1. Summary of significant accounting policies:

a. Business description

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 7,060 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 731 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 120 megawatts of capacity, including 87 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 4.1 million people.

b. Basis of accounting

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, 2018 and 2017 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2018. Actual results could differ from those estimates.

c. Patronage capital and membership fees

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.

d. Margin policy

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 the years 2018, 2017 and 2016, we achieved a margins for interest ratio of 1.14.

e. Revenue recognition

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 under their wholesale power contract to pay us for capacity and energy we furnish under their 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 between us and each of our members. 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 standard selling price at which we provide capacity services to our members is determined by our formulary rate on an annual basis. As a result, the consideration we receive for providing capacity services is determined annually. Over the course of a year, our member capacity revenues are relatively stable. Capacity revenues may fluctuate year to year largely due to the recovery of fixed operation and maintenance costs. 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. 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 significant 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. We do not provide all 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 2018 and 2017, our board approved a targeted margins for interest ratio of 1.14 and for years 2018 and 2017, we achieved a 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 if a refund to our members of excess consideration is likely. If required, 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. At December 31, 2018 and 2017, we recognized refund liabilities totaling $30,870,000 and $29,149,000, respectively that were applied to our members’ bills in January 2019. Based on our current agreements with non-members, we do not refund any consideration received from non-members.

Sales to members were as follows:


	(dollars in thousands)
	2018		2017			2016
Capacity revenues	$	927,419	$	912,421	$	949,193
Energy revenues		551,960		521,409		557,614
Total	$	1,479,379	$	1,433,830	$	1,506,807

The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2018, 2017 or 2016:


	2018		2017		2016
Jackson EMC	14.1	%	14.7	%	14.3	%
Cobb EMC	13.9	%	14.3	%	13.7	%
Sawnee EMC	n/a		n/a		10.5	%

Sales to non-members during years 2018, 2017 and 2016 were insignificant.

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 2018, 2017 and 2016 were $12,229,000, $11,000,000 and $16,096,000, respectively. The cumulative amount billed since inception of the program totaled $66,316,000.

In 2018, we began an additional rate management program that allows us to recover future expense on a current basis. Our members made a one-time election to participate in this program, which in general, 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 to manage the rate impacts associated with the commercial operation of the new Vogtle units. Participating members were billed $15,435,000 under this program in 2018. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income. Amounts deferred under the program will be amortized to income when applied to members’ bills.

f. Receivables

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, 2018, 2017 and 2016 were $122,888,000, $126,211,000 and $136,552,000, 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.

The remainder of our receivables is primarily related to transactions with affiliated companies and investment income. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period the amounts are determined to be uncollectible.

During 2018 and 2017, no impairment losses were recognized on any receivables that arose from contracts with members or non-members.

g. Nuclear fuel cost

The cost of nuclear fuel is amortized to fuel expense based on usage. The total nuclear fuel expense for 2018, 2017 and 2016 amounted to $85,949,000, $90,520,000, and $83,751,000, respectively.

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.

In 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, 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 $10,949,000, was recognized in our 2015 financial statements. Georgia Power filed additional claims in 2014 (as amended) and 2017 seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering the periods from January 1, 2011 through December 31, 2014 and January 1, 2015 through December 31, 2017, respectively. 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, 2018 for these additional claims. The final outcome of these matters cannot be determined at this time.

Both Plants Hatch and Vogtle have on-site dry spent storage facilities in operation. Facilities at both plants can be expanded to accommodate spent fuel through the expected life of each plant.

h. Asset retirement obligations and other retirement costs

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. 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.

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.

The following table reflects the details of the asset retirement obligations included in the consolidated balance sheets for the years 2018 and 2017.


	(dollars in thousands)
	Nuclear		Coal Ash		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		Other		Total
Balance at December 31, 2016	$	517,565	$	156,465	$	24,021	$	698,051
Liabilities settled		(17)		(943)		(1,185)		(2,145)
Accretion		31,026		4,629		1,019		36,674
Change in cash flow estimates		—		1,604		813		2,417
Balance at December 31, 2017	$	548,574	$	161,755	$	24,668	$	734,997

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 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. The increase in the cash flow estimates in 2018 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 were as follows:


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

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 Ash. On April 17, 2015 the Environmental Protection Agency published its final coal combustion residuals (CCR) rule which regulates CCRs as non-hazardous materials under Subtitle D of the Resource Conservation and Recovery Act. The rule took effect on October 19, 2015. Our most recent assessment of the coal ash asset retirement obligation resulted in a $161,303,000 increase in the obligation for coal ash decommissioning. 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. The 2018 increase in cash flow estimates 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 have internally segregated the funds collected for coal ash pond and landfill decommissioning costs, including earnings thereon. As of December 31, 2018 and December 31, 2017 the fund balances were $60,599,000 and $41,844,000, respectively

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.

Other. 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.

i. Nuclear decommissioning funds

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 2018 and 2017, 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 2018 and 2017, 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, 2018 and December 31, 2017. The funds are invested in a diversified mix of approximately 60% equity and 40% fixed income securities for both 2018 and 2017.


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

⁽¹⁾

Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $4,786,000.


	2018
Internal Funds:
	Cost				Net		Unrealized		Fair Value
	12/31/2017		Purchases		Proceeds(1)		Gain(Loss)		12/31/2018
Equity	$	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

⁽¹⁾

Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $689,000.


	2017
External Trust Funds:
	Cost				Net		Unrealized		Fair Value
	12/31/2016		Purchases		Proceeds(1)		Gain(Loss)		12/31/2017
Equity	$	200,595	$	61,406	$	(44,607)	$	76,221	$	293,615
Debt		148,011		388,609		(384,199)		170		152,591
Other		351		98		(1,600)		—		(1,151)
	$	348,957	$	450,113	$	(430,406)	$	76,391	$	445,055

⁽¹⁾

Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $19,707,000.


	2017
Internal Funds:
	Cost				Net		Unrealized		Fair Value
	12/31/2016		Purchases		Proceeds(1)		Gain(Loss)		12/31/2017
Equity	$	38,798	$	—	$	4,900	$	11,669	$	55,367
Debt		26,207		73,153		(65,820)		—		33,540
	$	65,005	$	73,153	$	(60,920)	$	11,669	$	88,907

⁽¹⁾

Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $12,232,800.

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 7.7% in the last ten years and 5.8% 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.

j. Depreciation

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 2018, 2017 and 2016 were as follows:


	Range of
	Useful Life in
	years*	2018		2017		2016
Steam production	49-65	2.57	%	2.91	%	2.84	%
Nuclear production	37-60	1.92	%	1.96	%	1.96	%
Hydro production	50	2.00	%	2.00	%	2.00	%
Other production	30-35	2.61	%	2.58	%	2.55	%
Transmission	36	2.75	%	2.75	%	2.75	%
General	3-50	2.00-33.33	%	2.00-33.33	%	2.00-33.33	%

*Calculated based on the composite depreciation rates in effect for 2018.

Depreciation expense for the years 2018, 2017 and 2016 was $227,213,000, $218,027,000, and $211,282,000, respectively.

k. Electric plant

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 ended 2018, 2017 and 2016, the allowance for funds used during construction rates were 4.25%, 4.45% and 4.61%, 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.

l. Cash and cash equivalents

We consider all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents. Temporary cash investments with maturities at the time of purchase of more than three months are classified as short‑term investments.

m. Restricted investments

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, 2018 and 2017, we had restricted investments totaling $653,158,000 and $882,909,000, respectively, of which $503,158,000 and $653,585,000, 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.

n. Inventories

We maintain inventories of fossil fuel and spare parts, including materials and supplies for our generation plants. These inventories are stated at weighted average cost.

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.

At December 31, 2018 and December 31, 2017, fossil fuels inventories were $48,709,000 and $54,050,000, respectively. Inventories for spare parts at 2018 and 2017 were $210,379,000 and $212,169,000, respectively.

o. Deferred charges and other assets

Other deferred charges primarily represent advance deposits to Georgia Power Company related to the Vogtle construction project and progress payments for equipment associated with future nuclear refueling outages.

For a discussion regarding regulatory assets, see Note 1q.

p. Deferred credits and other liabilities

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 January 2023, with the majority of the balance scheduled to be credited by the end of 2019.

Deferred credits and other liabilities also consists of asset retirement obligations as discussed in Note 1h and regulatory liabilities in Note 1q.

q. Regulatory assets and liabilities

We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates established under the wholesale power contracts we have with each of our members. These contracts extend through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from members.


	2018		2017
	(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	46,315	$	52,989
Amortization on capital leases(b)		34,918		33,846
Outage costs(c)		36,352		40,525
Asset retirement obligations – Ashpond and other(k)		137,835		68,289
Asset retirement obligations – Nuclear(k)		7,031		0
Depreciation expense(d)		41,244		42,667
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(e)		51,549		48,702
Interest rate options cost(f)		116,960		112,102
Deferral of effects on net margin – Smith Energy Facility(g)		160,509		166,454
Other regulatory assets(m)		22,350		19,510
Total Regulatory Assets	$	655,063	$	585,084

Regulatory Liabilities:
Accumulated retirement costs for other obligations(h)	$	13,873	$	12,813
Deferral of effects on net margin – Hawk Road Energy Facility(g)		19,101		19,553
Major maintenance reserve(i)		45,547		47,087
Amortization on capital leases(b)		17,156		20,055
Deferred debt service adder(j)		105,192		95,695
Asset retirement obligations – Nuclear(k)		0		53,571
Revenue deferral plan(l)		15,670		0
Other regulatory liabilities(m)		2,459		2,875
Total Regulatory Liabilities	$	218,998	$	251,649
Net regulatory assets	$	436,065	$	333,435

(a)

Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 25 years.

(b)

Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to capital lease payments and the aggregate of the amortization of the asset and interest on the obligation.

(c)

Consists of both coal‑fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight‑line basis to expense over periods up to 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.

(e)

Deferred charges consist of training related costs, including interest and carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units.

(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 in February 2020 and continue through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project.

(g)

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

(h)

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

(i)

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

(j)

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

(k)

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

(l)

Deferred revenues under a rate management program that allows for additional collections over a five-year period beginning in 2018. These amounts will be amortized to income and applied to member billings over the subsequent five-year period.

(m)

The amortization periods for other regulatory assets range up to 31 years and the amortization periods of other regulatory liabilities range up to 8 years.

r. Related parties

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 2018, 2017, and 2016, we incurred expenses from Georgia Transmission of $30,428,000, $28,410,000, and $27,399,000, 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 2018, 2017, and 2016, we incurred expenses from Georgia Systems Operations of $25,578,000, $25,597,000, and $23,994,000, respectively.

s. Other income

Other income includes net revenue from Georgia Transmission and Georgia Systems Operations for administrative costs, as well as capital credits from investments in associated organizations and other miscellaneous income.

t. Recently issued or adopted 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 expects to be entitled in exchange for those goods and services. In addition, Topic 606 requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers.

We adopted the new revenue standard effective January 1, 2018, using the full retrospective method, which requires us to restate each prior reporting period presented. The most significant impact of the new revenue standard to us relates to the potential recognition of refund liabilities in interim reporting periods. The adoption of the new revenue standard did not change the nature, amounts or timing of revenues we recognize within an annual reporting period and, therefore, restatement of the annual periods was not required. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. For years 2018 and 2017, we recognized refund liabilities totaling $30,870,000 and $29,149,000, respectively. Adoption of the new revenue standard had no impact to cash from or used in operating, financing, or investing on our consolidated cash flows statements.

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 margin. None of the other provisions in this standard will have any impact to our consolidated financial statements. As disclosed within Note 1i, we previously adopted regulatory accounting treatment with respect to unrealized gains and losses on our debt and equity securities within our nuclear decommissioning funds. During the fourth quarter of 2017, we adopted regulatory accounting treatment with respect to unrealized gains and losses on all other equity investments. Upon applying regulatory accounting treatment, unrealized gains on our equity investments are recorded as a regulatory liability and, conversely, unrealized losses on our equity investments are recorded as a regulatory asset, at the end of each reporting period. As of December 31, 2018 and December 31, 2017, we recorded, excluding our regulatory accounting treatment related to our nuclear decommissioning funds, $975,000 and $618,000, respectively, 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 did not have any 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 (Topic 842).” The new leases standard requires a dual approach for lessee accounting under which a lessee would account for leases as finance leases or operating leases. Both finance leases and operating leases will result in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the ROU asset and for operating leases the lessee would recognize a straight-line total lease expense. Quantitative and qualitative disclosures will also be required surrounding significant judgments made by management. The new lease standard does not substantially change lessor accounting. 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.

During 2018, the FASB issued additional guidance related to the new leases standard, including a practical expedient that allows entities to not evaluate existing and expired land easements that were not previously accounted for as leases upon adoption of Topic 842 and an additional transition method that allows entities to not apply the new leases guidance in the comparative periods entities present in their financial statements in the year of adoption.

We have fully completed our implementation of the new leases standard and the adoption of the standard did not have a material impact on our consolidated financial statements. We have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have a minor number of various nominal leases.

We account for the Scherer Unit No. 2 leases as capital leases and the railcar leases as operating leases under the current lease accounting model. The key changes in our adoption of the new leases standard is how we account for our operating leases that are currently off-balance sheet. Our evaluation process included, but was not limited to, reviewing all forms of leases, performing a completeness assessment over the lease population and analyzing the practical expedients available to us.

On January 1, 2019, we adopted the new leases standard using the optional transition method to apply the new lease guidance as of January 1, 2019, rather than as of the earliest period presented. Upon adoption of the new leases standard, we recognized right-of-use assets and offsetting lease liabilities totaling approximately $6,983,000.

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 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. We are currently evaluating the future impact of this standard on our consolidated financial statements.

In March 2018, the FASB issued “Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118.” In accordance with the standard, we recognized the provisional tax impacts related to the re-measurement of our deferred income tax assets and liabilities as of the year ended December 31, 2017. During the year ended December 31, 2018, we finalized our Staff Accounting Bulletin 118 analysis and there was no impact to the results of operations.

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.

As the standard relates only to disclosures, we do not expect the adoption of this standard to have a material impact on our consolidated financial statements. We are currently evaluating the standard and whether we will early adopt the standard.