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, GA that operates on a not-for-profit basis. We are owned by 38 retail electric distribution cooperative members in Georgia. The wholesale electric power we provide consists of a combination of generating units totaling 6,844 megawatts of nameplate capacity. 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 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, 2012 and 2011 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2012. 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 $195 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 the 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. Accumulated 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, 2009	$	(1,253	)
Unrealized gain		784

Balance at December 31, 2010		(469	)
Unrealized gain		1,087

Balance at December 31, 2011		618
Unrealized gain		285

Balance at December 31, 2012	$	903

e. Margin policy

We are required under the first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For the years 2012, 2011 and 2010, we achieved a margins for interest ratio of 1.14.

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. Energy provided is determined based on meter readings which are conducted at the end of each month. Actual energy costs are compared, on a monthly basis, to the billed energy costs, and an adjustment to revenues is made such that energy revenues are equal to actual energy costs.

Operating revenues from sales to non-members consists of capacity and energy sales to Georgia Power Company, as well as energy sales to other non-members. These capacity and energy sales are primarily associated with the Thomas A. Smith Energy Facility, formerly known as the Murray Energy Facility, which we acquired in April 2011. The agreement with Georgia Power, which was for the sale of the entire output of Unit No. 1 of Smith, expired on May 31, 2012. For further discussion of the Smith acquisition, see Note 14.

The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2012, 2011 and 2010:



	2012		2011		2010

Cobb EMC	12.8	%	12.5	%	14.5	%
Jackson EMC	11.9	%	10.9	%	11.6	%
Sawnee EMC⁽¹⁾	n/a		n/a		10.6	%

(1): In 2012 and 2011, Sawnee accounted for less than 10% of our total operating revenues.

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 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 plans 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 2011 and 2012 were $5,436,000 and $26,149,000, respectively.

g. Receivables

A substantial portion of our receivables are related to electricity sales to our members. 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, 2012 and 2011 were $109,673,000 and $108,920,000, 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.

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 2012, 2011 and 2010 amounted to $81,723,000, $74,814,000, and $65,916,000, 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 a second claim filed in 2008 against the Department of Energy by Georgia Power as agent for the co-owners, damages for nuclear fuel spent storage costs at Hatch and Vogtle Units No. 1 and No. 2 are being sought for the period of January 2005 through December 2010. No amounts have been recognized in the financial statements as of December 31, 2012 for the second claim. The final outcome of this matter cannot be determined at this time.

An on-site dry storage facility for Hatch is operational and can be expanded to accommodate spent fuel through the life of the plant. Sufficient storage capacity is available at Plant Vogtle in the spent fuel pools to maintain full core discharge capacity for both units into 2014. Construction of an on-site dry storage facility at Vogtle Units No.1 and No. 2 has commenced to ensure that we maintain spent fuel pool full-core discharge capability beyond 2014.

i. Asset retirement obligations and other retirement costs

Asset retirement obligations are computed as the present value of the 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, 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 decommissioning for financial statement purposes and for ratemaking purposes. We estimate an annual increase of approximately $200,000 over the next several years to the regulatory asset. For information regarding the regulatory asset 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 2012 and 2011.



		(dollars in thousands)
		2012			2011

Balance at beginning of year	$	298,758		$	280,496
Liabilities incurred		1,632			423
Liabilities settled		(1,117	)		(410	)
Accretion		19,554			18,249
Change in Cash Flow Estimate		62,535			–

Balance at end of year	$	381,362		$	298,758

Accounting standards for asset retirement and environmental obligations does 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.

j. Nuclear decommissioning trust fund

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 during the years 2012, 2011 and 2010 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 2012, the nuclear decommissioning trust fund has produced an average annualized return of approximately 7.1%. 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.

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 2012, 2011 and 2010 were as follows:



	Range of Useful Life in years*	2012	2011	2010

Steam production	49-65	1.85%	1.88%	1.56%
Nuclear production	37-60	1.54%	1.45%	1.50%
Hydro production	50	2.00%	2.00%	2.00%
Other production	27-33	2.74%	2.74%	2.60%
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 2012.

Depreciation expense for the years 2012, 2011 and 2010 was $164,901,000, $165,603,000, and $161,395,000, respectively.

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 2012, 2011 and 2010, the allowance for funds used during construction rates were 5.12%, 5.55% and 5.73%, 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.

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 of more than three months are classified as other short-term investments.

n. Restricted cash

At December 31, 2012, we had restricted cash totaling $9,109,000 of which $8,953,000 was classified as long-term. The long-term restricted cash balance at December 31, 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.

o. Restricted short-term investments

At December 31, 2012 and 2011, we had $64,671,000 and $106,676,000, 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.

p. Inventories

We maintain inventories of fossil fuels and spare parts 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, 2012 and 2011, fossil fuels inventories were $94,491,000 and $94,872,000, respectively. Inventories for spare parts at December 31, 2012 and 2011 were $169,458,000 and $151,923,000, respectively.

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, 2012, the remaining amortization periods for debt issuance costs range from approximately 1 to 38 years.

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, 2012, member power bill prepayments as reflected on the consolidated balance sheets, including unpaid discounts, were $105,932,000, of which, $65,079,000 is classified as a current liability and $40,853,000 as deferred credits and other liabilities. The prepayments are being applied against members' power bills through November 2017, with the majority of the remaining balance scheduled to be applied by the end of 2013.

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.

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 extending 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, 2012 and 2011:



		(dollars in thousands)
		2012		2011

Regulatory Assets:
Premium and loss on reacquired debt	$	86,319	$	98,538	(a)
Amortization on capital leases		28,670		46,627	(b)
Outage costs		30,901		42,866	(c)
Interest rate swap termination fees		17,326		21,316	(d)
Asset retirement obligations		11,382		29,341	(e)
Depreciation expense		49,785		51,209	(f)
Vogtle Units No. 3 and No. 4 training costs		23,030		17,602	(g)
Interest rate options cost		75,716		30,735	(h)
Effects on net margin- Smith Energy Facility		21,394		3,536	(i)
Other regulatory assets		8,379		9,777	(j)

Total Regulatory Assets	$	352,902	$	351,547
Regulatory Liabilities:
Accumulated retirement costs for other obligations	$	28,846	$	32,687	(e)
Net benefit of Rocky Mountain transactions		4,303		47,783	(k)
Effects on net margin- Hawk Road Energy Facility		17,113		15,811	(i)
Major maintenance sinking fund		30,948		28,524	(l)
Debt service adder		47,486		37,586	(m)
Other regulatory liabilities		1,289		1,609	(j)

Total Regulatory Liabilities	$	129,985	$	164,000
Net regulatory assets	$	222,917	$	187,547

(a): Represents premiums paid, together with unamortized transaction costs related to reacquired debt 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 amount paid 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 (gain) 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 the construction project.
(i): Effects on net margin for Smith and Hawk Road Energy Facilities will be deferred until the end of 2015 and amortized over the remaining life of each plant.
(j): The amortization period for other regulatory assets range up to 36 years and the amortization period of other regulatory liabilities range up to 8 years.
(k): Net benefit associated with Rocky Mountain lease transactions is amortized to income over the 30-year lease-back period. For a discussion of Rocky Mountain leases, see Note 4.
(l): Represents collections for future major maintenance costs; revenues to be recognized as major maintenance costs are incurred.
(m): 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.

t. Other income

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



		(dollars in thousands)
		2012		2011		2010

Capital credits from associated companies (Note 4)	$	1,919	$	2,095	$	2,096
Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs		4,280		4,071		3,834
Miscellaneous other		214		38		(564	)

Total	$	6,413	$	6,204	$	5,366

u. Presentation

Certain prior year amounts have been reclassified to conform with the current year presentation.

v. New accounting pronouncements

In May 2011, the Financial Accounting Standards Board issued "Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards." The amendments change the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements, but generally do not result in a change in the application of ASC 820 "Fair Value Measurements." These changes were effective for us on January 1, 2012. Our adoption of this standard did not have a material effect on our consolidated financial statements.

In June 2011, the FASB issued "Comprehensive Income (Topic 220) Presentation of Financial Statements" which amended certain provisions of ASC 220 "Comprehensive Income." These provisions change the presentation requirements for other comprehensive income and total comprehensive income and require one continuous statement or two separate but consecutive statements. Presentation of other comprehensive income in the statement of stockholders' equity is no longer permitted. These provisions are effective for fiscal and interim periods beginning after December 15, 2011. The adoption of these provisions did not have a material effect on our consolidated financial statements.

In December 2011, the 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. This guidance is effective for our fiscal year ending December 31, 2013. We do not expect the adoption of this standard to have a material impact on our consolidated financial statements.