Oglethorpe Power Corporation is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, Georgia that operates on a not-for-profit basis. We are owned by 38 retail electric distribution cooperative members in Georgia. We provide wholesale electric power from a combination of owned and co-owned generating units of which our ownership share totals 7,125 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 738 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 160 megawatts of capacity, including 127 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 4.2 million people.

Our consolidated financial statements include our accounts and the accounts of our majority-owned and controlled subsidiary. We have determined that there are no accounts of variable interest entities for which we are the primary beneficiary. We have eliminated any intercompany profits and transactions in consolidation.

We follow generally accepted accounting principles in the United States. We maintain our accounts in accordance with the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service. We also apply the accounting guidance for regulated operations.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 2019 and 2018 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 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.

We are organized and operate as a cooperative. Our members paid a total of $190 in membership fees. Patronage capital includes retained net margin. Any excess of revenues over expenditures from operations is treated as an advance of capital by our members and is allocated to each member on the basis of their fixed percentage capacity cost responsibilities in our generation.

Any distributions of patronage capital are subject to the discretion of our board of directors, subject to first mortgage indenture requirements. Under our first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to, (i) an event of default exists under the indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is not less than 30% of our long-term debt and equities.

As an electric membership cooperative, our principle business is providing wholesale electric service to our members. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. These contracts, which extend to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. 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.

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

Each of our members is obligated to pay us for capacity and energy we furnish under its wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. 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.

The consideration we receive for providing capacity services is determined by our formulary rate on an annual basis. The components of the formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and income from other sources. Capacity revenues, therefore, vary to the extent these components vary. Fixed costs include items such as fixed operation and maintenance expenses, administrative and general expenses, depreciation and interest. Year to year, capacity revenue fluctuations are generally due to the recovery of fixed operation and maintenance costs. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in accordance with the associated revenue deferral plan as the expenses are recognized. For information regarding regulatory accounting, see Note 1q.

Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our capacity revenues are based on the associated costs we expect to recover in a given year and are recognized and billed to our members in equal monthly installments over the course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. Non-member capacity revenues, if any, are typically billed and recognized in equal monthly installments over the term of the contract.

We have a power bill prepayment program pursuant to which our members may prepay future capacity costs and receive a discount. As this program provides us with financing, we adjust our capacity revenues by the amount of the discount, which is based on our avoided cost of borrowing. For additional information regarding our member prepayment program, see Note 1p.

We satisfy our performance obligations to deliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our members based upon the variable costs incurred to generate or purchase that energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members’ service territories, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned or

purchased resources or member-owned resources over which we have dispatch rights, and by members’ decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers. In 2019, we provided approximately 58% of our members’ energy requirements. The standard selling price for our energy revenues from non-members is the price mutually agreed upon.

We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 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 revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our 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 non-members.

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

We have a rate management program that allows us to expense and recover interest costs 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 were $14,943,000, $12,229,000 and $11,000,000, respectively. The cumulative amount billed since inception of the program totaled $81,259,000.

In 2018, we began an additional rate management program that allows us to recover future expense on a current basis from our members. In general, the program allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. Under this program, amounts billed to participating members during 2019 and 2018 were $73,051,000 and $15,435,000, respectively. Funds collected through this program are 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

A substantial portion of our receivables are related to capacity 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. Receivables from contracts with our members at December 31, 2019, 2018 and 2017 were $142,946,000, $122,888,000 and $126,211,000, respectively. Payment is received the following month in which capacity and 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.

Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants has pursued and continues to pursue legal remedies against the Department of Energy for breach of contract.

Georgia Power filed claims against the U.S. Government in 2014 (as amended) seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering the 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. However, these undisputed damages are not collectable by Georgia Power and no amounts will be recognized in our financial statements until the court enters final judgement on the remaining damages.

Georgia Power filed additional claims against the U.S. Government in 2017 seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts were recognized in the financial statements as of December 31, 2019 for these additional claims. The final outcome of these matters cannot be determined at this time.

Asset retirement obligations are legal obligations associated with the retirement of long-lived assets. These obligations represent the present value of the estimated costs for an asset's future retirement discounted using a credit-adjusted risk-free rate, and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities and coal ash ponds. In addition, we have retirement obligations related to 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.

Periodically, we obtain revised cost studies associated with our nuclear and fossil plants' asset retirement obligations. Actual retirement costs may vary from these estimates. The estimated costs of nuclear and coal ash pond decommissioning are based on the most recent studies performed in 2018 and 2019, respectively.


	(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
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

Nuclear Decommissioning. Nuclear decommissioning cost estimates are based on site studies and assume prompt dismantlement and removal of both the radiated and non-radiated portions of the plant from service, as well as the management of spent fuel. We do not have a legal obligation to decommission non-radiated structures and, therefore, these costs are excluded from the related asset retirement obligation and the amounts in the table above. Actual decommissioning costs may vary from these estimates because of, but not limited to, changes in the assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials and equipment. Our most recent assessment of the nuclear asset obligation, which occurred in 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 2.8% for the Hatch units and 2.7% for Vogtle Units 1 & 2. That increase in the cash flow estimates was primarily attributable to general inflation, labor costs, volume of low-level radioactive waste and spent fuel management, among other factors. Our portion of the estimated costs of decommissioning co-owned nuclear facilities are as follows:


	(dollars in thousands)
2018 site study	Hatch Unit No. 1		Hatch Unit No. 2		Vogtle Unit No. 1		Vogtle Unit No. 2
Expected 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

We apply the provision of regulated operations to nuclear decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses) of our nuclear decommissioning funds are compared to the associated decommissioning expenses with the difference deferred as regulatory asset or liability. As this difference is

largely attributable to the timing of decommissioning fund earnings, the difference is recorded as an adjustment to investment income in our consolidated statements of revenues and expenses. Unrealized gains and losses of the decommissioning funds are recorded directly to the regulatory asset or liability for asset retirement obligations in accordance with our ratemaking treatment.

Coal Combustion Residuals. Coal combustion residuals (CCR) are 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 coal ash pond asset retirement obligation resulted in a 5,958,000 decrease and a $161,303,000 increase in the obligation for coal ash 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 regulations. The significant increase in cash flow estimates in 2018 was primarily attributed to the refinement of site specific closure 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 apply the provision of regulated operations to coal ash pond and landfill decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses, if any) are compared to the associated decommissioning expenses with the difference deferred as a regulatory asset. As this difference is attributable to the associated 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 associated decommissioning fund are recorded directly to the regulatory asset in accordance with our ratemaking treatment.

Accounting standards for asset retirement and environmental obligations do not apply to a retirement cost for which there is no legal obligation to retire the asset, and non-regulated entities are not allowed to accrue for such future retirement costs. We continue to recognize retirement costs for these other obligations in our depreciation rates under the accounting provisions for regulated operations. Accordingly, the accumulated retirement costs for other obligations are reflected as a regulatory liability in our balance sheets. For information regarding accumulated retirement costs for other obligations, see Note 1q.

The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The NRC definition of decommissioning does not include all costs that may be associated with decommissioning, such as spent fuel management and non-radiated structures. We have established external trust funds to comply with the NRC's regulations. Upon approval by the NRC, any funding in the external trust in excess of their requirements may be used for other decommissioning costs. In 2019 and 2018, no 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 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.

In addition to the external trust funds, we maintain unrestricted investments internally designated for nuclear decommissioning. These internal funds are available to be utilized to fund the external trust funds, should additional funding be required, as well as other decommissioning costs outside the scope of the NRC funding regulations. The funds are included in long-term investments on our consolidated balance sheet. In both 2019 and 2018, we contributed $4,750,000 into the internal funds.

The following table outlines the fair value of our nuclear decommissioning funds as of December 31, 2019 and December 31, 2018. The funds were invested in a diversified mix of approximately 64% equity and 36% fixed income securities in 2019 and 60% equity and 40% fixed income in 2018.


	2019
External Trust Funds:	(dollars in thousands)
	Cost 12/31/2018		Purchases		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


	2018
External Trust Funds:	(dollars in thousands)
	Cost 12/31/2017		Purchases		Net Proceeds(1)		Unrealized Gain(Loss)		Fair Value 12/31/2018
Equity	$	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

Realized and unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings by a non-regulated entity are directly deducted from or added to the regulatory asset or liability for asset retirement obligations in accordance with our rate-making treatment.

The nuclear decommissioning trust fund has produced an average annualized return of approximately 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 increases in cost estimates of decommissioning can be recovered in future rates.

Depreciation is computed on additions when they are placed in service using the composite straight-line method. We use standard depreciation rates as well as site specific rates determined through depreciation studies as approved by the Rural Utilities Service. The 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 2019, 2018, and 2017 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%

Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, including acquisition adjustments, if any, plus the cost of any subsequent additions. Cost includes an allowance for the cost of equity and debt funds used during construction and allocable overheads. For the years 2019, 2018 and 2017, the allowance for funds used during construction rates were 4.30%, 4.25% and 4.45%, respectively.

Replacements and renewals of items considered to be units of property, the lowest level of property for which we capitalize, are charged to the plant accounts. At the time properties are disposed of, the original cost 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.

Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds currently 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, 2019 and 2018, we had restricted investments totaling $533,590,000 and $653,158,000, respectively, of which $461,757,000 and $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.

The fossil fuel inventories primarily include the direct cost of coal and related transportation charges. The cost of fossil fuel inventories is carried at weighted average cost and is charged to fuel expense as consumed. The spare parts inventories primarily include the direct cost of generating plant spare parts. The spare parts inventory is carried at weighted average cost and the parts are charged to expense or capitalized, as appropriate when installed.

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


	(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

(c)Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 48 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit.

(d)Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant.

(f)Deferral of premiums paid to purchase interest rate options used to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No. 3 and No. 4. Amortization will commence when Vogtle Unit 3 goes in-service, which is expected November 2021.

We and our 38 members are members of Georgia Transmission. Georgia Transmission provides transmission services to its members for delivery of its members' power purchases from us and other power suppliers. We have entered into an agreement with Georgia Transmission to provide transmission services for third party transactions and for service to our owned facilities. For 2019, 2018, and 2017, we incurred expenses from Georgia Transmission of $37,156,000, $30,428,000 and $28,410,000, respectively.

We, Georgia Transmission and 38 of our members are members of Georgia Systems Operations. Georgia Systems Operations operates the system control center and currently provides us system operations services and administrative support services. For 2019, 2018, and 2017, we incurred expenses from Georgia Systems Operations of $26,730,000, $25,578,000, and $25,597,000, respectively.

In February 2016, the Financial Accounting Standards Board (FASB) issued “Leases (Topic 842).” The new leases standard requires a dual approach for lessee accounting under which a lessee accounts for leases as finance leases or operating leases. Accounting for both finance leases and operating leases results in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee recognizes interest expense and amortization of the ROU asset and for operating leases the lessee recognizes 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. We adopted the new standard effective January 1, 2019. For additional information, see Note 6.

In June 2016, the FASB issued ‘‘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.

In August 2018, the FASB issued “Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement.” This standard eliminates, adds and modifies certain disclosure requirements for fair value measurements as part of the FASB’s disclosure framework project. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels and the valuation processes for Level 3 fair value measurements. However, public business entities will be required to disclose the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. An entity is permitted to early adopt any removed or modified disclosures upon issuance of this update and delay adoption of the additional disclosures until their effective date.