Summary of significant accounting policies: (Policies)

12 Months Ended

Dec. 31, 2013

Summary of significant accounting policies:

Basis of accounting

b. Basis of accounting

    Our consolidated financial statements include our accounts and the accounts of our majority-owned and controlled subsidiaries. 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, 2013 and 2012 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2013. 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 revenue over expenditures from operations is treated as advances of capital by our members and is allocated to each of them on the basis of their fixed percentage capacity cost responsibilities in our generation and purchased power resources.

    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 margin (deficit)

d. Accumulated other comprehensive margin (deficit)

    The table below provides detail regarding the beginning and ending balance for each classification of other comprehensive margin (deficit) 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 Margin (Deficit). Our effective tax rate is zero; therefore, all amounts below are presented net of tax.

Accumulated Other Comprehensive Margin (Deficit)
		(dollars in thousands)
		Available-for-sale Securities
Balance at December 31, 2010	$	(469	)
Unrealized gain		1,461
(Gain) reclassified to net margin		(374	)
Balance at December 31, 2011		618
Unrealized gain		770
(Gain) reclassified to net margin		(485	)
Balance at December 31, 2012		903
Unrealized (loss)		(1,396	)
(Gain) reclassified to net margin		(56	)
Balance at December 31, 2013	$	(549	)

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 2013, 2012 and 2011, we achieved a margins for interest ratio of 1.14.

Operating revenues

f. Operating revenues

    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. Electricity revenues are recognized when capacity and energy are provided. 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 equally 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.

    Operating revenues from sales to non-members consists primarily of capacity and energy sales at Smith. During 2013, energy sales accounted for all sales to non-members. In 2012, non-member sales were comprised of capacity and energy sales to Georgia Power Company, as well as energy sales to other non-members. We acquired Smith in April 2011 and the acquisition included a power purchase and sale agreement with Georgia Power that expired on May 31, 2012. For further discussion of the Smith acquisition, see Note 13.

    The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2013, 2012 and 2011:

	2013		2012		2011
Cobb EMC	13.2	%	12.8	%	12.5	%
Jackson EMC	10.9	%	11.9	%	10.9	%

(1)

None of our other members accounted for 10% or more of our total operating revenues in 2013, 2012 or 2011.

    In 2011, the Rural Utilities Service approved a rate change that permitted us to implement two rate management programs that allow us to expense and recover certain costs on a current basis that would otherwise be deferred or capitalized. The subscribing members of Smith and/or Vogtle Units No. 3 and No. 4, can elect to participate in one, both or neither of these two programs on an annual basis. The Smith program allows for the accelerated recovery of deferred net costs related to Smith. The Smith program became effective December 31, 2011. 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. This program became effective January 1, 2012. Under these programs, amounts billed to our members in 2013, 2012 and 2011 were $13,962,000, $26,149,000 and $5,436,000, 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. Member receivables at December 31, 2013 and 2012 were $117,287,000 and $109,673,000, respectively. The remainder of our receivables is primarily related to transactions with affiliated companies, electricity sales to non-members and to interest income on investments. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period determined to be uncollectible.

Nuclear fuel cost

h. Nuclear fuel cost

    The cost of nuclear fuel, including a provision for the disposal of spent fuel, is being amortized to fuel expense based on usage. The total nuclear fuel expense for 2013, 2012 and 2011 amounted to $86,828,000, $81,723,000, and $74,814,000, respectively.

    Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at 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 April 5, 2012, the U.S. Court of Federal Claims issued a final order for judgment in favor of Georgia Power in a lawsuit seeking damages for nuclear fuel spent storage costs incurred at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 from 1998 through 2004. Our ownership share of the $54,017,000 total award was $16,205,000. The judgment was recorded in June 2012 and resulted in a $9,679,000 reduction in total operating expenses and a $6,526,000 reduction to plant in service.

    In subsequent claims filed against the Department of Energy by Georgia Power as agent for the co-owners, damages for spent nuclear fuel storage costs at Hatch and Vogtle Units No. 1 and No. 2 are being sought for the period of January 2005 through December 2013. No amounts have been recognized in the financial statements as of December 31, 2013 for these claims. The final outcome of these matters cannot be determined at this time.

    An on-site dry storage facility at Vogtle Units No. 1 and No. 2 began operation in October 2013. At Hatch, an on-site dry spent fuel storage facility is also operational. 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 represent the present value of the estimated costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The liability we recognized primarily relates to decommissioning at our nuclear facilities. In addition, we have retirement obligations related to ash ponds, gypsum, landfill sites and asbestos removal.

    Under the accounting provisions for regulated operations, we record an offsetting regulatory asset or liability to reflect the difference in timing of recognition of the costs of nuclear decommissioning for financial statement purposes and for ratemaking purposes. For information regarding the regulatory asset or liability for asset retirement obligations, see Note 1s.

    In December 2012, we obtained revised asset retirement obligation studies associated with nuclear decommissioning at Hatch Unit No. 1 and No. 2, Vogtle Unit No. 1 and No. 2 and the decommissioning of ash ponds at Plants Scherer and Wansley. The change in cash flow estimates for both nuclear and ash pond decommissioning are reflected in the table below. For information regarding 2012 site studies associated with nuclear decommissioning, see Note 1j.

    The following tables reflect the details of the Asset Retirement Obligations included in the balance sheets for the years 2013 and 2012.

		(dollars in thousands)
		2013			2012
Balance at beginning of year	$	381,362		$	298,758
Liabilities incurred		–			1,632
Liabilities settled		(1,392	)		(1,117	)
Accretion		22,900			19,554
Change in Cash Flow Estimates		5,180			62,535
Balance at end of year	$	408,050		$	381,362

    Accounting standards for asset retirement and environmental obligations do not permit non-regulated entities to accrue future retirement costs associated with long-lived assets for which there are no legal obligations to retire. In accordance with regulatory treatment of these costs, we continue to recognize the retirement costs for these other obligations in depreciation rates. For information regarding accumulated retirement costs for other obligations, see Note 1s.

Nuclear decommissioning

j. Nuclear decommissioning

    The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. We have established external trust funds to comply with the NRC's regulations. The funds set aside for decommissioning 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. The funds are invested in a diversified mix of equity and fixed income securities. We have limited oversight of the day-to-day management of the fund investments.

    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. Unrealized gains and losses of the nuclear decommissioning trust fund 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 for asset retirement obligations in accordance with our rate-making treatment. Realized gains and losses on the nuclear decommissioning trust fund are also recorded to the regulatory asset.

    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. Actual decommissioning costs may vary from these estimates because of 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 2012. Our portion of the estimated costs of decommissioning co-owned nuclear facilities were as follows:

		(dollars in thousands)
2012 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 2012 dollars	$	186,000	$	252,000	$	182,000	$	241,000

    We have not collected any provision for decommissioning 2013, 2012 and 2011 because the balance in the decommissioning trust fund is expected to be sufficient to fund the nuclear decommissioning obligation in future years. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.4%. We assume a 6.0% earnings rate for our decommissioning trust fund assets. Since inception (1990) to 2013, the nuclear decommissioning trust fund has produced an average annualized return of approximately 7.5%. Notwithstanding the results of the revised site studies, 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. The depreciation rates for steam and nuclear below reflect revised rates from 2011 depreciation rate studies. Annual depreciation rates, as approved by the Rural Utilities Service, in effect in 2013, 2012 and 2011 were as follows:

	Range of Useful Life in years*	2013		2012		2011
Steam production	49-65	1.82	%	1.85	%	1.88	%
Nuclear production	37-60	1.54	%	1.54	%	1.45	%
Hydro production	50	2.00	%	2.00	%	2.00	%
Other production	27-33	2.55	%	2.74	%	2.74	%
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 2013.

    Depreciation expense for the years 2013, 2012 and 2011 was $171,240,000, $164,901,000, and $165,603,000, 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, 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 2013, 2012 and 2011, the allowance for funds used during construction rates were 4.93%, 5.12% and 5.55%, respectively.

    Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to expense. Replacements and renewals of items considered to be units of property 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.

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 other short-term investments.

Restricted cash

n. Restricted cash

    At December 31, 2013 and 2012, we had restricted cash totaling $35,131,000 and $9,109,000, respectively, of which $34,975,000 and $8,953,000, respectively was classified as long-term. The long-term restricted cash balance at December 31, 2013 and 2012 consisted of funds posted as collateral by counterparties to our interest rate options. See Note 3 for a discussion of our interest rate options.

Restricted short-term investments

o. Restricted short-term investments

    At December 31, 2013 and 2012, we had $272,686,000 and $64,671,000, respectively, on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted funds can only be utilized for future Rural Utilities Service/Federal Financing Bank debt service payments. The deposit earns interest at a Rural Utilities Service guaranteed rate of 5% per annum.

Inventories

p. 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 on the accompanying balance sheets.

    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. Spare parts are charged to inventory when purchased and then expensed or capitalized, as appropriate, when installed. The spare parts inventory is carried at weighted average cost and the parts are charged to expense or capital at weighted average cost.

    At December 31, 2013 and 2012, fossil fuels inventories were $124,359,000 and $94,491,000, respectively. Inventories for spare parts at December 31, 2013 and 2012 were $161,808,000 and $169,458,000, respectively.

Deferred charges and other assets

q. Deferred charges and other assets

    We account for debt issuance costs as deferred debt expense. Deferred debt expense is amortized to expense on a straight-line basis over the life of the respective debt issues, which approximates the effective interest rate method. As of December 31, 2013, the remaining amortization periods for debt issuance costs range from approximately 1 to 37 years.

Deferred credits and other liabilities

r. 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 and are recorded as a reduction to member revenues. At December 31, 2013, member power bill prepayments as reflected on the consolidated balance sheets, including unpaid discounts, were $114,718,000, of which, $82,405,000 is classified as a current liability and $32,313,000 as deferred credits and other liabilities. The prepayments are being applied against members' power bills through January 2018, with the majority of the remaining balance scheduled to be applied by the end of 2014.

    We have recorded a liability for a power sale agreement assumed in conjunction with the Hawk Road acquisition in May 2009. The liability is being amortized over the remaining life of the agreement which ends in 2015.

Regulatory assets and liabilities

s. 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.

    The following regulatory assets and liabilities are reflected on the accompanying balance sheets as of December 31, 2013 and 2012:

		(dollars in thousands)
		2013		2012
Regulatory Assets:
Premium and loss on reacquired debt	$	82,499	$	86,319	(a)
Amortization on capital leases		16,124		28,670	(b)
Outage costs		35,155		30,901	(c)
Interest rate swap termination fees		13,336		17,326	(d)
Asset retirement obligations		–		11,382	(e)
Depreciation expense		48,362		49,785	(f)
Vogtle Units No. 3 and No. 4 training costs		27,678		23,030	(g)
Interest rate options cost		38,984		75,716	(h)
Effects on net margin – Smith Energy Facility		63,491		21,394	(i)
Other regulatory assets		5,479		8,379	(j)
Total Regulatory Assets		331,108		352,902
Regulatory Liabilities:
Accumulated retirement costs for other obligations	$	24,520	$	28,846	(e)
Effects on net margin – Hawk Road Energy Facility		23,379		17,113	(i)
Major maintenance sinking fund		28,064		30,948	(k)
Debt service adder		57,223		47,486	(l)
Asset retirement obligations		19,508		–	(e)
Other regulatory liabilities		6,095		5,592	(j)
Total Regulatory Liabilities		158,789		129,985
Net regulatory assets	$	172,319	$	222,917

(a)

Represents premiums paid, together with unamortized transaction costs related to reacquired debt being amortized over the period of the refunding debt, which range up to 30 years.

(b)

See Note 6 under "Capital Leases." Recovered over the remaining life of the leases through 2031.

(c)

Consists of both coal-fired and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over an 18 to 36-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 swaps arrangements that are being amortized through 2016 and 2019.

(e)

See Note 1i under "Asset retirement obligations" for a discussion of the asset retirement obligation deferral and recovery and retirement costs for other obligations.

(f)

Prior to 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.

(g)

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 over the life of the units.

(h)

Deferral of net loss associated with the change in fair value of the interest rate options to hedge interest rates on a portion of expected borrowings related to Plant Vogtle Units No.3 and No.4 construction. Amortization will commence effective with the expected principal repayment of the DOE-guaranteed loan and amortized over the expected remaining life of DOE-guaranteed loan which will finance a portion of the construction project.

(i)

Effects on net margin for Smith and Hawk Road Energy Facilities are deferred until the end of 2015 and will be amortized over the remaining life of each plant.

(j)

The amortization periods for other regulatory assets range up to 35 years and the amortization periods of other regulatory liabilities range up to 18 years.

(k)

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

(l)

Collections to fund debt payments in excess of depreciation expense through the end of 2025; deferred revenues will be amortized over the remaining useful life of the plants.

Other income

t. Other income

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

		(dollars in thousands)
		2013			2012		2011
Capital credits from associated companies (Note 4)	$	1,954		$	1,919	$	2,095
Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs		4,459			4,280		4,071
Miscellaneous other		(723	)		214		38
Total	$	5,690		$	6,413	$	6,204

New accounting pronouncements

u. New accounting pronouncements

    In December 2011, the Financial Accounting Standards Board (FASB) issued "Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities," which modifies the disclosure requirements for offsetting financial instruments and derivative instruments. The update requires an entity to disclose information about offsetting and related arrangements and the effect of those arrangements on its financial position. The adoption of this standard was effective for us January 1, 2013 and did not have an impact on our consolidated financial statements.

    In February 2013, the FASB issued "Comprehensive Income (Topic 220): Reporting Amounts Reclassified out of Accumulated Other Comprehensive Income," which amended certain provisions of ASC 220 "Comprehensive Income." The update requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective items on the income statement for reclassified amounts that are required by U.S. GAAP to be reclassified entirely to net income. The update also requires additional footnote disclosures for reclassified amounts that are not required by U.S. GAAP to be reclassified entirely to net income. The adoption of this standard did not have a material impact on our consolidated financial statements.

Fair value of financial instruments

Fair Value:

    Authoritative guidance regarding fair value measurements for financial and non-financial assets and liabilities defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements.

    The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows:

•

Level 1.  Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded.

•

Level 2.  Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs.

•

Level 3.  Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs.

    Assets and liabilities measured at fair value are based on one or more of the following three valuation techniques:

• (1)

  Market approach.  The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business) and deriving fair value based on these inputs.
  
  

  (2)

  Income approach.  The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.
  
  

  (3)

  Cost approach.  The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). This approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset or comparable utility adjusted for obsolescence.

Derivatives

Derivative instruments:

    Our risk management and compliance committee provides general oversight over all risk management and compliance activities, including but not limited to, commodity trading, investment portfolio management and interest rate risk management. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. Prior to December 2012, our commodity trading derivatives were designated as hedging instruments under authoritative guidance for accounting for derivatives and hedging. In December 2012, we discontinued hedge accounting for these derivatives and began applying regulatory accounting. Consistent with our rate-making, unrealized gains or losses on natural gas swaps are reflected as a regulatory asset or liability. To hedge the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, we have entered into interest rate options. Hedge accounting is not applied to our interest rate options. Consistent with our rate-making, unrealized gains or losses from the interest rate options are recorded as a regulatory asset. Within our nuclear decommissioning trust fund, derivatives including options, swaps and credit default swaps which are non-speculative, could be utilized to mitigate volatility associated with duration, default, yield curve and the interest rate risks of the portfolio. Consistent with our rate-making, unrealized gains or losses related to the decommissioning trust funds are recorded as an increase or decrease in the associated regulatory asset or liability. We do not hold or enter into derivative transactions for trading or speculative purposes.

Investments

Investments:

Investments in debt and equity securities

    Investment securities we hold are classified as available-for-sale. Available-for-sale securities are carried at market value with unrealized gains and losses, net of any tax effect, added to or deducted from patronage capital, except that, in accordance with our rate-making treatment, unrealized gains and losses from investment securities held in the nuclear decommissioning trust fund are directly added to or deducted from the regulatory asset for asset retirement obligations. Realized gains and losses on the nuclear decommissioning trust fund are also recorded to the regulatory asset. All realized and unrealized gains and losses are determined using the specific identification method. Approximately 73% of these gross unrealized losses were in effect for less than one year.

Income taxes

Income taxes:

    While we are a not-for-profit membership corporation formed under the laws of Georgia, we are subject to federal and state income taxation. As a taxable cooperative, we are allowed to deduct patronage dividends that we allocate to our members for purposes of calculating our taxable income. We annually allocate income and deductions between patronage and non-patronage activities and substantially all of our income is from patronage-sourced activities, resulting in no current period income tax expense or current income tax liability.

    Although we believe that treatment of non-member sales as patronage-sourced income is appropriate, this treatment has not been examined by the Internal Revenue Service. If this treatment was not sustained, we believe that the amount of taxes on such non-member sales, after allocating related expenses against the revenues from such sales, would not have a material adverse effect on financial condition or results of operations and cash flows.

    We account for income taxes pursuant to the authoritative guidance for accounting for income taxes, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns.