Summary of significant accounting policies: (Policies)

12 Months Ended

Dec. 31, 2016

Summary of significant accounting policies:

Business description

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 7,809 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 728 megawatts of summer planning reserve capacity. 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.

Basis of accounting

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, 2016 and 2015 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2016. Actual results could differ from those estimates.

Patronage capital and membership fees

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.

Accumulated other comprehensive (deficit) margin

d. Accumulated other comprehensive (deficit) margin

    The table below provides detail regarding the beginning and ending balance for each classification of other comprehensive (deficit) margin along with the amount of any reclassification adjustments included in net margin for each of the years presented in the Statement of Patronage Capital and Membership Fees and Accumulated Other Comprehensive (Deficit) Margin.

    Our effective tax rate is zero; therefore, all amounts below are presented net of tax.

Accumulated Other Comprehensive (Deficit) Margin
		(dollars in thousands)
		Available-for-sale Securities
Balance at December 31, 2013	$	(549	)
Unrealized gain		1,180
(Gain) reclassified to net margin		(163	)
Balance at December 31, 2014		468
Unrealized gain		265
(Gain) reclassified to net margin		(675	)
Balance at December 31, 2015		58
Unrealized loss		(234	)
(Gain) reclassified to net margin		(194	)
Balance at December 31, 2016	$	(370	)

Margin policy

e. 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 2016, 2015 and 2014, we achieved a margins for interest ratio of 1.14.

Operating revenues

f. Operating revenues

    Electricity revenues are recognized when capacity and energy are provided. Operating revenues from sales to members consist primarily of electricity sales pursuant to long-term wholesale power contracts which we maintain with each of our members. These wholesale power contracts obligate each member to pay us for capacity and energy furnished in accordance with rates we establish. Capacity revenues recover our fixed costs plus a targeted margin and are charged regardless of whether our generation and purchased power resources are dispatched to produce electricity. Capacity revenues are based on an annual budget and, notwithstanding budget adjustments to meet our targeted margin, are recorded in approximately equal amounts throughout the year. Energy revenues recover variable costs, such as fuel, incurred to generate or purchase electricity and are recorded such that energy revenues equal the actual energy costs incurred.

    Prior to 2016, operating revenues from sales to non-members consisted primarily of energy sales at Smith.

    The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2016, 2015 or 2014:

	2016		2015		2014
Jackson EMC	14.3	%	9.7	%	10.4	%
Cobb EMC	13.7	%	13.1	%	13.6	%
Sawnee EMC	10.5	%	10.4	%	9.5	%

    We have a rate management program that allows us to expense and recover certain 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 2016, 2015 and 2014 were $16,096,000, $7,630,000 and $6,182,000, respectively. Prior to 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 to our members. Amounts billed to participating members under this program were $17,745,000 and $8,809,000 in 2015 and 2014, respectively.

Receivables

g. Receivables

    A substantial portion of our receivables are related to electricity 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 receivables at December 31, 2016 and 2015 were $136,552,000 and $108,729,000, respectively. The remainder of our receivables is primarily related to transactions with affiliated companies, electricity sales to non-members (2015) and to interest income on investments. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period the amounts are determined to be uncollectible.

Nuclear fuel cost

h. Nuclear fuel cost

    The cost of nuclear fuel is being amortized to fuel expense based on usage. The total nuclear fuel expense for 2016, 2015 and 2014 amounted to $83,751,000, $78,762,000, and $85,166,000, 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.

    On December 14, 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, as agent for the co-owners, to recover spent nuclear fuel storage costs at Plant 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 March 4, 2014, Georgia Power, as agent for the co-owners, filed a separate claim seeking damages for spent nuclear fuel storage costs at Plant Hatch and Vogtle Units No. 1 and No. 2 covering a period of January 1, 2011 through December 31, 2013. The damage period was subsequently amended and now extends through December 31, 2014. 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, 2016 for this claim. 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.

Asset retirement obligations and other retirement costs

i. 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 2015 and 2016, respectively.

    The following table reflects the details of the Asset Retirement Obligations included in the consolidated balance sheets for the years 2016 and 2015.

		(dollars in thousands)
		Nuclear		Coal Ash Pond			Other			Total
Balance at December 31, 2015	$	488,458	$	93,622		$	20,150		$	602,230
Liabilities settled		–		(553	)		(707	)		(1,260	)
Accretion		29,107		2,215			1,039			32,361
Change in Cash Flow Estimates		–		61,181			3,539			64,720
Balance at December 31, 2016	$	517,565	$	156,465		$	24,021		$	698,051

		(dollars in thousands)
		Nuclear		Coal Ash Pond		Other			Total
Balance at December 31, 2014	$	369,046	$	42,609	$	20,605		$	432,260
Liabilities settled		–		–		(299	)		(299	)
Accretion		23,231		1,929		948			26,108
Change in Cash Flow Estimates		96,181		49,084		(1,104	)		144,161
Balance at December 31, 2015	$	488,458	$	93,622	$	20,150		$	602,230

    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. The estimated costs of decommissioning are based on the most current study performed in 2015. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.5%. The increase in the cash flow estimates in 2015 was primarily attributable to security costs, waste disposal costs and inflation, among other factors. Our portion of the estimated costs of decommissioning co-owned nuclear facilities were as follows:

		(dollars in thousands)
2015 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 2015 dollars:
Radiated structures	$	193,000	$	213,000	$	178,000	$	195,000
Spent fuel management		49,000		47,000		49,000		47,000
Non-radiated structures		16,000		22,000		26,000		33,000
Total estimated site study costs	$	258,000	$	282,000	$	253,000	$	275,000

    We have established funds to comply with the Nuclear Regulatory Commission regulations regarding the decommissioning of our nuclear plants. See Note 1j for information regarding the nuclear decommissioning funds.

    Coal Ash Pond.    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 current assessment of the final CCR rule resulted in a $59,472,000 change in cash flow estimates for coal ash pond 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 2016 increase in cash flow estimates was primarily attributed to an increase in the closure cost estimates. The increase in the cash flow estimates in 2015 was a result of changes in the assumptions regarding the timing of expenditures as well as an increase in the cost estimates. Additional adjustments to the asset retirement obligations are expected periodically as we continue to assess the impact of the rule on our estimates and assumptions.

    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 1r.

Nuclear decommissioning funds

j. 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 2016 and 2015, 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, 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.

    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. During 2016 and 2015, member collections of $4,750,000, respectively were contributed into the internal funds.

    The following table outlines the fair value of our nuclear decommissioning funds as of December 31, 2016 and December 31, 2015. The funds are invested in a diversified mix of approximately 60% equity and 40% fixed income securities for both 2016 and 2015.

	2016
External Trust Funds:
		12.31.15 Cost		Purchases		Net Proceeds(1)			Unrealized Gain(Loss)			12.31.16 FV
Equity	$	198,265	$	46,865	$	(43,395	)	$	38,749		$	240,484
Debt		144,187		347,383		(343,040	)		(1,675	)	$	146,855
Other		187		1,258		(2,754	)		(1	)	$	(1,310	)
Total	$	342,639	$	395,506	$	(389,189	)	$	37,073		$	386,029

Internal Funds:
			12.31.15 Cost		Purchases		Net Proceeds(1)			Unrealized Gain(Loss)			12.31.16 FV
Equity		$	33,513	$	0	$	5,285		$	7,263		$	46,061
Debt			25,539		42,783		(42,115	)		(211	)	$	25,996
Total		$	59,052	$	42,783	$	(36,830	)	$	7,052		$	72,057
(1)	Also included in net proceeds are net realized gains or losses, interest income and dividends, contributions and fees of $12,270,144.

	2015
External Trust Funds:
		12.31.14 Cost		Purchases		Net Proceeds(2)			Unrealized Gain(Loss)			12.31.15 FV
Equity	$	183,527	$	104,417	$	(77,504	)	$	23,321		$	233,761
Debt		130,407		454,072		(450,747	)		(2,128	)	$	131,604
Other		324		79		(1,935	)		(4	)	$	(1,536	)
Total	$	314,258	$	558,568	$	(530,186	)	$	21,189		$	363,829

Internal Funds:
			12.31.14 Cost		Purchases		Net Proceeds(2)			Unrealized Gain(Loss)			12.31.15 FV
Equity		$	19,796	$	0	$	13,717		$	4,537		$	38,050
Debt			22,767		82,554		(79,782	)		(263	)	$	25,276
Total		$	42,563	$	82,554	$	(66,065	)	$	4,274		$	63,326
(2)	Also included in net proceeds are net realized gains or losses, interest income and dividends, contributions and fees of $44,871,375.

    Realized and unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings or other comprehensive margin (deficit) 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.

    Since inception in 1990 through 2016, the nuclear decommissioning trust fund has produced an average annualized return of approximately 5.9%. 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 increase in cost estimates of decommissioning can be recovered in future rates.

Depreciation

k. 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 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 depreciation rates in effect in 2016, 2015 and 2014 were as follows:

	Range of Useful Life in years*	2016		2015		2014
Steam production	49-65	2.84	%	1.93	%	1.86	%
Nuclear production	37-60	1.96	%	1.55	%	1.53	%
Hydro production	50	2.00	%	2.00	%	2.00	%
Other production	27-33	2.55	%	2.38	%	2.56	%
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 2016.

    Depreciation expense for the years 2016, 2015 and 2014 was $211,282,000, $180,866,000, and $178,302,000, respectively.

Electric plant

l. 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 2016, 2015 and 2014, the allowance for funds used during construction rates were 4.61%, 4.73% and 4.97%, 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, plus cost of removal, less salvage of such property, is charged to the accumulated provision for depreciation. 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.

Cash and cash equivalents

m. 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.

Restricted cash and investments

n. Restricted cash and investments

    Restricted cash and investments primarily consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted investments can only be utilized for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments; deposits can also be used for debt service payments on direct loans made by the Rural Utilities Service but we no longer have such direct loans. The funds on deposit earn interest at a rate of 5% per annum. At December 31, 2016 and 2015, we had restricted cash and investments totaling $468,179,000 and $387,961,000, respectively, of which $221,122,000 and $134,690,000, respectively was 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.

Inventories

o. 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 based on weighted average cost. 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, 2016 and December 31, 2015, fossil fuels inventories were $57,289,000 and $104,086,000, respectively. Inventories for spare parts at 2016 and 2015 were $202,542,000 and $195,166,000, respectively.

Deferred charges and other assets

p. Deferred charges and other assets

    Prepayments to Georgia Power Company primarily represent progress payments for equipment associated with future nuclear refueling outages.

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

Deferred credits and other liabilities

q. 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 July 2021, with the majority of the balance scheduled to be credited by the end of 2017.

    In connection with the Vogtle Units No. 3 and No. 4 construction project, we are accruing long-term contract retainage amounts for substantial and mechanical milestones that will become due near the anticipated commercial operation dates of the units. For more information regarding the Vogtle construction project, see Note 8.

Regulatory assets and liabilities

r. 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 under the wholesale power contracts with our members, which 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.

		(dollars in thousands)
		2016		2015
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	55,084	$	61,916
Amortization on capital leases(b)		32,274		30,253
Outage costs(c)		39,986		42,027
Interest rate swap termination fees(d)		3,570		5,355
Asset Retirement Obligations – Ashpond and other(l)		33,747		1,098
Depreciation expense(e)		44,091		45,514
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f)		43,444		37,646
Interest rate options cost(g)		107,394		102,554
Deferral of effects on net margin – Smith Energy Facility(h)		172,399		178,343
Other regulatory assets(m)		13,398		25,548
Total Regulatory Assets		545,387		530,254
Regulatory Liabilities:
Accumulated retirement costs for other obligations(i)	$	9,829	$	8,910
Deferral of effects on net margin – Hawk Road Energy Facility(h)		20,163		20,775
Major maintenance reserve(j)		28,379		22,422
Amortization on capital leases(b)		23,084		26,502
Deferred debt service adder(k)		86,082		76,334
Asset retirement obligations – Nuclear(l)		11,766		8,316
Other regulatory liabilities(m)		18,445		3,708
Total Regulatory Liabilities		197,748		166,967
Net regulatory assets	$	347,639	$	363,287

(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 27 years.
(b)	Represents the difference between expense recognized for rate-making purposes and 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 a 24-month period. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 to 24-month operating cycles of each unit.
(d)	Represents losses on settled interest rate swap arrangements that are being amortized through the end of 2018.
(e)	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)	Deferred charges related to Vogtle Units No. 3 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.
(g)	Deferral of net loss associated with the change in fair value and expired cost of interest rate options purchased to hedge interest rates on certain borrowings related to Vogtle Units No.3 and No.4 construction. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project.
(h)	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.
(i)	Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets.
(j)	Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred.
(k)	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.
(l)	Represents difference in timing of recognition of the costs of decommissioning and ashpond remediation for financial statement purposes and for ratemaking purposes.
(m)	The amortization periods for other regulatory assets range up to 33 years and the amortization periods of other regulatory liabilities range up to 10 years.

Related parties

s. 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 own facilities. For 2016, 2015, and 2014, we incurred expenses from Georgia Transmission of $27,399,000, $28,172,000, and $27,893,000, 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 2016, 2015, and 2014, we incurred expenses from Georgia Systems Operations of $23,994,000, $22,616,000, and $23,351,000, respectively.

Other income

t. Other income

    The components of other income within the Consolidated Statement of Revenues and Expenses were as follows:

		(dollars in thousands)
		2016			2015		2014
Capital credits from associated companies (Note 4)	$	1,679		$	1,859	$	1,986
Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs		6,553			6,278		4,944
Miscellaneous other		(5,561	)		1,006		(310	)
Total	$	2,671		$	9,143	$	6,620

New accounting pronouncements

u. 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 expects to be entitled in exchange for those goods and services. The standard was effective for the annual reporting period beginning after December 15, 2016 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the 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). Early adoption was not permitted.

    In August 2015, the FASB issued an update to Topic 606 deferring the effective date by one year. The standard is effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. The standard also permits early adoption of the standard, but not before the original effective date of December 15, 2016.

    While we expect that the majority of our revenues will be included in the scope of Topic 606, we have not fully completed our evaluation of the new revenue standard. Our evaluation process includes, but is 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. A large majority of our revenues 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. However, we continue to evaluate the effects, if any, of Topic 606 on our interim period revenues as it relates to budget adjustments, which may be made during the year that affect our annual revenue requirement. We also continue to evaluate other revenue streams and the related contracts, as well as monitor issues specific to the power and utilities industry. As the ultimate impact of the new revenue standard has not yet been determined, we have not elected our transition method.

    In July 2015, the FASB issued "Inventory (Topic 330): Simplifying the Measurement of Inventory." Under the new inventory standard, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal, and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could be replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventory measured using the last-in, first-out or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first out or average cost, the method used to measure all of our inventories. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted as of the beginning of an interim or annual reporting period. As permitted, on April 1, 2016, we early adopted these amendments and applied their provisions prospectively. The adoption of this amendment did not have a material impact on our consolidated financial statements.

    In November 2015, the FASB issued "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes." The amendments in this standard simplifies the presentation of deferred income taxes by eliminating the separate classification of deferred income tax assets and liabilities into current and noncurrent amounts in the statement of financial position. The amendments in the update require that all deferred tax assets and liabilities be classified as noncurrent in the consolidated balance sheets. The new standard is effective for us either prospectively or retrospectively for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted as of the beginning of an interim or annual reporting period. As permitted, on October 1, 2016, we early adopted these amendments and applied their provisions retrospectively. There was no impact to our consolidated financial statements as a result of the adoption of this standard.

    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 sheets of the fiscal year of adoption and certain provisions should be applied prospectively. We are currently evaluating the future impact of this standard on our consolidated financial statements.

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

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

    In August 2016, 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 should 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. We are currently evaluating the future impact of this standard on our consolidated financial statements.

    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. Our restricted cash balances are nominal and accordingly we do not expect the adoption of this standard to have a material impact on our consolidated financial statements.