Oglethorpe Power Corporation is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, GA. We are owned by 39 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.

In December 2009, Flint EMC became our 39^th member. Flint did not have a percentage capacity responsibility from any of our generation resources in 2011; however, it has the right to participate in any future generation resources we may acquire or construct.

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 provisions 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, 2011 and 2010 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2011. Actual results could differ from those estimates.

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 costs 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.

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, 2008	$	(1,348	)
Unrealized gain		95

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

We are required under the first mortgage indenture to produce a margins for interest ratio of at least 1.10. For the years 2011, 2010 and 2009, we achieved a margins for interest ratio of 1.14, 1.14 and 1.12, respectively.

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 consist primarily of capacity and energy sales to Georgia Power Company under an agreement to sell the entire output of Murray Unit No. 1 through May 31, 2012, which was acquired in April 2011. In addition, we sold energy generated at Murray Unit No. 2 to non-members. For further discussion of the Murray Energy Facility acquisition, see Note 12a.

The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2011, 2010 and 2009:

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 Murray and/or Plant 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 Murray program allows for the accelerated recovery of deferred net costs related to Murray. The Murray program became effective December 31, 2011 and the amount expensed and billed to members in 2011 was immaterial. The Vogtle program allows for the recovery of financing costs associated with the construction of Plant Vogtle Units No. 3 and No.4 on a current basis. This program became effective January 1, 2012.

A substantial portion of our receivables are related to electricity sales to our members. The 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. 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.

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 2011, 2010 and 2009 amounted to approximately $74,814,000, $65,916,000, and $52,163,000, 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, is pursuing legal remedies against the Department of Energy for breach of contract. An on-site dry storage facility for Plant 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 Plant Vogtle Units No.1 and No.2 is expected to begin in sufficient time to maintain pool full-core discharge capability.

On July 9, 2007, the U.S. Court of Federal Claims found in favor of Southern Company and awarded damages in the amount of $59,900,000 for Plant Hatch and Plant Vogtle. Our share of the award is $17,980,000. The decision has been appealed by the Department of Energy. No amounts have been recognized in the financial statements as of December 31, 2011. The final outcome of this matter cannot be determined at this time. Our rate-making treatment of any such future award received would be passed on to our members.

The accounting and reporting for asset retirement obligations are done under the authoritative guidance related to asset retirement obligations. The liability recognized primarily relates to our nuclear facilities. We also recognized retirement obligations for ash ponds, landfill sites, asbestos removal and gypsum.

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 decrease of approximately $800,000 over the next several years to the regulatory asset. For information regarding the regulatory asset for asset retirement obligations, see Note 1s.

Accounting for asset retirement 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.

In December 2009, we obtained revised asset retirement obligations studies associated with decommissioning at Plants Hatch and Vogtle. The studies were based on the completed plant decommissioning cost estimates and were in accordance with the standards defined in the accounting guidance related to asset retirement obligations. The 2009 studies resulted in a change in the cash flow estimates of nuclear decommissioning costs as noted in the following table.

The following tables reflect the details of the Asset Retirement Obligations included in the balance sheets for the years 2011 and 2010.



		(dollars in thousands)
		Balance at 12/31/10		Liabilities Incurred (Settled)			Accretion		Change in Cash Flow Estimate			Balance at 12/31/11

Nuclear decommissioning	$	272,197	$	–		$	17,616	$	–		$	289,813
Other		8,299		13			633		–			8,945

Total	$	280,496	$	13		$	18,249	$	–		$	298,758



		(dollars in thousands)
		Balance at 12/31/09		Liabilities Incurred (Settled)			Accretion		Change in Cash Flow Estimate			Balance at 12/31/10

Nuclear decommissioning	$	255,654	$	–		$	16,543	$			$	272,197
Other		8,981		(1,201	)		588		(69	)		8,299

Total	$	264,635	$	(1,201	)	$	17,131	$	(69	)	$	280,496

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 Nuclear Regulatory Commission'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. Information with respect to our portion of the estimated costs of decommissioning co-owned nuclear facilities is as follows:

We have not collected any provision for decommissioning during the years 2011, 2010 and 2009 because the balance in the decommissioning trust fund at December 31, 2011 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 2011, the nuclear decommissioning trust fund has produced an average annualized return of approximately 7.0%. 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 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 new 2011 depreciation rate studies. Annual depreciation rates, as approved by the Rural Utilities Service, in effect in 2011, 2010 and 2009 were as follows:



	Range of Useful Life in years*	2011	2010	2009

Steam production	49-65	1.88%	1.56%	1.52%
Nuclear production	37-60	1.45%	1.50%	1.90%
Hydro production	50	2.00%	2.00%	2.00%
Other production	27-33	2.74%	2.60%	3.00%
Transmission	36	2.75%	2.75%	2.75%
General	3-50	2.00-33.33%	2.00-33.33%	2.00-33.33%

Depreciation expense for the years 2011, 2010 and 2009 was $182,905,000, $144,715,000, and $133,235,000, respectively

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. For the years ended 2011, 2010 and 2009, the allowance for funds used during construction rates were 5.55%, 5.73% and 5.54%, 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.

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.

At December 31, 2011, we had restricted cash totaling $43,683,000 of which $43,070,000 was classified as long-term. The long-term restricted cash balance at December 31, 2011 consisted of funds posted as collateral by counterparties to our interest rate options. See Note 2 for a discussion of our interest rate options. The current portion of restricted cash at December 31, 2011 and 2010 primarily consisted of clean renewable energy bond proceeds on deposit with CoBank to fund a qualifying project at the Rocky Mountain Pumped Storage Hydroelectric facility.

At December 31, 2011 and 2010, we had $106,676,000 and $97,286,000, respectively, on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted funds will 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.

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 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. 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.

At December 31, 2011 and 2010, fossil fuels inventories were $94,872,000 and $54,348,000, respectively. Inventories for spare parts at December 31, 2011 and 2010 were $151,923,000 and $117,467,000, respectively.

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, 2011, the remaining amortization periods for debt issuance costs range from approximately 1 to 39 years.

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, 2011, member power bill prepayments as reflected on the consolidated balance sheets, including unpaid discounts, were $102,319,000, of which, $66,819,000 is classified as a current liability and $35,500,000 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 2012.

In conjunction with the Hawk Road acquisition in May 2009, we recorded a liability for the assumed power sale agreement, which is being amortized over the remaining life of the agreement which ends in 2015. For further discussion of the Hawk Road acquisition, see Note 12b.

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, 2011 and 2010:



		(dollars in thousands)
		2011		2010

Regulatory Assets:
Premium and loss on reacquired debt	$	98,538	$	111,570	(a)
Amortization on capital leases		46,627		64,561	(b)
Outage costs		42,866		23,796	(c)
Interest rate swap termination fees		21,316		25,306	(d)
Asset retirement obligations		29,341		15,699	(e)
Depreciation expense		51,209		52,632	(f)
Deferred charges related to Plant Vogtle Units 3 and 4 training costs		17,602		9,707	(g)
Interest rate options cost		30,735		–	(h)
Other regulatory assets		13,313		7,865	(i)

Total Regulatory Assets	$	351,547	$	311,136
Regulatory Liabilities:
Accumulated retirement costs for other obligations	$	32,687	$	39,205	(e)
Net benefit of Rocky Mountain transactions		47,783		50,965	(j)
Deferral of effects on net margin- Hawk Road and Murray Energy facilities		15,811		21,956	(k)
Major maintenance sinking fund		28,524		28,500	(l)
Deferred debt service adder		37,586		27,678	(m)
Other regulatory liabilities		1,609		1,931	(i)

Total Regulatory Liabilities	$	164,000	$	170,235
Net regulatory assets	$	187,547	$	140,901

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

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

In January 2010, the Financial Accounting Standards Board (FASB) issued Fair Value Measurements and Disclosures – Improving Disclosures about Fair Value Measurements. Effective March 31, 2011, the standard requires a reporting entity to present separately information about purchases, sales, issuances, and settlements (that is, on a gross basis rather than a net basis) in the reconciliation for fair value measurements using significant unobservable inputs (Level 3). Our adoption of the standard did not have a material effect on our disclosures.

In April 2011, the FASB issued Fair Value Measurements: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRSs). The amendments clarify the FASB's intent about the application of existing fair value measurement and disclosure requirements and include those that change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The standard is effective for our fiscal year ended December 31, 2011. The adoption of the standard did not have any impact on our results of operations, cash flows or financial condition.

In May 2011, the FASB issued Comprehensive Income: Presentation of Comprehensive Income. The standard requires that an entity present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. In December 2011, the FASB issued Comprehensive Income: Deferral of the Effective Date for Amendments to the Presentation of Reclassification of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. The standard indefinitely defers the effective date of the specific requirement to present the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income on the face of the financial statements due to concerns that the requirement will be difficult for preparers and may add unnecessary complexity to financial statements. All entities should report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before May 2011. All other requirements issued in Comprehensive Income: Presentation of Comprehensive Income are effective for our fiscal year ending December 31, 2012. Our adoption of this standard will not have a material effect on our 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. The adoption of this standard is not expected to have a material impact on our consolidated financial position or results of operations.