitled on an annual basis. We will recognize a refund liability for the consideration which we expect to refund to our Members, if such excess consideration received would result in a significant reversal in the cumulative revenues recognized. In January 2016, the FASB issued "Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities." The amendments in this update address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Certain provisions within this update can be adopted early. Certain provisions within this update should be applied by means of a cumulative effect adjustment to the balance sheet of the fiscal year of adoption and certain provisions should be applied prospectively. One of the provisions in this standard requires our equity investments, except those accounted for under the equity method of accounting or those that result in consolidation of our subsidiary, to be measured at fair value with changes in fair value recognized in net income. None of the other provisions in this standard will have any impact to our consolidated financial statements. Effective December 31, 2017, we adopted regulatory accounting treatment with respect to unrealized gains and/or losses on our equity investments. Upon applying regulatory accounting treatment, unrealized gains on our equity investments will be recorded as a regulatory liability and, conversely, unrealized losses on our equity investments will be recorded as a regulatory asset, at the end of each reporting period. As of December 31, 2017, we recorded $618,000 of unrealized losses on our equity investments as a regulatory asset. On January 1, 2018, we adopted the amendments within this standard. The adoption of this standard will have no impact to our consolidated financial statements due to our regulatory accounting treatment for unrealized gains and/or losses on our equity investments. In February 2016, the FASB issued "Leases“Leases (Topic 842)."” The new leases standard requires a dual approach for lessee accounting under which a lessee would accountaccounts for leases as finance leases or operating leases. BothAccounting for both finance leases and operating leases will resultresults in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognizerecognizes interest expense and amortization of the ROU asset and for operating leases the lessee would recognizerecognizes a straight-line total lease expense. Quantitative and qualitative disclosures are required for significant judgments made by management. The new lease standard does not substantially change lessor accounting. TheWe adopted the new leases standard is effective for us on a modified retrospective approach for annual reporting periods beginning after December 15, 2018, and interim periods therein. Early adoption is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements."Financial Instruments – ‘‘Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments."’’ The amendments in this update replace the current incurred loss impairment methodology with a methodology that reflects expected credit losses. The new credit losses standard is effective for us prospectively for annual reporting periods beginning after December 15, 2019, and interim periods therein. The amendments in this update can bestatements. In August 2016,statements, however, we do not anticipate the FASB issued "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments." The amendments in this standard provide specific guidance on eight cash flow classification issues relating to how certain cash receipts and cash payments are presented and classified in the statement of cash flows, thereby reducing the current and potential future diversity in practice. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments shouldimpact will be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. The amendments should be applied using a retrospective transition method to each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. As permitted, on October 1, 2017, we early adopted these amendments and applied their provisions retrospectively. The adoption of this standard had no impact on our consolidated financial statements as the amendments did not change how we present and classify the eight identified cash flow classification issues within our consolidated statement of cash flows. In November 2016, the FASB issued "Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)." The amendments in this standard require the statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows. The new standard is effective for us on a retrospective basis for annual reporting periods beginning after December 15, 2017, and interim periods therein. Early adoption is permitted, including adoption in an interim period. As permitted, on October 1, 2017, we early adopted these amendments and applied their provisions retrospectively. The adoption of this standard had no impact on our consolidated financial statements as we did not have any restricted cash balances in 2017 and 2016. None of our assets or liabilities measured at fair value on a recurring basis were categorized as Level 3 at December 31, 2017 or December 31, 2016. Fair Value Measurements at Reporting Date Using December 31, 2017 Quoted Prices in
Active Markets for
Identical Assets
(Level 1) Significant Other
Observable Inputs
(Level 2) (dollars in thousands) $ 142,419 $ 142,419 $ – $ 88,820 – 88,820 $ 66,317 – 66,317 $ 38,791 38,791 – $ 49,379 – 49,379 $ 47,833 47,833 – $ 92 – 92 $ 3,725 – 3,725 $ 7,679 7,679 – $ 20,071 – 20,071 $ 16,215 – 16,215 $ 6,670 6,670 – $ 7,267 – 7,267 $ 87,011 87,011 – $ 259 – 259 $ 3,129 3,129 – $ 6,328 – 6,328 Fair Value Measurements at Reporting Date Using December 31, 2019 Quoted Prices in
Active Markets for
Identical Assets
(Level 1)Significant Other
Observable Inputs
(Level 2)Significant
Unobservable Inputs
(Level 3)(dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 179,346 $ 179,346 $ — $ — International equity trust $ 96,204 — 96,204 — Corporate bonds and debt $ 63,849 — 63,849 — US Treasury securities $ 45,522 45,522 — — Mortgage backed securities $ 62,400 — 62,400 — Domestic mutual funds $ 55,522 55,522 — — Municipal bonds $ 1,189 — 1,189 — Federal agency securities $ 2,586 — 2,586 — Other $ 4,721 4,450 271 — Long-term investments: International equity trust $ 23,161 — 23,161 — Corporate bonds and debt $ 20,395 — 20,395 — US Treasury securities $ 9,257 9,257 — — Mortgage backed securities $ 12,867 — 12,867 — Domestic mutual funds $ 126,380 126,380 — — Federal agency securities $ 1,082 — 1,082 — Treasury STRIPS $ 59,816 — 59,816 — Other $ 1,906 1,906 — — Natural gas swaps $ 32,256 — 32,256 — Fair Value Measurements at Reporting Date Using December 31, 2018 Quoted Prices in
Active Markets for
Identical Assets
(Level 1)Significant Other
Observable
Inputs
(Level 2)Significant
Unobservable
Inputs
(Level 3)(dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 136,196 $ 136,196 $ — $ — International equity trust $ 76,852 — 76,852 — Corporate bonds and debt $ 51,356 — 48,853 2,503 US Treasury securities $ 47,712 47,712 — — Mortgage backed securities $ 56,004 — 56,004 — Domestic mutual funds $ 43,359 43,359 — — Municipal bonds $ 278 — 278 — Federal agency securities $ 6,066 — 6,066 — Other $ 2,995 2,031 964 — Long-term investments: International equity trust $ 17,382 — 17,382 — Corporate bonds and debt $ 12,571 — 11,366 1,205 US Treasury securities $ 12,062 12,062 — — Mortgage backed securities $ 11,517 — 11,517 — Domestic mutual funds $ 94,494 94,494 — — Federal agency securities $ 941 — 941 — Treasury STRIPS $ 14,113 — 14,113 — Other $ 1,045 1,045 — — Natural gas swaps $ 13,154 — 13,154 — Fair Value Measurements at Reporting Date Using December 31, 2016 Quoted Prices in
Active Markets for
Identical Assets
(Level 1) Significant Other
Observable
Inputs
(Level 2) (dollars in thousands) $ 170,408 $ 170,408 $ – $ 66,861 – 66,861 $ 60,019 – 60,019 $ 34,119 34,119 – $ 41,914 – 41,914 $ 943 – 943 $ 7,102 – 7,102 $ 4,663 4,663 – $ 15,946 – 15,946 $ 11,853 – 11,853 $ 5,909 5,909 – $ 6,844 – 6,844 $ 57,932 57,932 – $ 1,085 – 1,085 $ 305 305 – $ (15,090 ) – (15,090 ) assetmortgage backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no0 unfunded commitments for the international equity trust and redemption may occur daily with a three-day3-day redemption notice period.Year Ended December 31, 2019 (dollars in
thousands)Balance at December 31, 2018 $ 3,708 Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) 94 Liquidations (3,802) Balance at December 31, 2019 $ — Year Ended December 31, 2018 (dollars in
thousands)Balance at December 31, 2017 $ — Transfers to Level 3 4,997 Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) (1,289) Balance at December 31, 2018 $ 3,708 20172019 and 20162018 were as follows (in thousands):2019 2018 Carrying
ValueFair
ValueCarrying
ValueFair
ValueLong-term debt $ 9,726,428 $ 11,180,658 $ 9,347,307 $ 9,837,254 2017 2016 Carrying
Value Fair
Value Carrying
Value Fair
Value $ 8,232,703 $ 9,155,942 $ 8,304,523 $ 9,043,029 estimated based on observed or quoted market prices for the same or similar issues, or based on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. We also have small amounts of long-term debt provided by National Rural Utilities Cooperative Finance Corporation (CFC). The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from a third party data reporting service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of December 31, 2017 and 20162019 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC. and cash equivalents, and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments. As discussed in Note 1m, restrictedRestricted investments consist of funds on deposit with the Rural Utilities Service in theAccount. TheAccount and the carrying amount of these investments approximates fair value because of the liquid nature of the deposits with the U.S. Treasury.risk management and compliance activities, including but not limited to, commodity trading, investment portfolio managementand interest rate risk management. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas.derivative activities. We do not apply hedge accounting for any of these derivatives,to derivative transactions, but instead apply regulatoryregulated operations accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps are reflected as regulatory assets or liabilities, as appropriate.20172019 all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade. Gas hedges.20172019 and 2016,2018, the estimated fair value of our natural gas contracts werewas a net liability of $6,328,000$32,256,000 and a net asset of $15,090,000,$13,154,000, respectively.20172019 and 2016,2018, neither we nor any counterparties were required to post credit support or collateral under the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 20172019 due to our credit rating being downgraded below investment grade, we would have been required to post letters of credit of approximately $6,328,000$32,256,000 with our counterparties.20172019 that is expected to settle or mature each year:Year Natural Gas
Swaps
(MMBTUs)(in millions) 2020 25.1 2021 22.6 2022 15.5 2023 10.5 2024 8.2 Total 81.9 Natural Gas
Swaps
(MMBTUs) (in millions) 27.1 18.9 16.1 13.1 7.9 83.1 Interest rate options. In fourth quarter of 2011, we purchased seventeen LIBOR swaptions at a cost of $100,000,000 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we expected to incur through March 2017 to finance the two additional nuclear units at Plant Vogtle. The last of these options, having a notional value of $80,169,000, expired without value at March 31, 2017. In accordance with rate-making treatment, we deferred the premiums paid to purchase these swaptions and related carrying costs, and will continue to defer other incidentals. The deferral will continue and costs will be amortized and collected in rates from February 2020 through February 2044, corresponding with the life of the associated debt that we hedged with the swaptions.20172019 and 2016. We do not apply hedge accounting to these derivative instruments.Balance Sheet
LocationFair Value 2019 2018 (dollars in thousands) Assets Natural gas swaps Other current assets $ — $ 226 Liabilities Natural gas swaps Other current liabilities $ 12,898 $ 2,066 Natural gas swaps Other deferred credits $ 19,358 $ 11,314 Balance Sheet
Location Fair Value 2017 2016 (dollars in thousands)
Other current assets $ 412 13,833 Other deferred charges $ – 3,289
Other current liabilities $ 1,575 $ 54 Other deferred credits $ 5,165 $ 1,977 2017, 20162019, 2018 and 2015.Consolidated
Statement of
Revenues and
Expenses Location2019 2018 2017 (dollars in thousands) Natural Gas Swaps Fuel $ 224 $ 6,088 $ 3,818 Natural Gas Swaps Fuel (9,308) (956) (1,677) Total $ (9,084) $ 5,132 $ 2,141
Statement of
Revenues and
Expenses Location (dollars in thousands) Fuel $ 3,818 $ 2,445 $ 206 Fuel (1,677 ) (19,697 ) (20,102 ) $ 2,141 $ (17,252 ) $ (19,896 ) gains(gains) and (losses)losses on derivative instruments deferred on the balance sheet at December 31, 20172019 and 2016.Consolidated Balance
Sheet Location2019 2018 (dollars in thousands) Natural Gas Swaps Regulatory asset $ 32,256 $ 13,154 Total $ 32,256 $ 13,154 Consolidated Balance
Sheet Location 2017 2016 (dollars in thousands) Regulatory asset $ (6,328 ) $ (62 ) Regulatory liability – 15,152 Regulatory asset – (5,788 ) $ (6,328 ) $ 9,302 classified as available-for-sale and are carriedrecorded at market value. Prior to October 1, 2017, unrealized gains and losses of investment securities related to nuclear decommissioning were deferred pursuant to regulated operations accounting, while those for all other investment securities were added to or deducted from accumulated other comprehensive (deficit) margin. Duringfair value in the fourth quarter of 2017, we began applyingaccompanying consolidated balance sheets. We apply regulated operations accounting to the unrealized gains and losses of all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. Approximately 75%At December 31, 2019, investments with a fair value of the$22,352,000 were in an unrealized loss position for greater than one year and represented approximately 86% of our gross unrealized losses, while investments with a fair value of $69,567,000 were in effectan unrealized loss position for less than one year. (dollars in thousands) Gross Unrealized Cost Gains Losses Fair Value $ 246,549 $ 91,954 $ (4,064 ) $ 334,439 240,878 1,814 (2,262 ) 240,430 10,807 1 – 10,808 $ 498,234 $ 93,769 $ (6,326 ) $ 585,677 (dollars in thousands) Gross Unrealized Cost Gains Losses Fair Value $ 237,317 $ 51,054 $ (5,041 ) $ 283,330 201,492 1,167 (3,423 ) 199,236 3,339 – (2 ) 3,337 $ 442,148 $ 52,221 $ (8,466 ) $ 485,903 All of the available-for-sale At December 31, 2018, investments are recorded atwith a fair value of $49,975,000 were in the accompanying consolidated balance sheets, therefore the carryingan unrealized loss position for greater than one year and represented approximately 59% of our gross unrealized losses, while investments with a fair value equals the fair value.(dollars in thousands) Gross Unrealized 2019 Cost Gains Losses Fair Value Equity $ 258,870 $ 144,832 $ (5,990) $ 397,712 Debt 354,535 8,474 (874) 362,135 Other 6,356 — — 6,356 Total $ 619,761 $ 153,306 $ (6,864) $ 766,203 (dollars in thousands) Gross Unrealized 2018 Cost Gains Losses Fair Value Equity $ 251,226 $ 64,954 $ (9,105) $ 307,075 Debt 278,030 1,718 (4,955) 274,793 Other 3,075 — — 3,075 Total $ 532,331 $ 66,672 $ (14,060) $ 584,943 available-for-sale, which are included in the estimated fair value table above, at December 31, 20172019 and 20162018 are as follows:(dollars in thousands) 2019 2018 Cost Fair Value Cost Fair Value Due within one year $ 81,637 $ 81,914 $ 65,039 $ 63,925 Due after one year through five years 47,212 48,188 62,293 61,924 Due after five years through ten years 51,892 54,184 50,606 49,855 Due after ten years 173,794 177,849 100,092 99,089 Total $ 354,535 $ 362,135 $ 278,030 $ 274,793 (dollars in thousands) 2017 2016 Cost Fair Value Cost Fair Value $ 54,785 $ 54,143 $ 8,292 $ 8,268 53,050 52,834 52,452 52,054 51,367 51,600 65,657 64,971 81,676 81,853 75,091 73,943 $ 240,878 $ 240,430 $ 201,492 $ 199,236 2017, 20162019, 2018 and 2015:(dollars in thousands) 2019 2018 2017 Gross realized gains $ 18,076 $ 14,268 $ 35,523 Gross realized losses (12,018) (19,139) (16,909) Proceeds from sales 544,043 626,612 521,345 (dollars in thousands) 2017 2016 2015 $ 35,523 $ 19,934 $ 53,453 (16,909 ) (20,030 ) (18,989 ) 521,345 439,540 640,217 20172019 and 2016:(dollars in thousands) 2019 2018 National Rural Utilities Cooperative Finance Corporation (CFC) $ 24,065 $ 24,061 CT Parts, LLC 7,175 10,236 Georgia Transmission Corporation 32,106 30,237 Georgia System Operations Corporation 7,000 9,250 Other 2,972 3,253 Total $ 73,318 $ 77,037 (dollars in thousands) 2017 2016 $ 24,056 $ 24,049 10,243 10,250 28,690 27,285 8,500 7,500 3,492 3,699 $ 74,981 $ 72,783 2022.six6 long-term lease transactions relating to our 74.61% undivided interest in Rocky Mountain. In each transaction, we leased a portion of our undivided interest in Rocky Mountain to six6 separate owner trusts for the benefit of three3 investors, referred to as owner participants, for a term equal to 120% of the estimated useful life of Rocky Mountain. Immediately thereafter, the owner trusts leased their undivided interests in Rocky Mountain to our wholly owned subsidiary, Rocky Mountain Leasing Corporation, or RMLC, for a term of 30 years under six6 separate leases. RMLC then subleased the undivided interests back to us under six6 separate leases for an identical term.five5 of the six6 lease transactions prior to the end of their lease terms. The remaining lease in place represented approximately 10% of the original lease transactions. Pursuant to a payment undertaking agreement, we have a guarantee for the annual basic rent payments due under the remaining lease. The fair value amount relating to the guarantee of basic rent payment is immaterial to us principally due to the high credit rating of the payment undertaker, Rabobank Nederland. The basic rental payments remaining through the end of the lease, which expires in 2027, are approximately $47,882,000.five5 installments in 2027. If we do not elect to cause RMLC to purchase the owner trust's undivided interest in Rocky Mountain, Georgia Power has an option to purchase the undivided interest. If neither we nor Georgia Power exercise our purchase option, and we return (through RMLC) the undividedno0 current period income tax expense or current or deferred income tax liability.2019 2018 2017 Statutory federal income tax rate 21.0 % 21.0 % 35.0 % Patronage exclusion (21.0) % (20.8) % (34.1) % AMT credit monetization 0.0 % 0.0 % 2.2 % Other 0.0 % (0.2) % (0.9) % Effective income tax rate 0.0 % 0.0 % 2.2 % 2017 2016 2015 35.0 % 35.0 % 35.0% (34.1 %) (34.7 %) (34.7%) (2.2 %) 0.0 % 0.0% (0.9 %) (0.3 %) (0.3%) (2.2 %) 0.0 % 0.0% approximate $1,117,000 current tax benefit realized in 2017 as a result of monetizing the remaining balance of alternative minimum tax credits. This benefit is as a result of a refundable credit, and since it is applied after considering the patronage dividend deduction, it is not allocated to our members, but instead is a source of cash to the taxpayer applied against its normal operating expenses. The benefit is shown as a component of production operating expenses on the statement of revenues and expenses.20172019 and 20162018 were as follows: (dollars in thousands) 2017 2016 $ 19,668 $ 29,724 – 599 231,268 349,127 75,013 109,793 325,949 489,243 (19,668 ) (29,724 ) $ 306,281 $ 459,519
$ 271,652 $ 435,570 114,514 170,402 78,407 123,121 464,573 729,093 158,292 269,574 (158,292 ) (269,574 ) $ – $ – (dollars in thousands) 2019 2018 Deferred tax assets Net operating losses $ 1,123 $ 3,830 Tax credits (alternative minimum tax and other) — — Accounting for Rocky Mountain transactions 231,844 231,543 Advance payments 74,482 46,708 Other assets 88,821 82,655 Deferred tax assets 396,270 364,736 Less: Valuation allowance (1,123) (3,830) Net deferred tax assets $ 395,147 $ 360,906 Deferred tax liabilities Depreciation $ 258,724 $ 268,039 Accounting for Rocky Mountain transactions 118,021 116,226 Other liabilities 68,035 75,691 Deferred tax liabilities 444,780 459,956 Net deferred tax liabilities 49,633 99,050 Less: Patronage exclusion (49,633) (99,050) Net deferred taxes $ — $ — 2017,2019, we have federal tax net operating loss carryforwards and alternative minimum tax credits as follows: (dollars in thousands) Alternative
Minimum
Tax Credits NOLs $ – $ 61,533 – 10,516 – 4,362 $ – $ 76,411 The net operating loss expiration dates start in the year 2018 and endof $4,362,000 which expire in the year 2020. Due to the tax basis method for allocating patronage dividends and as shown by the above valuation allowance, it is not more likely than not that the deferred tax asset related to the net operating losses will be realized. On December 18, 2015, the Protecting Americans from Tax Hikes (PATH) Act was signed into law. The PATH Act allowed us to accelerate and monetize AMT credits in lieu of bonus depreciation through the tax year ended December 31, 2019. The remaining credit of $599,000 will be claimed on the tax return filed for the tax year ended December 31, 2017. following its passage by the United States Congress, the President signed into law Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, or the Act. The Act will makemade significant changes to U.S. federal income tax laws. The Act reducesreduced the federal tax rate for corporations from 35% to 21% effective January 1, 2018 and changeschanged or appliesapplied limitations to certain tax deductions. As of December 31, 2017, we have not completed our accounting for the tax effects upon enactment of the Act; however we have been able to make a reasonable estimate of the effects on our existing deferred tax balances. We have remeasured the deferred tax assets and liabilities to reflect the applicable tax rate expected to be in effect when the timing differences reverse, which is 21%. No net impact to the results of operations was recorded as a result of this remeasurment, however the impact to the components of the net deferred tax assets and liabilities is reflected in the above table. We continue to analyze the impact of this tax reform legislation which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts, however we do not believe it will have a material impact on the company's results of operation or cash flows.20142016 and forward. State jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state jurisdictions include 20142016 and forward. We have no liabilities recorded for uncertain tax positions.Capital leases: In 1985,Leases:sold and subsequently leased back from four purchasers theirhave a relatively small portfolio of leases with the most significant being our 60% undivided ownership interest in Scherer Unit No. 2.2 and railcar leases for the transportation of coal. We also have various other leases of minimal value.gainadoption of this standard did not materially impact our consolidated financial statements.the sale is being amortizedshort-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the termslease term. Lease expense recognized for our short-term leases during 2019 and 2018 was insignificant.the leases. The assumed interest rate at inception of the lease in 1985 was 11.05%. Three of theour Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one1 lease extends through June 30, 2031. At the end of the lease,leases, we can elect at our sole discretion to:lessors The minimum lease payments under the capital leases together with the present value of the net minimum lease payments as of December 31, 2017 are as follows: (dollars in
thousands) $ 22,424 14,949 14,949 14,949 7,474 92,905
167,650
(73,292
)
94,358
(7,166
)
$
87,192 The Scherer No. 2 lease is reported as a capital lease. For rate-making purposes, however, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the capital leaseright-of-use asset and the interest on the capitalfinance lease obligation is recognized as a regulatory asset. CapitalFinance lease amortization is recorded in depreciation and amortization expense.Classification 2019 2018 (dollars in thousands) Right-of-Use Assets - Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation $ (257,504) $ (252,233) Total finance lease assets $ 45,228 $ 50,499 Lease liabilities - Finance leases Obligations under finance leases $ 75,649 $ 81,730 Long-term debt and finance leases due within one year $ 6,081 $ 5,461 Total finance lease liabilities $ 81,730 $ 87,191 Classification 2019 2018 (dollars in thousands) Right-of-Use Assets - Operating leases Electric plant in service $ 3,237 $ — Total operating lease assets $ 3,237 $ — Lease liabilities - Operating leases Capitalization - Other $ 2,293 $ — Other current liabilities $ 1,252 — Total operating lease liabilities $ 3,545 $ — 2019 2018 (dollars in thousands) Lease Cost Classification Finance lease cost: Amortization of leased assets Depreciation and amortization $ 4,756 $ 4,199 Interest on lease liabilities Interest expense $ 9,488 $ 10,045 Operating lease cost Inventory(1) & production expense $ 3,179 $ 4,562 Total lease cost $ 17,423 $ 18,806 December 31, 2019 December 31, 2018 Lease Term and Discount Rate Weighted-average remaining lease term (in years): Finance leases 8.84 9.82 Operating leases 7.39 n/a Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 5.12 % n/a 2019 2018 (dollars in thousands) Other Information Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from finance leases $ 9,488 $ 15,258 Operating cash flows from operating leases $ 3,710 $ — Financing cash flows from finance leases $ 5,461 $ 7,166 Right-of-use assets obtained in exchange for new operating lease liabilities $ 6,983 $ — (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2020 $ 14,949 $ 1,399 $ 16,348 2021 $ 14,949 $ 795 $ 15,744 2022 $ 14,949 $ 605 $ 15,554 2023 $ 14,949 $ 384 $ 15,333 2024 $ 14,949 $ 72 $ 15,021 Thereafter $ 55,532 $ 1,085 $ 56,617 Total lease payments $ 130,277 $ 4,340 $ 134,617 Less: imputed interest $ (48,547) $ (795) $ (49,342) Present value of lease liabilities $ 81,730 $ 3,545 $ 85,275 2019 2018 Lease income $ 6,071 $ 4,969 capitalfinance lease obligations through 20222024 are as follows:(dollars in thousands) 2020 2021 2022 2023 2024 FFB $ 209,958 $ 216,652 $ 221,761 $ 229,530 $ 203,452 FMBs 1,010 1,010 1,010 1,010 63,510 — — — — 368,225 CFC 391 — — — — $ 211,359 $ 217,662 $ 222,771 $ 230,540 $ 635,187 Finance Leases 6,081 6,772 7,541 8,398 9,351 Total $ 217,440 $ 224,434 $ 230,312 $ 238,938 $ 644,538 (dollars in thousands) 2018 2019 2020 2021 2022 $ 188,857 $ 157,105 $ 172,189 $ 177,383 $ 180,754 1,010 351,010 1,010 1,010 1,010 18,677 37,352 170,902 18,676 – 984 1,035 391 – – $ 209,528 $ 546,502 $ 344,492 $ 197,069 $ 181,764 7,166 5,462 6,082 6,722 7,541 $ 216,694 $ 551,964 $ 350,574 $ 203,791 $ 189,305
2038 and the Series 2017 bonds totaling $122.6 million have a mandatory redemption in 2023 if the bonds are not remarketed before then, with nominal maturities in 2040 and 2045.on the bonds, this includesincluded are amounts that would be due ifat the standby letterslater of (i) maturity date of the credit supportingsupport facilities backing the Series 2009 and Series 2010 pollution control bonds, were drawn uponor at the mandatory redemption date of the Series 2017A and became payable in accordance with their terms, such as would occur ifSeries 2017B pollution control bonds or (ii) at the maturity of an alternative back-up credit facility we currently have available to refinance draws on the credit facilities. We currently maintain a $1.21 billion syndicated bank credit facility with a maturity date of December 2024 which backs the lettersSeries 2010 pollution control bonds and would be available as an alternative back-up credit facility for the Series 2009 and Series 2017 pollution control bonds noted above. As such, December 2024 is the designated maturity date for all of credit were issued under was not renewed or extended at its expiration date. These amounts equal $18.7 million in 2018, $37.4 million in 2019, $170.9 million in 2020 and $18.7 million in 2021. We anticipate extending these credit facilities before their expiration.pollution control bonds totaling $368.2 million. The nominal maturities of the Series 2009 and Series 2010 pollution control bonds range from 2030 through 2038.20172019 and 20162018 was 4.17%3.96% and 4.34%4.24%, respectively.20172019 and 2016December 31, 2018 are as follows:2019 2018 Principal Unamortized Debt
Issuance Costs
and
Debt DiscountsPrincipal Unamortized Debt
Issuance Costs
and
Debt Discounts(dollars in thousands) FFB $ 5,540,215 $ 60,356 $ 4,372,422 $ 50,210 FMBs 3,205,052 39,793 3,556,062 41,509 PCRBs 980,770 11,073 980,770 11,612 CFC 391 — 1,426 — $ 9,726,428 $ 111,222 $ 8,910,680 $ 103,331 2017 2016 Principal Unamortized Debt
Issuance Costs
and
Debt Discounts Principal Unamortized Debt
Issuance Costs
and
Debt Discounts (dollars in thousands) $ 4,192,450 $ 51,593 $ 4,259,723 $ 55,754 3,057,072 34,673 3,058,083 36,717 980,770 9,347 980,770 8,789 2,411 – 3,347 – – – 2,600 – $ 8,232,703 $ 95,613 $ 8,304,523 $ 101,260 (the Title XVII Loan Guarantee Program), we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 (as amended, the Loan Guarantee Agreement) pursuant to which thethea Note Purchase Agreement, dated as of February 20, 2014 (the Original Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two2 future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Credit Facility Documents). TheCredit FacilityNote and together with the Additional Note Purchase Agreement, the Additional FFB Documents)., under which we may make long-term loan borrowings through the Federal Financing Bank.will beare used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program. Aggregate borrowingsloan guarantee program (Eligible Project Costs). Borrowings under the FacilityOriginal FFB Notes may not exceed $3,057,069,461, of which $335,471,604 is designated for capitalized interest.the Department of Energyit is required to make any payments to the Federal Financing Bank under theits guarantee. Our payment obligations to the Federal Financing Bank under the FFB Notes and reimbursement obligations to the Department of Energy under its guarantee, but not our covenants to the Department of Energy under the Loan Guarantee Agreement, are secured equally and ratably with all of our other notes and obligations issued under our first mortgage indenture. The final maturity date for each advance is February 20, 2044. Interest is payable quarterly in arrears and principal payments will beginon all advances under the FFB Notes began on February 20, 2020. Under both FFB Notes, the interestInterest rates on advances during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%. At December 31, 2017, aggregate Department of Energy-guaranteed borrowings totaled $1,735,586,000, including capitalized interest. Pursuant toamended terms of the Loan Guarantee Agreement, we are restricted from receiving further advances until certain conditions are met, including Department of Energy approval of the Bechtel Agreement (as defined inAdditional FFB Note 8) and the Department of Energy and we enter into an amendment to the Loan Guarantee Agreement to incorporate provisions relating to the Bechtel Agreement and other replacement agreements. While not assured, we expect to satisfy these conditions in the second quarter of 2018. When these conditions are satisfied, advances may be requested under the Facility on a quarterly basis through December 31, 2020. In addition toNovember 30, 2023, one year beyond the conditions described above, futurecurrent anticipated commercial operation date of Vogtle Unit No. 4.includingas well as (i) certification of compliance with the requirements of the Title XVII Loan Guarantee Program,loan guarantee program, (ii) accuracy of project-related representations and warranties, (iii) delivery of updated project-related information, our continued(iv) no Project Adverse Event (as described in Note 8) having occurred or, if a Project Adverse Event has occurred, that Co-owners (as described in Note 8) representing at least 90% of the ownership interests have voted to continue construction, have not deferred construction and we have provided the Department of our interest in Vogtle Units No. 3 and No. 4 free and clear of any liens except those permitted underEnergy with certain additional information, (v) certification regarding Georgia Power's compliance with certain obligations relating to the Loan Guarantee Agreement,Cargo Preference Act, as amended, (vi) evidence of compliance with the prevailingapplicable wage requirements of the Davis-Bacon Act, as amended, and(vii) certification from the Department of Energy's consulting engineer that proceeds of the advance are used to reimburse eligible project costs. Under the Loan Guarantee Agreement, upon the occurrence ofEnergy may require usEnergy's option the Federal Financing Bank's commitment to prepaymake further advances under the Facility will terminate and we will be required to repay the outstanding principal amount of all guaranteed borrowings under the Facility over a period of five years, with level principal amortization. These events include (i) abandonment of the Vogtle Units No. 3 and No. 4 project, including a decision by Georgia Power to cancel the project, (ii) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (ii)(iii) termination of the Services Agreement as defined in Note 8 or rejection of the Services Agreement in bankruptcy, if Georgia Power does not maintain access to certain related intellectual property rights, (iii) a decision(iv) termination of the Services Agreement by us notcontinuethe Department of Energy of their intent to cancel construction of Vogtle Units No. 3 and No. 4 (iv)coupled with termination by the Co-owners of the Services Agreement or the Bechtel Agreement, (vi) failure of the Co-owners to enter into a replacement contract with respect to the Services Agreement or the Bechtel Agreement following the Co-owners' termination of such agreement with the intent to replace it, (vii) the Department of Energy's takeover of construction of Vogtle Units No. 3 and No. 4 under certain conditions, (viii) the occurrence of any Project Adverse Event that results in a cancellation of the Vogtle Units No. 3 and No. 4 project or the cessation or deferral of construction beyond the periods permitted under the Amended Loan Guarantee Amendment, (ix) loss of or failure to receive necessary regulatory approvals under certain circumstances, (v)(x) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (vi)(xi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (vii)(xii) change of control of Oglethorpe and (viii)(xiii) certain events of loss or condemnation. We may also voluntarily prepay outstanding borrowings under the Facility. Under the FFB Credit Facility Documents, any prepayment will be subject to a make-whole premium or discount, as applicable. On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to approximately $1,620,000,000 of additional guaranteed funding under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. Final approval and issuance of this additional loan guarantee by the Department of Energy cannot be assured and is subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions.2017,2019, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $22,098,000$115,353,000 for long-term financing of general and environmental improvements at existing plants.2018,2020, we received an additional $2,636,000$18,318,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants.Pollution Control Revenue Bonds: On October 12, 2017, the Development Authority of Burke County (Georgia), the Development Authority of Heard County (Georgia) and the Development Authority of Monroe County (Georgia) issued, on our behalf, $122,620,000 (Series 2017A Burke, Heard and Monroe and 2017B Burke) in aggregate principal amount of tax-exempt pollution control revenue bonds to refinance costs associated with certain of our pollution control facilities. The bonds were directly purchased by a bank and the proceeds were used to repay outstanding commercial paper issued to redeem certain auction rate pollution control revenue bonds in January 2017. Each series of bonds bears interest at an indexed variable rate until October 3, 2022, the initial mandatory tender date. Bonds that are not remarketed by the initial mandatory tender date will be returned to the holders thereof and will be subject to mandatory redemption on October 2, 2023. These pollution control revenue bonds are scheduled to mature in 2040 through 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture. On December 28, 2017, the Development Authority of Burke County (Georgia) issued, on our behalf, $399,785,000 (Series 2017C, D, E, F Burke) in aggregate principal amount of tax-exempt pollution control revenue bonds to refinance costs associated with certain of our pollution control facilities. The bonds were directly purchased by two banks and the proceeds defeased our obligations under $399,785,000 of pollution control revenue bonds issued in 2008 that were callable on or after January 1, 2018. Those 2008 bonds were fully redeemed on their call date. Each series of the 2017 bonds bore interest at an indexed variable rate until February 1, 2018 when we converted the bonds into fixed interest rate modes. We converted the (i) $200,000,000 Series 2017C and Series 2017D bonds to a fixed rate of 4.125% per annum to maturity with an optional call at par on February 1, 2028, (ii) $100,000,000 Series 2017E bonds to a fixed term rate of 3.25% per annum to the mandatory tender date of February 3, 2025 and (iii) $99,785,000 Series 2017F bonds to a fixed term rate of 3.00% per annum to the mandatory tender date of February 1, 2023. The Series 2017C, D, E, F bonds are scheduled to mature in 2041 through 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture.
Credit Facilities:d)2017,2019, we had a total of $1,610,000,000 of committed credit arrangements comprised of four4 separate facilities with maturity dates that range from October 20182021 to March 2020.December 2024. These credit facilities are for general working capital purposes, issuing letters of credit and backing up outstanding commercial paper. Under our unsecured committed lines of credit that we had in place at December 31, 2017,2019, we had the ability to issue letters of credit totaling $760,000,000 in the aggregate, of which $509,000,000 remained available. At December 31, 2017,2019, we had 1) $251,000,000(i) $252,000,000 under these lines of credit in the form of issued letters of credit supporting variable rate demand bonds and collateral postings to third parties, and 2) $191,000,000(ii) $282,370,000 dedicated under one of these lines of credit to support a like amount of commercial paper that was outstanding.20172019 and December 31, 20162018 was 1.58%2.12% and 0.93%2.98%, respectively.20172019 and 20162018 is as follows:2019 2018 (dollars in thousands) Plant Investment Accumulated
DepreciationInvestment Accumulated
DepreciationOwned property $ 2,989,693 $ (1,815,258) $ 2,975,727 $ (1,775,569) 56,991 (4,956) 55,861 (3,479) 934,567 (462,063) 910,259 (441,240) 749,971 (360,014) 655,618 (311,606) 1,284,508 (545,908) 1,222,538 (442,840) 137,513 (113,259) 137,133 (109,509) 618,939 (270,058) 618,621 (258,359) 226,316 (110,008) 226,156 (105,540) 260,494 (67,065) 254,925 (75,308) 294,809 (144,847) 293,638 (136,007) 317,210 (150,805) 315,463 (141,279) 655,106 (195,638) 648,464 (179,486) 3,887 (3,738) 3,887 (3,626) Transmission plant 96,198 (59,096) 95,861 (56,973) Other 96,522 (57,826) 93,503 (56,193) Property under capital lease: 789,991 (472,486) 776,316 (447,391) Total in-service $ 9,512,715 $ (4,833,025) $ 9,283,970 $ (4,544,405) Construction work in progress Vogtle Units No. 3 & No. 4 $ 4,617,654 $ 3,600,631 Environmental and other
generation improvements198,357 263,146 Other 885 2,265 Total construction work in progress $ 4,816,896 $ 3,866,042 2017 2016 (dollars in thousands) Investment Accumulated
Depreciation Investment Accumulated
Depreciation
(Nuclear – 30% ownership) $ 2,916,852 $ (1,751,558 ) $ 2,885,559 $ (1,712,642 )
(Nuclear – 30% ownership) 36,745 (2,514 ) 36,163 (1,567 )
(Nuclear – 30% ownership) 824,890 (420,000 ) 809,971 (407,400 )
(Fossil – 30% ownership) 587,436 (236,155 ) 577,781 (190,974 )
(Fossil – 60% ownership) 1,102,085 (399,774 ) 1,083,772 (368,948 ) 136,351 (106,370 ) 135,849 (102,642 )
(Hydro – 75% ownership) 609,048 (246,758 ) 607,742 (234,765 ) 225,808 (104,269 ) 227,878 (104,342 ) 251,671 (73,998 ) 250,595 (69,984 ) 292,250 (128,344 ) 290,790 (119,874 ) 313,587 (133,378 ) 313,693 (123,946 ) 642,732 (170,366 ) 614,453 (176,701 ) 3,887 (3,552 ) 3,582 (3,569 ) 92,929 (55,502 ) 92,085 (53,251 ) 92,179 (54,927 ) 99,644 (61,356 )
757,957 (414,867 ) 757,282 (383,378 )
$
8,886,407
$
(4,302,332
)
$
8,786,839
$
(4,115,339
)
$ 2,721,949 $ 3,069,476 212,476 158,181 1,443 557
$
2,935,868
$
3,228,214 �� 20172019 and 20162018 of $197,000,000.(2)The 2017 amount is net of a $1,104,000,000 credit recorded as a result of payments received from Toshiba under the Guarantee Settlement Agreement as described in Note 8b.two2 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.two2 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle. Under the terms of the EPC Agreement, the Co-owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments. Toshiba Corporation guaranteed certain payment obligations of Westinghouse under the EPC Agreement (the Toshiba Guarantee), including any liability of Westinghouse for abandonment of work. On In March 29, 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. In connection with the bankruptcy filing, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with Westinghouse and WECTEC Staffing Services LLC to provide for a continuation of work at Vogtle Units No. 3 and No. 4. The Interim Assessment Agreement expired onEffective in July 27, 2017, upon the effective date of the Services Agreement discussed below. Subsequent to Westinghouse's bankruptcy filing, a number of subcontractors to Westinghouse alleged non-payment by Westinghouse for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken actions to remove liens on the site filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against Westinghouse and the Co-owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and payment of other Westinghouse pre-petition accounts payable have been paid or accrued as of December 31, 2017. On June 9, 2017, Georgia Power and the other Co-owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (the Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee was $3,680,000,000 (the Guarantee Obligations), of which our proportionate share was $1,104,000,000. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, the Co-owners, certain affiliates of the Municipal Electric Authority of Georgia, and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (the Settlement Agreement Amendment). The Settlement Agreement Amendment provided that Toshiba's remaining scheduled payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of the Co-owners and certain affiliates of the Municipal Electric Authority of Georgia against Westinghouse, and the Co-owners surrendered certain letters of credit securing a portion of Westinghouse's potential obligations under the EPC Agreement. Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement which was amended and restated on July 20, 2017 (the Services Agreement), forpursuant to which Westinghouse to transition construction management of Vogtle Units No. 3is providing facility design and No. 4 to Southern Nuclearengineering services, procurement and to provide ongoing design, engineering,technical support and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved Westinghouse's motion seeking authorization to (i) enter into the Services Agreement, (ii) assumestaff augmentation on a time and assign to the Co-owners certain project-related contracts, (iii) join the Co-owners as counterparties to certain assumed project-related contracts, and (iv) reject the EPC Agreement.materials cost basis. The Services Agreement and Westinghouse's rejection of the EPC Agreement, became effective upon approval by the Department of Energy on July 27, 2017. The Services Agreementprovides that it will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days'days’ written notice. Effective 23, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, wherebypursuant to which Bechtel will serveserves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). Facility design and engineering remains the responsibility of Westinghouse under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will beis reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel'sBechtel’s performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts Pursuant to the loan guarantee agreement between usthe Department of Energy, we are required to obtain the Department of Energy's approval of the Bechtel Agreement and further amend the loan guarantee agreement to incorporate provisions relating to the Bechtel Agreement and other replacement agreements prior to receiving any further advances. On November 2, 2017, the Co-owners entered into an amendment to their jointScheduleagreements for Vogtle Units No. 3 and No. 4 (as amended, the Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. 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 if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power 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 because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in Georgia Power's seventeenth Vogtle construction monitoring (VCM) report of more than $1,000,000,000 or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Joint Ownership Agreements, the required approval of holders of ownership interestsinterest 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. On December 21, 2017, the Georgia Public Service Commission took a series of actions related to the construction of Vogtle Units No. 3 and No. 4 and issued its related order on January 11, 2018. Among other actions, the Public Service Commission (i) accepted Georgia Power's recommendation that construction of Vogtle Units No. 3 and No. 4 be completed, with Southern Nuclear Operating Company, Inc. serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Public Service Commission reserve the right to reconsider the decision to continue construction. Parties have filed two petitions with the Fulton County Superior Court appealing the Georgia Public Service Commission's January 11, 2018 order. Georgia Power has stated that it believes these appeals have no merit; however, an adverse outcome in one or both of these appeals could have a material impact on our financial condition and results of operations. We expect Vogtle Units No. 3 and No. 4 to be placed in service by November 2021 and November 2022, respectively. Our project budget for the additional Vogtle units is $7$7.5 billion, which includes capital costs, allowance for funds used during construction, our allocation of the project-level contingency and a contingency amount. This budget is net of the $1,104,000,000 of payments we received from Toshiba under the Guarantee Settlement Agreement.separate Oglethorpe-level contingency. As of December 31, 2017,2019, our total investment in the additional Vogtle units was $2,938,000,000, netapproximately $4.9 billion.payments received from Toshiba underproject. The project-level contingency is separate and in addition to our Oglethorpe-level contingency.Guarantee Settlement Agreement. The payments from Toshiba were recordedareas of commodity installation, system turnovers and workforce statistics.reductionstrategy to maintain margin to the constructionregulatory-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 progress balance fora backlog of activities and completion percentages below the additional Vogtle units.eventprojected overall capital cost forecast and confirmed the Vogtle project is cancelled, our proportionate shareregulatory-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 Co-owners' cancellation costs are estimatedregulatory-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 be approximately $230,000,000. Ifbelieve 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.is cancelled, we would seek regulatory accounting treatmentmilestones to amortize our investmentalign 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 Vogtle project over a long-term period which would require the approvalregulatory-approved in-service dates of our board of directorsNovember 2021 and the Rural Utilities Service.construction-related challenges includingwith management of contractors subcontractors, and vendors,vendors; subcontractor performance; supervision of craft labor and related craft labor productivity, particularly in the installation of electrical and availability,mechanical commodities, ability to attract and retain craft labor and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and installationthe initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structuresTable or components (some of Contentsand components,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. AspectsWestinghouse AP1000 designconstruction site, including limiting exposure of individuals who are basedshowing 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 new technologies and commercial operation of this design has yet to be tested.resolutionsubmittal by Southern Nuclear of inspections, tests, analyses, and acceptance criteriadocumentation 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.$1,371,000in 2019, 2018 and $1,310,000 in 2017, 2016 and 2015, respectively.Prior to 2016, the effective rate of the employer retirement contribution was 8%. Our contributions to the employer retirement contribution feature of the 401(k) plan were approximately $4,172,000, $3,903,000 and $3,791,000 $3,678,000in 2019, 2018 and $2,611,0002017, respectively.2017, 20162019 and 2015,2018, respectively.$13,400,000,000.$13.9 billion. This amount is covered by private insurance and a mandatory program of deferred premiums that could be assessed against all owners of nuclear power reactors. Such private insurance provided by American Nuclear Insurers (ANI), is carried by Georgia Power for the benefit of all the co-owners of Plants Hatch and Vogtle. Agreements of indemnity have been entered into by and between each of the co-owners and the NRC. In the event of a nuclear incident involving any commercial nuclear facility in the country involving total public liability in excess of $450,000,000$450 million, a licensee of a nuclear power plant could be assessed a deferred premium of up to $127,000,000$138 million per incident for each licensed reactor operated by it, but not more than $19,000,000$20 million per reactor per incident to be paid in a calendar year. On the basis of our ownership interest in four4 nuclear reactors, we could be assessed a maximum of $153,000,000$165 million per incident, but not more than $23,000,000$25 million in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five5 years, and exclude any applicable state premium taxes. The next scheduled adjustment is due no later than September 10, 2018.$1,500,000,000$1.5 billion for members' operating nuclear generating facilities. Additionally, there is coverage through NEIL for decontamination, excess property insurance, and premature decommissioning coverage up to $1,250,000,000$1.25 billion for nuclear losses in excess of the $1,500,000,000 primary coverage. On April 1, 2014, NEIL introduced a new excessand non-nuclear policypolicies providing coverage up to $750,000,000$750 million for non-nuclear losses in excess of the $1,500,000,000$1.5 billion primary coverage.$2,750,000,000$2.75 billion in limits for accidental property damage occurring during construction.$40,000,000.subject(subject to normal policy limits.limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3,200,000,000$3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.a. Operating leases As of December 31, 2017, our estimated minimum rentalfor our railcar leases for use at our coal-fired facilities over the next five yearsto meet fuel, transportation, maintenance and thereafter are as follows: (dollars in thousands) $ 5,277 2,923 583 – These railcar leasing costs are added to the cost of the fossil inventories and are recognized in fuel expense. Rental expenses totaled $4,919,000, $4,456,000 and $4,849,000 in 2017, 2016 and 2015, respectively. We are assessing our future railcar needs and evaluating our leasing options.b. Fuel and Georgia Power, on our behalf for coal, have entered into various long-term commitments for the procurement of coal and nuclear fuel. The contracts in most cases contain provision for price escalations, minimum and maximum purchase levels and other financial commitments. The value of the coal commitments is based on maximum coal prices and minimum volumes as provided in the contracts and does not include taxes, transportation, government impositions or railcar costs. For further discussion of total nuclear fuel expense, see Note 1g. On April 11, 2014, we signed a precedent agreementTranscontinental Gas Pipeline Company, LLC (Transco) for additionalvarious counterparties to provide firm natural gas transportation to our Smith facility.natural gas-fired facilities. The newvalue of these agreements is based on fixed rates as provided in the contracts and does not include variable costs.gas pipeline by Transco was placed into servicegas-fired facilities. In most cases, these agreements include provisions for price escalation and performance bonuses and, if applicable, are included in August 2017. Total fixed chargesthe values; timing of expenditures is based on current operational assumptions. Certain agreements contain significant cancellation for convenience penalties and, therefore, amounts in the table below include total estimated expenditures over the 25-year base term willlife of the agreement. If these agreements were terminated by us in 2020 for convenience, our cancellation obligation would be approximately $942,500,000.2017,2019, our estimated minimum long-term commitments are as follows:(dollars in thousands) Coal Nuclear Fuel Gas
TransportationMaintenance
AgreementsAsset
Retirement
ObligationsFinance and Operating Leases 2020 $ 13,019 $ 55,300 $ 63,985 $ 53,911 $ 6,623 $ 16,348 2021 5,231 36,200 63,444 14,461 19,206 15,744 2022 2,524 31,200 53,643 14,929 33,742 15,554 2023 — 18,400 49,044 3,330 32,932 15,333 2024 — 20,800 46,686 29,750 42,504 15,021 Thereafter — 14,300 798,660 218,456 3,453,280 56,617 (dollars in thousands) Coal Nuclear Fuel Gas
Transportation $ 14,809 $ 56,500 $ 66,905 7,526 32,500 60,854 4,598 25,300 57,530 – 30,900 57,481 – 26,300 48,515 – 39,600 776,587 dioxide, for certain new and modified facilities. In general, these and other types of environmental requirements are becoming increasingly stringent. dioxide. At this time, thenew and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs.20172019 and 20162018 is as follows:First
QuarterSecond
QuarterThird
QuarterFourth
Quarter(dollars in thousands) 2019 Operating revenues $ 356,600 $ 358,860 $ 382,623 $ 332,209 Operating margin 66,032 51,712 59,209 40,256 Net margin 23,596 9,383 18,286 3,196 2018 Operating revenues $ 373,646 $ 365,921 $ 384,644 $ 355,902 Operating margin 69,931 60,849 54,845 39,351 Net margin 27,400 17,285 11,334 (4,820) First
Quarter Second
Quarter Third
Quarter Fourth
Quarter (dollars in thousands) $ 354,170 $ 367,119 $ 385,906 $ 327,001 69,330 69,222 68,770 31,548 21,454 21,426 20,805 (12,408 )
$ 348,161 $ 379,343 $ 431,013 $ 348,714 71,093 74,148 70,929 39,494 20,598 23,277 18,630 (12,160 ) 2017 and 20162018 were due to reductions to revenue requirements in order to achieve, but not exceed, the targeted margins for interest ratio of 1.14.20172019 and 2016, and2018, the related consolidated statements of revenues and expenses, comprehensive margin, patronage capital and membership fees and accumulated other comprehensive (deficit) margin (deficit) and cash flows for each of the three years in the period ended December 31, 2017,2019, and the related notes (collectively referred to as the "consolidated“consolidated financial statements"statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 20172019 and 2016,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2019, in conformity with U.S. generally accepted accounting principles.Company'sCompany’s management. Our responsibility is to express an opinion on the Company'sCompany’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.Company'sCompany’s internal control over financial reporting. Accordingly, we express no such opinion./s/ Ernst & Young LLPCompany'sCompany’s auditor since 2010.29, 201820, 202020172019 in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information we are required to disclose in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.20172019 in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.2017,2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.that.the new candidate. Should that candidate also fail to receive a majority vote, this nomination and election process would be repeated until a nominated candidate is elected by a majority of the members. NameAgePosition Executive Officers:NameAge Position Executive Officers: Michael L. Smith 60 58President and Chief Executive Officer Michael W. Price 59 57Executive Vice President and Chief Operating Officer Elizabeth B. Higgins 51 49Executive Vice President and Chief Financial Officer William F. Ussery 55 53Executive Vice President, Member and External Relations Annalisa M. Bloodworth 41 39Senior Vice President and General Counsel Lori K. Holt 58 56Senior Vice President, Fuels & Co-owned Assets James A. Messersmith 67 63Senior Vice President, Plant Operations Keith D. Russell 58 56Senior Vice President, Capital Projects and Technical Services Heather Teilhet 44 Senior Vice President, External Affairs Jami G. Reusch 57 55Vice President, Human Resources Heather Teilhet42Vice President, Governmental Affairs
Directors:Bobby C. Smith, Jr. 66 64Chairman and At-Large Director Marshall S. Millwood 70 68Vice-Chairman and At-LargeMember Group Director (Group 3)Jimmy G. Bailey 71 69At-Large Director George L. Weaver 72 70Member Group Director (Group 1) James I. White 74 72Member Group Director (Group 1) Danny L. Nichols 55 53Member Group Director (Group 2) Sammy G. Simonton 78 76Member Group Director (Group 2) Randy Crenshaw 67 65Member Group Director (Group 3) M. Anthony Ham66Member Group Director (Group 3)Fred A. McWhorter 73 71Member Group Director (Group 4) Jeffrey W. Murphy 56 54Member Group Director (Group 4) Ernest A. "Chip" Jakins III 50 48Member Group Director (Group 5) Wm. Ronald Duffey 78 76Outside Director hashave entered into an employment contract with us that provides for minimum annual base salary and performance pay. See "EXECUTIVE COMPENSATION – Compensation Discussion and Analysis – Employment Agreements" for further discussion of these agreements.has aholds several Senior Professional certificates in Human Resources certification.Heather H. Teilhet is our Vice President, Governmental Affairs and has served in that capacity since January 2017. Prior to joining us, Ms. Teilhet served as Vice President of Government Relations for Georgia Electric Membership Corporation from 2010 to 2016, where she represented Georgia's 41 electric cooperatives before the Georgia General Assembly, the U.S. Congress and certain regulatory agencies. Prior to joining Georgia EMC, she served as a senior staff member for Georgia Governor Sonny Perdue and as a staff member for Georgia Governor Roy Barnes. Ms. Teilhet graduated from the University of Georgia and holds a Masters in Public Administration from Georgia State University.2019.2022. Mr. Bailey is a member of the compensation committee and the construction project committee. Mr. Bailey is a director of Diverse Power Incorporated, an EMC. Mr. Bailey has owned and operated a construction contracting business since 1970.from 1970 to 2018. He also serves as Chairman of Kudzu Networks Inc., a subsidiary of Diverse Power, and iswas President of the Georgia Directors Association.2019.2022. He is a member of the compensationaudit committee. Mr. Crenshaw is President and Chief Executive Officer of Irwin Electric Membership Corporation and Middle Georgia Electric Membership Corporation. Mr. Crenshaw also serves on the board of directors for Georgia Electric Membership Corporation, where heGreen Power EMC and Smarr EMC and is the Secretary-Treasurer and on the executive committee, and the Georgia Cooperative Council, where he serves as Chairman. He is also onchairman of the board of directors for Green Power EMC, Smarr EMC and GRESCO Utility Supply, Inc andInc. He is a former member of the Georgia Systems Operations board of directors and former chairman of the Georgia Cooperative Council board of directors. He is also past President of the Irwin/Ocilla Chamber of Commerce and a member of the Irwin Development Board.Vice Chair of the board of directors of Piedmont Healthcare, where he is also serves on the Executive Committee, Executive Performance and Compensation Committee and Governance and Nominating Committee. Mr. Duffey is also a former member of the board of directors of the Georgia Chamber of Commerce.M. Anthony Ham is a member group director (group 3). Mr. Ham has served on ourCommerce board of directors since March 2004, and his present term will expire in March 2020. He is a memberdirectors.Workers Compensation Fund Executive Committee, and for Green Power EMC. He is also a member of the Georgia Chamber of Commerce.2019.2022. He is a member of the compensation committee and the construction project committee. Mr. McWhorter serves as Chairman of the Rayle Electric Membership Corporation board of directors. Mr. McWhorter also serves on the board of directors for Georgia Electric Cooperative. He is the owner of F.A. McWhorter Poultry Farms.an at-large director.a member group director (group 3). Mr. Millwood has served on our board of directors since March 2003, and his present term will expire in March 2021.2020. He is the chairman of the compensation committee and a member of the construction project committee. He has been the owner and operator of Marjomil Inc., a poultry and cattle farm in Forsyth County, Georgia, since 1998. He is a director of Sawnee Electric Membership Corporation.compensationaudit committee. Mr. Simonton is a director of Walton Electric Membership Corporation. Mr. Simonton is currently the owner of Simonton Farms and has previous business affiliations with Meridian Homes, Moreland Altobelli Associates, Inc. and the Georgia Department of Transportation.2019.2022. He is a member of the audit committee. Mr. Weaver has been employed by Central Georgia Electric Membership Corporation since 1970 and is currently serving as President and Chief Executive Officer. Mr. Weaver is currently a director of Southeastern Data Cooperative and is a former director of Federated Rural Electric Insurance Corporation.Randy Crenshaw, Anthony Ham,Jimmy Bailey, Chip Jakins, Fred McWhorter and Danny Nichols and Sammy Simonton.Fred McWhorter.Marshall Millwood. Mr. Nichols is the chairman of the construction project committee.i)(i) significant compliance issues, ii)(ii) significant audits/examinations by governmental or other regulatory agencies, and iii)(iii) significant regulatory proceedings. The risk management and compliance committee, comprised of our chief executive officer, chief operating officer, chief financial officer, and the executive vice president of member and external relations, provides general oversight over all of our risk management and compliance activities, including but not limited to commodity trading, fuels management, insurance procurement, debt management, investment portfolio management, environmental and electric reliability compliance and cyber-security. The risk management and compliance committee has implemented comprehensive policies and procedures, consistent with current board policies, which govern our activities pertaining to market, compliance/regulatory and other risks. For further discussion about our risk management and compliance committee and its activities, see "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK."20172019 for our executive officers should be comprised of the following three primary components:2017,2019, we contributed an additional amount equal to 11% of an executive officer's pay per period. See "– Nonqualified Deferred Compensation" below for additional information regarding our contributions to our executive officers' retirement plans.2017,2019, our performance measures were divided into the following categories: i)(i) safety, ii)(ii) operations, iii)(iii) construction and project management, iv)(iv) corporate compliance, v)(v) financial and vi)(vi) quality. Targeted performance measures in these categories are designed to help us accomplish our corporate goals which will benefit our members, employees and promote responsible environmental stewardship.For example, in 2017, we added a new safety goal to enhance our lockout-tagout procedures. We also review and refine these goals annually and make adjustments as necessary to ensure that we are consistently stretching our expectations and performance. Although some performance measures may stay the same, the applicable threshold may become more difficult. For example, in 2019, we increased some of the performance thresholds for our operations goals. The following provides an overview of the purposes of each category of our corporate goals:OneOur safety performance goal is measured by comparinggoals focused on the incident rate in our work environment against the national incident rate compiled by the U.S. Departmentnumber of Labor's Bureau of Labor Statistics. The other three goals focus onlost time incidents, safety training and meetings, and enhancing our safety program and procedures.whichthat minimizes long-term maintenance and replacement energy costs. Certain operational goals take into account performance standards as required by contracts related to the facility operations. Our achieving operational excellence at the corporate level results in the most reliable, efficient and lowest cost power supply for our members.meeting applicablesuccessful project deadlines. In 2017, we revised our goals related to our compliance with the electric reliability standards. entirely on the achievement of corporate goals and other executive officers' performance pay is based 75% on the achievement of corporate goals and 25% on individual performance. For executive officers whose performance pay is based entirely on corporate goal achievement, we multiply 20% of his or her base salary by the corporate goal achievement percentage to determine his or her performance bonus. For executive officers whose performance pay is based on corporate goals and individual performance, we multiply 15% of his or her base salary by the corporate goal achievement percentage and multiply 5% of his or her base salary by an individual performance ranking that ranges from 0% to 200%.20172019 Corporate Goals20172019 performance pay were the following:Performance
Category/ DescriptionPerformance Measure Threshold Maximum 2019
ResultWeight Weighted
Goal
AchievedSafety Incident Rate Lost Work Time Incidents 1 (if not OSHA) 0 0 3.0 % 3.00 % Training and Meetings 100.0 % 100.0 % 100.0 % 1.0 % 1.00 % Safety Observations 150/70 250/140 264/177 2.5 % 2.50 % Hazard Reduction Program 75.0 % 100.0 % 100.0 % 0.5 % 0.50 % Oglethorpe Managed Successful Starts 97.2 % 100.0 % 99.9 % 4.0 % 3.74 % Fleet Successful Dispatch 92.5 % 97.5 % 100.0 % 3.0 % 3.00 % Peak Season Availability 76.0 % 99.9 % 84.0 % 19.0 % 15.96 % Co-Owned Fleet Coal Fleet Peak Season Equivalent Forced Outage Rate 5.5 % 3.5 % 0.2 % 1.3 % 1.33 % Coal Fleet Annual Equivalent Unplanned Unavailability Factor 6.2 % 4.3 % 2.9 % 0.7 % 0.67 % Nuclear Fleet Capability Factor 91.4 % 92.8 % 92.9 % 2.0 % 2.00 % Construction and Project Management Vogtle Units No. 3 and No. 4 Oglethorpe Performance 0.0 % 100.0 % 95.0 % 7.0 % 6.65 % Status of Project Meet applicable deadlines 75.0 % 3.0 % 2.25 % Oglethorpe Managed Projects Status of Projects Meet applicable deadlines & budgets 81.7 % 6.0 % 4.90 % Corporate Compliance Environmental Final Notices of Violation and Letters of Non-Compliance 1 (if fine is ≤ $5,000) or 2 0 0 4.0 % 4.00 % Reportable Spills 1 0 0 4.0 % 4.00 % Mandatory Electric Reliability Standards Non-Critical Infrastructure Protection Compliance 1+ (if minimal penalty) 0 0 3.0 % 3.00 % Critical Infrastructure Protection Compliance 1+ (if minimal penalty) 0 0 3.0 % 3.00 % Financial Cost Saving Current Year / Long-Term Savings $ 0 $ 50,000,000 $ 91,615,913 14.0 % 14.00 % Additional Cost Savings $ 0 $ 50,000,000 $ 14,518,999 0-5.0% 1.45 % Internal Control over Financial Reporting Significant Deficiency or Material Weakness 0 0 0 2.0 % 2.00 % Control Deficiency 2 1 0 2.0 % 2.00 % Quality Board Satisfaction Board of Directors Survey 80.0 % 100.0 % 94.7 % 15.0 % 14.20 % Total 100.0 % 95.15 % Performance
Category/ Description Performance Measure Threshold Maximum 2017 Result Weight Weighted
Goal
Achieved Safety Incident Rate Lost Work Time Cases 1+ (if not OSHA) 0 1 3.0 % 1.50 % Safety Program(1) Training and Meetings 33.3 % 100.0% 100.0 % 1.0 % 1.00 % Safety Observations 175 300 >300 3.0 % 3.00 % Procedures Lockout-Tagout Enhancement Meet applicable deadlines 100.0 % 3.0 % 3.00 %
Operations(2)
Oglethorpe Managed Successful Starts 96.9 % 100.0% 99.0 % 4.0 % 2.97 % Fleet Successful Dispatch 92.5 % 97.5% 96.5 % 3.0 % 1.98 % Peak Season Availability 66.5 % 99.69% 88.5 % 19.0 % 16.81 % Smith Gas Availability 0.0 % 100.0% 65.9 % 1.0 % 0.66 % Co-Owned Fleet Coal Fleet Peak Season Equivalent Forced Outage Rate 5.25 % 3.25% 1.2 % 1.33 % 1.33 % Coal Fleet Annual Equivalent Unplanned Unavailability Factor 6.0 % 4.0% 4.4 % 0.67 % 0.61 % Nuclear Fleet Capability Factor 91.7 % 92.1% 93.5 % 2.0 % 2.00 %
Construction and Project Management
Vogtle Units No. 3 and No. 4 Oglethorpe Performance 0.0 % 100.0% 100.0 % 6.0 % 6.00 % Status of Project Meet applicable deadlines 0.0 % 2.0 % 0.00 % Oglethorpe Managed Projects Status of Projects Meet applicable deadlines 87.5 % 4.0 % 3.50 %
Corporate Compliance
Environmental Final Notices of Violation and Letters of Non-Compliance 1 (if fine is £
$5,000) or 2 0 2 4.0 % 2.00 % Reportable Spills 1 0 0 4.0 % 4.00 % Mandatory Electric Reliability Standards Non-Critical Infrastructure Protection Compliance 1+ (if minimal penalty) 0 0 3.0 % 3.00 % Critical Infrastructure Protection Compliance 1+ (if minimal penalty) 0 0 3.0 % 3.00 %
Financial
Cost Saving Current Year / Long-Term Savings $0 $35,000,000 $ 77,998,267 14.0 % 14.00 % Internal Control over Financial Reporting Significant Deficiency or Material Weakness 0 0 0 2.0 % 2.00 % Control Deficiency 2 1 0 2.0 % 2.00 %
Quality
Board Satisfaction Board of Directors Survey 80.0 % 100.0% 95.7 % 15.0 % 14.40 % 100.0 % 88.71 % have beenare aggregated for purposes of the table.results based on all of the generating units within the category.88.71%95.15% of our corporate goals for 2017.2019. As a result, Mr. Smith, Mr. Price, Ms. Higgins and Mr. Ussery received performance pay in an amount equal to 88.71%95.15% of 20% of his or her base salary. Mr. Messersmith88.71%95.15% of 15% of his base salary plus 115% of 5% of his base salary. Set forth below is a table showing performance pay figures for each of our executive officers who received performance pay in 2017:Executive Officer Performance Pay* Michael L. Smith $ 149,376 Michael W. Price 88,091 Elizabeth B. Higgins 88,714 William F. Ussery 68,953 James A. Messersmith 66,052 Executive Officer Performance Pay* $ 126,330 75,936 76,468 59,436 58,602 2017.2019. Actual compensation earned in 20172019 is reported in the Summary Compensation Table below.2020.2022. Mr. Smith's agreement will automatically renew pursuant to the corresponding provision of the agreement for successive one-year periods unless either party provides written notice not to renew the agreement twenty-four months before the expiration of any extended term. Each year, our board of directors makes an affirmative determination as to whether to provide such notice and no such notice has been provided. Mr. Smith's minimum annual base salary under his agreement is $630,000, and is subject to review and adjustment by our board of directors. Mr. Smith is eligible for an annual bonus and to participate in incentive compensation plans generally available to similarly situated employees and for an annual bonus determined by our board of directors at its sole discretion. Mr. Smith is also entitled to an automobile or an automobile allowance during the term of the agreement. Mr. Smith's employment agreement contains severance pay provisions.20192022 and will automatically renew for successive one-year periods unless either party provides written notice not to renew the agreement twelvetwenty-four months before the expiration of any extended term. Each year, our president and chief executive officer makes an affirmative determination as to whether to provide such notice, and no such notices have been provided.$414,000$445,100 for Mr. Price, $417,100$448,250 for Ms. Higgins and $324,400$348,400 for Mr. Ussery. Salaries are subject to review and possible adjustment as determined by the president and chief executive officer. Each executive is also eligible for an annual bonus and to participate in incentive compensation plans generally available to similarly situated employees and for an annual bonus determined by usthe president and chief executive officer at ourhis sole discretion. The employment agreements with Mr. Price, Ms. Higgins and Mr. Ussery contain severance pay provisions.isare entitled to severance payments and benefits in the event they are terminated not for cause or they resign for good reason.$1,572,912. The compensation committee also$1,781,908. Mr. Smith, Mr. Price, Ms. Higgins and Mr. Ussery would receive upon the occurrence of a severance event. The compensation committeeevent and determined that it was appropriate for these executive officers to receive severance compensation equal to one year's compensation,a maximum of two years of his or her then current base salary, plus benefits as described below, because such agreements provide a measure of stability for both us and the executive officers. In addition, like our president and chief executive officer, these executive officers are not compensated using options or other forms of equity compensation that lead to significant wealth accumulation. Therefore, the compensation committeeour president and chief executive officer believes such severance compensation is necessary to address competitive concerns and offset any potential risk our executive officers face in the course of their employment.one year of the executive'sexecutive officer's then current base salary through the rest of the term of the agreement (with a minimum of one year's pay and a maximum of two years' pay), payable within 30 days of termination, subject to the provisions of Internal Revenue Code Section 409A. In addition, the executive will be entitled to six monthsone year of outplacement services and an amount equal to the executive's cost for medical and dental continuation coverage under COBRA for six months.one year. Severance is payable only if the executive signs a form releasing all claims against us. The maximum severance that would be payable to Mr. Price, Ms. Higgins and Mr. Ussery in the circumstances described above is $473,556, $477,600,$1,031,783, $1,030,459, and $366,506,$799,119, respectively.20172019 for filing with the SEC.Randy CrenshawM. Anthony HamDanny Nichols
Marshall S. MillwoodSammy G. SimontonCrenshaw,McWhorter, Mr. Ham, Mr. Jakins, Mr. NicholsSimonton and Mr. SimontonNichols served as members of our compensation committee in 2017.$8.8$8.6 million to us in 20172019 under its wholesale power contract accounted for approximately 0.6% of our total revenues. Middle Georgia's revenues of $5.7$5.6 million to us in 20172019 under its wholesale power contract accounted for approximately 0.4% of our total revenues.$210.4$205.5 million to us in 20172019 under its wholesale power contract accounted for approximately 14.7%14.4% of our total revenues.$44.5$43.9 million to us in 20172019 under its wholesale power contract accounted for approximately 3.1% of our total revenues.2017, 20162019, 2018 and 2015. Name and Principal Position Year Salary Bonus Non-Equity
Incentive Plan
Compensation All Other
Compensation(1) Total Name and Principal Position Year Salary Bonus Non-Equity
Incentive Plan
CompensationAll Other
Compensation(1)Total Michael L. Smith 2017 $ 708,026 $ – $ 126,330 $ 144,420 $ 978,776 Michael L. Smith 2019 $ 777,546 $ — $ 149,376 $ 156,167 $ 1,083,089 President and 2016 683,550 – 129,103 136,677 949,330 President and 2018 735,773 — 137,337 147,423 1,020,533 Chief Executive Officer 2015 656,250 – 113,050 86,864 856,164 Chief Executive Officer 2017 708,026 — 126,330 144,420 978,776
Michael W. Price
2017
425,667
–
75,936
109,838
611,441
Michael W. Price 2019 459,937 — 88,091 97,313 645,341 Executive Vice President and 2016 411,667 – 77,691 93,704 580,567 Executive Vice President and 2018 442,250 — 82,548 92,629 617,427 Chief Operating Officer 2015 397,500 – 68,360 59,478 525,338 Chief Operating Officer 2017 425,667 — 75,936 109,838 611,441
Elizabeth B. Higgins
2017
428,683
–
76,468
91,103
596,254
Elizabeth B. Higgins 2019 463,192 — 88,714 97,554 649,460 Executive Vice President and 2016 414,750 – 78,273 79,465 569,914 Executive Vice President and 2018 445,375 — 83,132 92,600 621,107 Chief Financial Officer 2015 400,333 – 68,873 61,701 530,907 Chief Financial Officer 2017 428,683 — 76,468 91,103 596,254
William F. Ussery
2017
333,233
–
59,436
73,508
466,177
William F. Ussery 2019 360,013 — 68,953 78,575 507,541 Executive Vice President, 2016 322,833 – 60,877 78,308 462,018 Executive Vice President, 2018 346,167 — 64,614 76,047 486,828 Member and External Relations 2015 313,333 – 53,833 48,547 415,713 Member and External Relations 2017 333,233 — 59,436 73,508 466,177
James A. Messersmith
2017
305,546
–
58,602
66,242
430,390
James A. Messersmith 2019 328,371 — 66,052 74,458 468,881 Senior Vice President, Senior Vice President, 2018 316,487 — 62,966 73,774 453,227 Plant Operations Plant Operations 2017 305,546 — 58,602 66,242 430,390 20172019 consist of matching contributions and contributions made by Oglethorpe under the 401(k) Retirement Savings Plan on behalf of each Mr. Smith, Mr. Price, Ms. Higgins, Mr. Ussery, and Mr. Messersmith of $36,000, $36,000, $36,000, $36,000, and $36,000, respectively;$37,000; contributions by Oglethorpe to a nonqualified deferred compensation plan on behalf of Mr. Smith, Mr. Price, Ms. Higgins, Mr. Ussery, and Mr. Messersmith, respectively of $89,880, $43,033, $40,642, $25,087$99,382, $45,954, $46,130, $28,662 and $20,446;$24,182; car allowances; paid time off, executive health benefits; customary holiday gifts and service awards.2017.Estimated Future
Payouts
Under Non-Equity
Incentive Plan AwardsName Grant Date Threshold Maximum Michael L. Smith N/A $ 35,864 $ 156,990 Michael W. Price N/A $ 21,150 $ 92,581 Elizabeth B. Higgins N/A $ 21,299 $ 93,236 William F. Ussery N/A $ 16,555 $ 72,467 James A. Messersmith N/A $ 24,500 $ 82,472 Estimated Future
Payouts
Under Non-Equity
Incentive Plan Awards Grant Date Name Threshold Maximum Michael L. Smith N/A $ 31,059 $ 142,408
Michael W. Price
N/A
$
18,669
$
85,600
Elizabeth B. Higgins
N/A
$
18,800
$
86,200
William F. Ussery
N/A
$
14,613
$
67,000
James A. Messersmith
N/A
$
22,361
$
76,879
20172019 Corporate Goals."270,000280,000 as indexed).20172019 along with aggregate earnings for the same period.Name Executive
Contributions
in Last FYAggregate
Withdrawals/
Distributions
in Last FYAggregate
Balance at
Last FYEMichael L. Smith $ 35,000 $ 99,382 $ 108,136 $ — $ 738,591 Michael W. Price $ 7,300 $ 45,954 $ 95,371 $ — $ 481,969 Elizabeth B. Higgins $ 10,000 $ 46,130 $ 111,870 $ — $ 527,926 William F. Ussery $ 1,000 $ 28,662 $ 41,399 $ — $ 226,481 James A. Messersmith $ — $ 24,182 $ 28,267 $ — $ 151,368 Name Executive
Contributions
in Last FY Registrant
Contributions
in Last FY(1) Aggregate
Earnings
in Last FY(2) Aggregate
Withdrawals/
Distributions
in Last FY Aggregate
Balance at
Last FYE Michael L. Smith $ 25,000 $ 89,880 $ 49,391 $ – $ 399,817 Michael W. Price $ 6,066 $ 43,033 $ 39,496 – $ 303,248 Elizabeth B. Higgins $ 12,284 $ 40,642 $ 55,842 – $ 335,422 William F. Ussery – $ 25,087 $ 20,572 – $ 141,145 James A. Messersmith – $ 20,446 $ 12,134 – $ 81,905 2017.2017,2019, we had 277299 employees, including full-time, part-time, temporary and seasonal workers (excluding our president and chief executive officer), who were all located in the United States. We then calculated the annual total compensation for each of these employees for the fiscal year ended December 31, 20172019 in the same manner in which we calculated our president and chief executive officer's total annual compensation presented in the "Summary Compensation Table." Employee compensation includes salary, performance pay and benefits.20172019 was $138,937.$148,238. As set forth in the Summary Compensation Table, our president and chief executive officer's annual total compensation for 20172019 was $978,776.$1,083,089. The ratio of our president and chief executive officer's annual total compensation to our median employee's annual total compensation for the fiscal year ended December 31, 20172019 was 7.04:7.31:1.2017.Name Total Fees
Earned or Paid
in CashMember Directors Jimmy G. Bailey $ 16,000 Randy Crenshaw $ 14,400 Ernest A. "Chip" Jakins III $ 12,400 Fred A. McWhorter $ 14,200 Marshall S. Millwood, Vice-Chairman $ 15,000 Jeffrey W. Murphy $ 15,000 Danny L. Nichols $ 14,300 Sammy G. Simonton $ 16,300 Bobby C. Smith, Jr., Chairman $ 16,780 George L. Weaver $ 16,300 James I. White $ 16,100 Outside Director Wm. Ronald Duffey $ 32,000 Name Total Fees
Earned or Paid
in Cash Member Directors Jimmy G. Bailey $ 22,100 Randy Crenshaw $ 19,900 M. Anthony Ham $ 20,100 Ernest A. "Chip" Jakins III $ 20,100 Fred A. McWhorter $ 21,600 Marshall S. Millwood, Vice-Chairman $ 21,600 Jeffrey W. Murphy $ 21,200 Danny L. Nichols $ 21,000 Bobby C. Smith, Jr., Chairman $ 27,080 Sammy G. Simonton $ 21,600 George L. Weaver $ 23,000 James I. White $ 23,600 Outside Director Wm. Ronald Duffey $ 39,600 2017,2019, we paid our member directors a fee of $1,200 per board meeting and $800 per day for attending committee meetings, other meetings, or other official business approved by the chairman of the board of directors. Member directors are paid $600 per day for attending the annual meeting of members and member advisory board meetings and $300 per day for participation by video conference for a meeting of the advisory board. OurWe paid our outside director was paid a fee of $5,500 per board meeting for four meetings a year and a fee of $1,000 per board meeting for the remaining other board meetings held during the year. Our outside director was also paid $1,000 per day for attending committee meetings, annual meetings of the members or other official business. In addition, we reimburse all directors for out-of-pocket expenses incurred in attending a meeting. All directors are paid $100 per dayhour, or for each fraction thereof, up to a daily cap of $600, when participating in meetings by conference call. The chairman of the board of directors is paid an additional 20% of his director's fee per board meeting for time involved in preparing for the meetings. The audit committee financial expert is paid an additional $400 per audit committee meeting for the time involved in fulfilling that role. If more than one meeting is held the same day, only one day's per diem is paid. Neither our outside director nor member directors receive any perquisites or other personal benefits from us.$8.8$8.6 million to us in 20172019 under its wholesale power contract accounted for approximately 0.6% of our total revenues. Middle Georgia's revenues of $5.7$5.6 million to us in 20172019 under its wholesale power contract accounted for approximately 0.4% of our total revenues.$210.4$205.5 million to us in 20172019 under its wholesale power contract accounted for approximately 14.7%14.4% of our total revenues.$21.3$18.7 million to us in 20172019 under its wholesale power contract accounted for approximately 1.5%1.3% of our total revenues.$44.5$43.9 million to us in 20172019 under its wholesale power contract accounted for approximately 3.1% of our total revenues.$42.0$42.8 million to us in 20172019 under its wholesale power contract accounted for approximately 2.9%3.0% of our total revenues.2017.2019. Although we do not have any securities listed on the NASDAQ Stock Market, we have used its independence criteria in making this determination in accordance with applicable SEC rules.20172019 and 2016,2018, fees for services provided by our independent registered public accounting firm, Ernst & Young LLP were as follows:2019 2018 (dollars in thousands) $ 544 $ 528 242 12 59 38 2 2 Total $ 847 $ 580 2017 2016 (dollars in thousands) Audit Fees(1) $ 513 $ 498 Audit-Related Fees(2) 67 57 Tax Fees(3) 41 26 All Other Fees(4) 2 2 Total $ 623 $ 583 20172019 were pre-approved in accordance with the pre-approval policy and procedures adopted by the audit committee. The policy requires that requests for all services must be submitted to the audit committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-approval is provided at regularly scheduled meetings.Page(1)Page (1) Financial Statements (Included under "Financial Statements and Supplementary Data") (2) (2)None applicable.None applicable. (3)(3) ExhibitsExhibits Number Description *3.1(a) – Restated Articles of Incorporation of Oglethorpe, dated as of July 26, 1988. (Filed as Exhibit 3.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1988, File No. 33-7591.) *3.1(b) – *3.2 – *4.1 – *4.2.1(a) – *4.2.1(b) – *4.2.1(c) – *4.2.1(d) – *4.2.1(e) – *4.2.1(f) – *4.2.1(g) – *4.2.1(h) – *4.2.1(i) – –*4.2.1(j) – –*4.2.1(k) – –*4.2.1(l) – –*4.2.1(m) – –*4.2.1(n) – –*4.2.1(o) – –*4.2.1(p) – –*4.2.1(q) – –*4.2.1(r) – –*4.2.1(s) – –*4.2.1(t) – –*4.2.1(u) – –*4.2.1(v) – –*4.2.1(w) – –*4.2.1(x) – –*4.2.1(y) – –*4.2.1(z) – –*4.2.1(aa) – –*4.2.1(bb) – –*4.2.1(cc) – –*4.2.1(dd) – –*4.2.1(ee) – –*4.2.1(ff) – –*4.2.1(gg) – –*4.2.1(hh) – –*4.2.1(ii) – –*4.2.1(jj) – –*4.2.1(kk) – –*4.2.1(ll) – –*4.2.1(mm) – –*4.2.1(nn) – –*4.2.1(qq) – –*4.2.1(rr) – –Forty-Third Supplemental Indenture, dated as of August 1, 2008, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2008A (Burke) Note, Series 2008B (Burke) Note and Series 2008C (Burke) Note. (Filed as Exhibit 4.7.1(rr) to the Registrant's Form 10-K for the fiscal year ended December 31, 2008, File No. 33-7591.) *4.2.1(ss) – –*4.2.1(tt) – –*4.2.1(uu) – –*4.2.1(vv) – –*4.2.1(ww) – –*4.2.1(xx) – –*4.2.1(yy) – –*4.2.1 (zz) – –*4.2.1 (bbb) – –*4.2.1 (ccc) – –*4.2.1 (ddd) – –*4.2.1 (eee) – –*4.2.1(fff) – –*4.2.1(ggg) – –*4.2.1(hhh) – –*4.2.1(iii) – –*4.2.1(jjj) – –*4.2.1(kkk) – –*4.2.1(lll) – –*4.2.1(mmm) – –*4.2.1(nnn) – –*4.2.1(ooo) – –*4.2.1(ppp) – –*4.2.1(qqq) – –*4.2.1(rrr) – –*4.2.1(sss) – –*4.2.1(ttt) – –*4.2.1(uuu) – –*4.2.1(vvv) – –*4.2.1(www) – –*4.2.1(xxx) – –*4.2.1(yyy) – –*4.2.1(zzz) – –*4.2.1(aaaa) – *4.2.1(bbbb) – *4.2.2 – –*4.3 – –– –Loan Agreement, dated as of December 1, 2009, between the Development Authority of Monroe County and Oglethorpe relating to the Development Authority of Monroe County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Scherer Project), Series 2009A, and five other substantially identical (Variable Rate Bonds) loan agreements. – –Note, dated December 10, 2009, from Oglethorpe to U.S. Bank National Association, as trustee, acting pursuant to a Trust Indenture, dated as of December 1, 2009, between the Development Authority of Monroe County and U.S. Bank National Association relating to the Development Authority of Monroe County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Scherer Project), Series 2009A, and five other substantially identical notes. – –Trust Indenture, dated as of December 1, 2009, between the Development Authority of Monroe County and U.S. Bank National Association, as trustee, relating to the Development Authority of Monroe County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Scherer Project), Series 2009A, and five other substantially identical indentures. – –Loan Agreement, dated as of April 1, 2013, between the Development Authority of Appling County and Oglethorpe relating to the Development Authority of Appling County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Hatch Project), Series 2013A, and two other substantially identical (Term Rate Bonds) loan agreements. – –Note, dated April 23, 2013, from Oglethorpe to U.S. Bank National Association, as trustee, acting pursuant to a Trust Indenture, dated as of April 1, 2013, between the Development Authority of Appling County and U.S. Bank National Association relating to the Development Authority of Appling County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Hatch Project), Series 2013A, and two other substantially identical notes. – –Trust Indenture, dated as of April 1, 2013, between the Development Authority of Appling County and U.S. Bank National Association, as trustee, relating to the Development Authority of Appling County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Hatch Project), Series 2013A, and two other substantially identical indentures. – –Loan Agreement, dated as of October 1, 2017, between the Development Authority of Burke County and Oglethorpe relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017A, and three other substantially identical (Indexed Put Rate Bonds) loan agreements. – –Note, dated October 12, 2017, from Oglethorpe to U.S. Bank National Association, as trustee, acting pursuant to a Trust Indenture, dated as of October 1, 2017, between the Development Authority of Burke County and U.S. Bank National Association relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017A, and three other substantially identical notes. – –Trust Indenture, dated as of October 1, 2017, between the Development Authority of Burke County and U.S. Bank National Association, as trustee, relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017A, and three other substantially identical indentures. – –Bondholder's Agreement, dated as of October 1, 2017, by and between Oglethorpe and RBC Municipal Products, LLC, relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017A, and three other substantially identical bondholder's agreements. – –Loan Agreement, dated as of December 1, 2017, between the Development Authority of Burke County and Oglethorpe relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017C, and three other substantially identical (Fixed Rate and Term Rate Bonds) loan agreements. – –Note, dated December 28, 2017, from Oglethorpe to U.S. Bank National Association, as trustee, acting pursuant to a Trust Indenture, dated as of December 1, 2017, between the Development Authority of Burke County and U.S. Bank National Association relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017C, and three other substantially identical notes. – –Trust Indenture, dated as of December 1, 2017, between the Development Authority of Burke County and U.S. Bank National Association, as trustee, relating to the Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2017C, and three other substantially identical indentures. – –Term Loan Agreement, dated as of August 1, 2009, between Oglethorpe and National Rural Utilities Cooperative Finance Corporation, relating to the Series 2009C Note. – –First Amendment to Term Loan Agreement, dated as of December 20, 2013, by and between Oglethorpe and National Rural Utilities Cooperative Finance Corporation, relating to the Series 2009C Note. – –Second Amendment to Term Loan Agreement, dated as of March 23, 2015, by and between Oglethorpe and National Rural Utilities Cooperative Finance Corporation, relating to the Series 2009C Note.– Third Amendment to Term Loan Agreement, dated as of December 12, 2018, by and between Oglethorpe and National Rural Utilities Cooperative Finance Corporation, relating to the Series 2009C Note. – Series 2009C CFC Note, dated August 11, 2009, in the original principal amount of $250,000,000, from Oglethorpe to National Rural Utilities Cooperative Finance Corporation. – –Bond Purchase Agreement, dated as of December 30, 2009, between Oglethorpe and CoBank, ACB, relating to Oglethorpe Power Corporation (An Electric Membership Corporation) First Mortgage Bond, Series 2009 CoBank (Clean Renewable Energy Bond). – –Oglethorpe Power Corporation (An Electric Membership Corporation) First Mortgage Bond, Series 2009 CoBank (Clean Renewable Energy Bond), dated December 30, 2009, from Oglethorpe to CoBank, ACB, in the original principal amount of $16,165,400. *4.10.1 – –*4.10.2 – –*4.10.3 – –*4.10.4 – –*4.10.5 – *4.10.6 – * 4.10.4(a)4.10.6(a)– –* 4.10.4(b)4.10.6(b)– –* 4.10.4(c)4.10.6(c)– –*4.10.4(d)–Amendment No. 4, dated as of December 8, 2017, to the Loan Guarantee Agreement between Oglethorpe and the Department of Energy. (Filed as Exhibit 4.1 to the Registrant's Form 8-K filed on December 11, 2017, File No. 333-192954.)*4.10.5–Reimbursement Note No. 1, dated February 20, 2014, issued by Oglethorpe to the Department of Energy. (Filed as Exhibit 4.5 to the Registrant's Form 8-K filed on February 20, 2014, File No. 000-53908.)*4.10.6(d) – *4.10.6(e) – *4.10.6(f) – *4.10.7 – *4.10.8 – 4.10.9 – Reimbursement Note, dated March 22, 2019, issued by Oglethorpe to the Department of Energy. (Filed as Exhibit 4.4 to the Registrant's Form 8-K filed on March 27, 2019, File No. 333-192954.) *10.1.1(a) – Participation Agreement No. 2 among Oglethorpe as Lessee, Wilmington Trust Company as Owner Trustee, The First National Bank of Atlanta as Indenture Trustee, Columbia Bank for Cooperatives as Loan Participant and Ford Motor Credit Company as Owner Participant, dated December 30, 1985, together with a schedule identifying three other substantially identical Participation Agreements. (Filed as Exhibit 10.1.1(b) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.1(b) – Supplemental Participation Agreement No. 2. (Filed as Exhibit 10.1.1(a) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.1(c) – Supplemental Participation Agreement No. 1, dated as of June 30, 1987, among Oglethorpe as Lessee, IBM Credit Financing Corporation as Owner Participant, Wilmington Trust Company and The Citizens and Southern National Bank as Owner Trustee, The First National Bank of Atlanta, as Indenture Trustee, and Columbia Bank for Cooperatives, as Loan Participant. (Filed as Exhibit 10.1.1(c) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.) *10.1.1(d) – *10.1.2 – General Warranty Deed and Bill of Sale No. 2 between Oglethorpe, Grantor, and Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Grantee, together with a schedule identifying three substantially identical General Warranty Deeds and Bills of Sale. (Filed as Exhibit 10.1.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.3 – *4.10.6–Reimbursement Note No. 2, dated February 20, 2014, issued by Oglethorpe to the Department of Energy. (Filed as Exhibit 4.6 to the Registrant's Form 8-K filed on February 20, 2014, File No. 000-53908.)* 10.1.1(a)10.1.4(a)– –Participation Agreement No. 2 among Oglethorpe as Lessee, Wilmington Trust Company as Owner Trustee, The First National Bank of Atlanta as Indenture Trustee, Columbia Bank for Cooperatives as Loan Participant and Ford Motor Credit Company as Owner Participant, dated December 30, 1985, together with a schedule identifying three other substantially identical Participation Agreements. (Filed as Exhibit 10.1.1(b) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)*10.1.1(b)–Supplemental Participation Agreement No. 2. (Filed as Exhibit 10.1.1(a) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)*10.1.1(c)–Supplemental Participation Agreement No. 1, dated as of June 30, 1987, among Oglethorpe as Lessee, IBM Credit Financing Corporation as Owner Participant, Wilmington Trust Company and The Citizens and Southern National Bank as Owner Trustee, The First National Bank of Atlanta, as Indenture Trustee, and Columbia Bank for Cooperatives, as Loan Participant. (Filed as Exhibit 10.1.1(c) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.)*10.1.1(d)–Second Supplemental Participation Agreement No. 2, dated as of December 17, 1997, among Oglethorpe as Lessee, DFO Partnership, as assignee of Ford Motor Credit Company, as Owner Participant, Wilmington Trust Company and NationsBank, N.A. as Owner Trustee, The Bank of New York Trust Company of Florida, N.A. as Indenture Trustee, CoBank, ACB as Loan Participant, OPC Scherer Funding Corporation, as Original Funding Corporation, OPC Scherer 1997 Funding Corporation A, as Funding Corporation, and SunTrust Bank, Atlanta, as Original Collateral Trust Trustee and Collateral Trust Trustee, with a schedule identifying three substantially identical Second Supplemental Participation Agreements and any material differences. (Filed as Exhibit 10.1.1(d) to Registrant's Form S-4 Registration Statement, File No. 333-4275.)*10.1.2–General Warranty Deed and Bill of Sale No. 2 between Oglethorpe, Grantor, and Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Grantee, together with a schedule identifying three substantially identical General Warranty Deeds and Bills of Sale. (Filed as Exhibit 10.1.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)*10.1.3–Amended and Restated Indenture of Trust, Deed to Secure Debt and Security Agreement No. 2, dated December 1, 1997, between Wilmington Trust Company and NationsBank, N.A. collectively as Owner Trustee, under Trust Agreement No. 2, dated December 30, 1985, with DFO Partnership, as assignee of Ford Motor Credit Company, and The Bank of New York Trust Company of Florida, N.A. as Indenture Trustee, with a schedule identifying three other substantially identical Amended and Restated Indentures of Trust, Deeds to Secure Debt and Security Agreements and any material differences. (Filed as Exhibit 4.4 to the Registrant's Form S-4 Registration Statement, File No. 333-42759.)*10.1.4(a)–Lease Agreement No. 2, dated December 30, 1985, between Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Lessor, and Oglethorpe, Lessee, with a schedule identifying three other substantially identical Lease Agreements. (Filed as Exhibit 4.5(b) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.4(b) – –First Supplement to Lease Agreement No. 2 (included as Exhibit B to the Supplemental Participation Agreement No. 2 listed as Exhibit 10.1.1(b)). *10.1.4(c) – –First Supplement to Lease Agreement No. 1, dated as of June 30, 1987, between The Citizens and Southern National Bank as Owner Trustee under Trust Agreement No. 1 with IBM Credit Financing Corporation, as Lessor, and Oglethorpe, as Lessee. (Filed as Exhibit 4.5(c) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.) *10.1.4(d) – –*10.1.5(a) – –Supporting Assets Lease No. 2, dated December 30, 1985, between Oglethorpe, Lessor, and Wilmington Trust Company and William J. Wade, as Owner Trustees, under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Lessee, together with a schedule identifying three substantially identical Supporting Assets Leases. (Filed as Exhibit 10.1.3 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.5(b) – –First Amendment to Supporting Assets Lease No. 2, dated as of November 19, 1987, together with a schedule identifying three substantially identical First Amendments to Supporting Assets Leases. (Filed as Exhibit 10.1.3(a) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.) *10.1.5(c) – –*10.1.6(a) – –Supporting Assets Sublease No. 2, dated December 30, 1985, between Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Sublessor, and Oglethorpe, Sublessee, together with a schedule identifying three substantially identical Supporting Assets Subleases. (Filed as Exhibit 10.1.4 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.6(b) – –First Amendment to Supporting Assets Sublease No. 2, dated as of November 19, 1987, together with a schedule identifying three substantially identical First Amendments to Supporting Assets Subleases. (Filed as Exhibit 10.1.4(a) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.) *10.1.6(c) – –*10.1.7(a) – –Tax Indemnification Agreement No. 2, dated December 30, 1985, between Ford Motor Credit Company, Owner Participant, and Oglethorpe, Lessee, together with a schedule identifying three substantially identical Tax Indemnification Agreements. (Filed as Exhibit 10.1.5 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.8 – –Assignment of Interest in Ownership Agreement and Operating Agreement No. 2, dated December 30, 1985, between Oglethorpe, Assignor, and Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Assignee, together with a schedule identifying three substantially identical Assignments of Interest in Ownership Agreement and Operating Agreement. (Filed as Exhibit 10.1.6 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.9(a) – –Consent, Amendment and Assumption No. 2, dated December 30, 1985, among Georgia Power Company and Oglethorpe and Municipal Electric Authority of Georgia and City of Dalton, Georgia and Gulf Power Company and Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, together with a schedule identifying three substantially identical Consents, Amendments and Assumptions. (Filed as Exhibit 10.1.9 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.1.9(b) – –Amendment to Consent, Amendment and Assumption No. 2, dated as of August 16, 1993, among Oglethorpe, Georgia Power Company, Municipal Electric Authority of Georgia, City of Dalton, Georgia, Gulf Power Company, Jacksonville Electric Authority, Florida Power & Light Company and Wilmington Trust Company and NationsBank of Georgia, N.A., as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, together with a schedule identifying three substantially identical Amendments to Consents, Amendments and Assumptions. (Filed as Exhibit 10.1.9(a) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.) *10.2.1(a) – –Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit 10.6.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.2.1(b) – –Amendment to Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of December 30, 1985. (Filed as Exhibit 10.1.8 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.2.1(c) – –Amendment Number Two to the Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of July 1, 1986. (Filed as Exhibit 10.6.1(a) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.) *10.2.1(d) – –Amendment Number Three to the Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of August 1, 1988. (Filed as Exhibit 10.6.1(b) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.) *10.2.1(e) – –Amendment Number Four to the Plant Robert W. Scherer Units Number One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of December 31, 1990. (Filed as Exhibit 10.6.1(c) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.) *10.2.2(a) – –Plant Robert W. Scherer Units Numbers One and Two Operating Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit 10.6.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.2.2(b) – –Amendment to Plant Robert W. Scherer Units Numbers One and Two Operating Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of December 30, 1985. (Filed as Exhibit 10.1.7 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.2.2(c) – –Amendment Number Two to the Plant Robert W. Scherer Units Numbers One and Two Operating Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of December 31, 1990. (Filed as Exhibit 10.6.2(a) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.) *10.2.3 – –Plant Scherer Managing Board Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia, City of Dalton, Georgia, Gulf Power Company, Florida Power & Light Company and Jacksonville Electric Authority, dated as of December 31, 1990. (Filed as Exhibit 10.6.3 to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.) *10.3.1(a) – –Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit 10.7.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.3.1(b) – –Amendment Number One, dated January 18, 1977, to the Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia. (Filed as Exhibit 10.7.3 to the Registrant's Form 10-K for the fiscal year ended December 31, 1986, File No. 33-7591.) *10.3.1(c) – –Amendment Number Two, dated February 24, 1977, to the Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia. (Filed as Exhibit 10.7.4 to the Registrant's Form 10-K for the fiscal year ended December 31, 1986, File No. 33-7591.) *10.3.2 – –*10.3.2(a) – –*10.3.2(b) – *10.3.2(c) – *10.3.2(d) – *10.3.2(e) – *10.3.3 – *10.3.3(a) – *10.3.3(b) – *10.3.4 – 10.3.4(a) – – – – 10.3.6(c) Amendment No. 2 to Construction Completion Agreement dated as of November 8, 2019, between Georgia Power Company, for itself and as agent for Oglethorpe, Municipal Electric Authority of Georgia, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and the City of Dalton, Georgia and Bechtel Power Corporation. (Incorporated by reference to Exhibit 10(c)(8) of Georgia Power Company's Form 10-K for the fiscal year ended December 31, 2019, filed with the SEC on February 20, 2020.) *10.4.1 – Plant Hal Wansley Purchase and Ownership Participation Agreement between Georgia Power Company and Oglethorpe, dated as of March 26, 1976. (Filed as Exhibit 10.8.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.4.2(a) – –Plant Hal Wansley Operating Agreement between Georgia Power Company and Oglethorpe, dated as of March 26, 1976. (Filed as Exhibit 10.8.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.4.2(b) – –*10.4.2(c) – –*10.4.2(d) – *10.4.3 – –Plant Hal Wansley Combustion Turbine Agreement between Georgia Power Company and Oglethorpe, dated as of August 2, 1982 and Amendment No. 1, dated October 20, 1982. (Filed as Exhibit 10.18 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.5.1 – –Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement between Georgia Power Company and Oglethorpe, dated as of January 6, 1975. (Filed as Exhibit 10.9.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.5.2 – –Edwin I. Hatch Nuclear Plant Operating Agreement between Georgia Power Company and Oglethorpe, dated as of January 6, 1975. (Filed as Exhibit 10.9.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.) *10.6.1 – –Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement, dated as of November 18, 1988, by and between Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1988, File No. 33-7591.) *10.6.2 – –Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement, dated as of November 18, 1988, by and between Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.2 to the Registrant's Form 10-K for the fiscal year ended December 31, 1988, File No. 33-7591.) *10.7.1 – –*10.7.2 – –*10.7.3 – –*10.9(b) – *10.10 – Supplemental Agreement by and among Oglethorpe, Tri-County Electric Membership Corporation and Georgia Power Company, dated as of November 12, 1990, together with a schedule identifying 37 other substantially identical Supplemental Agreements. (Filed as Exhibit 10.30 to the Registrant's Form 8-K, filed January 4, 1991, File No. 33-7591.) *10.11.1(a) – *10.11.1(b) – *10.11.2 – *10.11.3 – *10.12 – *10.13 – Amended and Restated Credit Agreement, dated as of December 11, 2019, among Oglethorpe, as borrower, and the lenders identified therein, including National Rural Utilities Cooperative Finance Corporation, as administrative agent. (Filed as Exhibit 10.1 to the Registrant's Form 8-K filed on December 11, 2019, File No. 333-192954.) – – – – – 14.1 – Code of Conduct, available on our website, www.opc.com. 31.1 – 31.2 – 32.1 – 32.2 – 101 – XBRL Interactive Data File. 29th20th day of March, 2018.OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)By: By:
/s/ MICHAEL L. SMITHMICHAEL L. SMITH President and Chief Executive Officer SignatureTitleDate
Signature
Title
Date/s/ MICHAEL L. SMITH MICHAEL L. SMITHPresident and Chief Executive Officer (Principal Executive Officer) March 29, 201820, 2020
MICHAEL L. SMITH/s/ ELIZABETH B. HIGGINS ELIZABETH B. HIGGINS
Executive Vice President and Chief Financial Officer (Principal Financial Officer)
March 29, 201820, 2020
ELIZABETH B. HIGGINS/s/ G. KENNETH WARREN, JR. G. KENNETH WARREN, JR.
Vice President, Controller (Principal Accounting Officer)
March 29, 201820, 2020
G. KENNETH WARREN, JR./s/ JIMMY G. BAILEY Director March 20, 2020 JIMMY G. BAILEY DirectorMarch 29, 2018/s/ RANDY CRENSHAW RANDY CRENSHAW
Director
March 29, 201820, 2020
RANDY CRENSHAW/s/ WM. RONALD DUFFEY Director March 20, 2020 WM. RONALD DUFFEY DirectorMarch 29, 2018/s/ M. ANTHONY HAMM. ANTHONY HAMDirectorMarch 29, 2018
/s/ ERNEST A. JAKINS IIIDirector March 20, 2020 ERNEST A. JAKINS III Director/s/ FRED MCWHORTER Director March 29, 201820, 2020FRED MCWHORTER SignatureTitleDate
Signature
Title
Date/s/ FRED MCWHORTERFRED MCWHORTERDirectorMarch 29, 2018/s/ MARSHALL S. MILLWOOD Director March 20, 2020 MARSHALL S. MILLWOOD DirectorMarch 29, 2018/s/ JEFFREY W. MURPHY Director March 20, 2020 JEFFREY W. MURPHY DirectorMarch 29, 2018/s/ DANNY L. NICHOLS Director March 20, 2020 DANNY L. NICHOLS DirectorMarch 29, 2018/s/ SAMMY G. SIMONTON Director March 20, 2020 SAMMY G. SIMONTON DirectorMarch 29, 2018/s/ BOBBY C. SMITH, JR. Director March 20, 2020 BOBBY C. SMITH, JR. DirectorMarch 29, 2018/s/ GEORGE L. WEAVER Director March 20, 2020 GEORGE L. WEAVER DirectorMarch 29, 2018/s/ JAMES I. WHITE Director March 20, 2020 JAMES I. WHITE DirectorMarch 29, 2018