Oglethorpe Power Corporation August 25, 2011 Second Quarter 2011 Investor Briefing

Certain of the statements made by representatives of Oglethorpe Power Corporation (An Electric Membership Corporation) (“Oglethorpe”) during the course of this presentation that are not historical facts are forward-looking statements. Although Oglethorpe believes that the assumptions underlying these statements are reasonable, you are cautioned that such forward-looking statements are inherently uncertain and involve necessary risks that may affect Oglethorpe’s business prospects and performance, causing actual results to differ from those discussed during the presentation. When considering forward-looking statements, you should keep in mind risk factors and other cautionary statements included in Oglethorpe’s SEC filings. Any forward-looking statements made are subject to all the risks and uncertainties, many of which are beyond management’s control, as described in Oglethorpe’s SEC filings. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, Oglethorpe’s actual results and plans could differ materially from those expressed in any forward-looking statements. Oglethorpe undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information or future events. This electronic presentation is provided as of August 25, 2011. If you are viewing this presentation after that date, there may have been events that occurred subsequent to such date that would have a material adverse effect on the financial information that was presented, and Oglethorpe has not undertaken any obligation to update the electronic presentation. Risk Factors, Forward-Looking Statements

Oglethorpe Power Corporation Overview Tom Smith President and Chief Executive Officer

Overview of Oglethorpe Power Corporation Business Members Ratings Not-for-profit Georgia electric membership corporation. One of the largest electric cooperatives in the United States. Owns or leases approximately 7,080 MW of generation capacity. Operates or schedules another 1,287 MW on behalf of the Members. 2011 YTD system peak of 9,000 MW. Wholesale electric power provider for 39 distribution cooperatives in Georgia (the “Members”). Take or pay, joint and several Wholesale Power Contracts through December 2050. Allows for recovery of all costs, including debt service. Senior Secured Ratings: Baa1 / A / A (all stable) Short-term Ratings: P-2 / A-1 / F1 Financial Annual revenues in excess of $1 billion. Total assets of approximately $7.6 billion.

Member Systems and Service Territory Members’ service territory: Serve 1.8 million consumers (meters), representing a population of 4.1 million people. Covers 38,000 square miles, or 65 percent of Georgia. Includes 151 out of 159 counties in Georgia. Members’ load: Approximately 2/3 residential. Exclusive right to provide retail service in designated service territories. No residential competition. Competition only at inception for C&I loads in excess of 900kW. In 2010, Cobb EMC, Jackson EMC and Sawnee EMC accounted for 14.5%, 11.6%, and 10.6% of Oglethorpe’s total revenues, respectively. No other Member over 10%. The top 15 Members accounted for approximately 80% of total revenue in 2010. = Oglethorpe’s Members 2010 Member Customer Base by MWh Sales

Oglethorpe has acquired over 2,000 MW of gas-fired generation for ~$900 million in the last two years increasing Oglethorpe’s owned / leased generation capacity by 40%. These acquisitions generated value for Oglethorpe’s Members and have compared favorably to self-build options. As a result of the acquisition of Murray, deferral of the $477 million Warren Biomass Project and cancellation of the $750 million self-build combined cycle plant, Oglethorpe has reduced previously projected construction related capital expenditures by $1.2 billion through 2015 (exclusive of the acquisition price). Oglethorpe will continue to monitor potential future acquisition opportunities – in particular for CTs in the 2016 timeframe. Acquisition Summary Closing Date Seller Capacity (MW) Acquisition Value Participating Members ($ Millions) ($ / KW) Hawk Road CTs 4/30/2009 Dynegy 500 $203(a) $406 37 Hartwell CTs 10/13/2009 International Power 300 $170 $567 39 Murray CCs 4/8/2011 KGen 1,250 $529(b) $423 34 Total 2,050 $902 $440 (a) Includes $105 million purchase price and $98 million liability assumed for PPA. (b) Final asset valuation, excluding certain post-closing true-ups.

Diverse Mix of Generating Resources (a) Represents resources owned, leased, or operated by Oglethorpe. Excludes Members’ SEPA allocation. Capacity reflects planning capacity. 2011 Capacity(a) ~7,800 MW Rocky Mountain Pumped Storage Hydro Sewell Creek Energy Facility Chattahoochee Energy Facility Hawk Road Energy Facility Plant Wansley Talbot Energy Facility Hartwell Energy Facility Plant Vogtle Plant Hatch Doyle Generating Plant Smarr Energy Facilitiy Plant Scherer Murray Energy Facility

Operations and Project Highlights Mike Price Executive Vice President and Chief Operating Officer

Member Demand Requirements Member Energy Requirements (MW) Percent Change (Million MWh) Percent Change 6.1% 10.4% 0.8% 10.4% 4.1% 3.9% 2.8% -0.3% -3.7% -5.3% Note: The data is at the Members’ delivery points (net of system losses). While Flint EMC was not a Member from 2005 through 2009, Flint EMC data is included in all years. Year to date data is through 8/24/2011 Highest Summer Peak (2007) = 9294 MW Highest Winter Peak (2010) = 8462 MW 2011 Summer Peak (YTD) = 9000 MW -2.0% Historical Load 9.1% 0.1% -4.3% (Forecasted) Days ≥ 90° Days ≥ 95° Days ≥ 100° 50 24 9 39 4 38 4 84 19 61 17 8

New AP1000 units will be adjacent to existing two units at Vogtle site. Experienced developer and operator, Southern Nuclear. Very favorable EPC contract with experienced contractors, Westinghouse and Stone & Webster consortium, which includes parent guarantees. In 2010, amended to replace certain index based adjustments with fixed escalation amounts. 30% share or 660 MW of 2,200 MW total capacity from additional units. Georgia Power, MEAG and City of Dalton are other co-owners. Oglethorpe’s share is fully subscribed by its members. $4.2 billion estimated total cost to Oglethorpe (including AFUDC). Vogtle Units 3 & 4 Project Highlights Conceptual Drawing of Vogtle Units 3 & 4 Georgia Power 45.7% Oglethorpe Power 30% MEAG 22.7% Dalton Utilities 1.6%

2017 Vogtle Units 3 & 4 Capital Expenditures and Timeline 2017 Unit 4 in Service May 2005 Development Agreement Mar 2008 File Combined Construction Operating License (COL) with NRC Aug 2009 NRC Issuance of ESP/LWA 2016 Unit 3 in Service Q2 2012 Start of DOE Funding (projected) April 2006 Definitive Agreements Aug 2006 Early Site Permit (ESP) Filed with NRC May 2010 Signed DOE Conditional Term Sheet Q4 2011 DCD Final Rulemaking Dec 2011/ Early 2012 NRC Issuance of COL Forecast Actuals $1.1 billion spent to date through 6/30/2011

Nuclear Regulatory Committee (NRC) staff has completed their review of the Final Safety Evaluation Report (FSER) for the Westinghouse AP1000 DCD and the Vogtle Combined Construction Permits and Operating Licenses (COLs). Westinghouse AP1000 design certification now in final rulemaking stage. NRC staff expected to deliver final rulemaking package by early October for Commission to proceed on affirmation vote process. Following affirmation, NRC may approve limited work authorization to begin nuclear island foundation work. NRC could issue COLs in December of 2011 following successful completion of mandatory hearing process, or NRC may wait until the effective date of DCD rule, expected in February 2012, to issue COL (and LWA) as outlined in August 9th NRC staff letter. NRC Commission will decide the ultimate schedule. Key Vogtle Licensing Activities

No immediate impacts to the licensing or construction have been identified. NRC launched a review of U.S. operating nuclear power plants. Assembled a task force that includes current senior NRC Managers and former NRC experts to conduct short and long term studies. Task force short term study report issued July 12. “Continued operation and continued licensing activities do not pose an imminent risk to public health and safety.” Overarching recommendation to clarify the existing regulatory framework. Comprehensive set of recommendations including focus on station blackout mitigation capability, spent fuel pool cooling, hydrogen control and mitigation in containments, and other items relating to severe accident scenarios. Related to Vogtle 3 & 4: Task Force “supports completing [AP1000 and ESBWR] design certification rulemaking activities without delay.” Report stated that the AP1000, by nature of its passive safety systems design, “have many of the design features and attributes necessary to address the task force recommendations”. Recent Events in Japan

July 12, 2011 Unit 4 Unit 3 Construction Update Modular Assembly Building March 8, 2010 October 15, 2010 January 12, 2010

Cooling Tower Foundations – Deep drilled piles July 12, 2011

Recently Finalized/Proposed EPA Regulations Cross-State Air Pollution Rule (Final 7/2011) New emission caps for SO2 and NOx Oglethorpe’s 2012 strategy: Purchase SO2 emission allowances and/or modify operations at Plant Scherer In 2013, emission control equipment at Scherer is scheduled to be installed and no additional allowance purchases are anticipated No significant impact expected on operation of Oglethorpe’s plants or financial condition Water Intake – Rule 316(b) (Proposed) Would require utilities to add cooling towers to power plants that currently have “once-through” cooling Generally applicable to generation facilities permitted to withdraw more than two million gallons of water/day Applies to Plants Hatch, Vogtle, Scherer, and Wansley (each of these plants already has cooling towers) Effects not expected to be significant Expect final rule July 2012 EGU MACT Rule (Proposed) Proposes stringent new maximum achievable control technology (MACT) emission limits, including mercury Could require installation of activated carbon injection and baghouses at Plant Wansley (potential impact ~$150 million in 2014-2016) The total potential cost will depend on the final rule Expect final rule November 2011 Coal Combustion Byproducts (Proposed) Regulatory options under consideration vary from treatment as non-hazardous to hazardous A final rule may require significant changes including construction of lined landfills, groundwater monitoring, and pond closures. Potential impact will depend on a final rule but could be approximately half a billion dollars, or potentially more Final promulgation has been delayed (2012?)

Financial Highlights Betsy Higgins Executive Vice President and Chief Financial Officer

Submitted Part I and Part II loan applications in 2008. Signed conditional term sheet with DOE in May 2010. Expect to commence negotiations on definitive agreements in September. DOE has been engaged with Georgia Power for several months negotiating “common provisions” of loan agreement (this will save Oglethorpe time in negotiations with DOE) Final decision on loan approval is not expected to occur until after approval of the COLs. DOE loan guarantee targets 70% of eligible project costs, not to exceed $3.057 billion. All-in pricing expected to be favorable relative to taxable capital markets. Will be secured under Oglethorpe’s First Mortgage Indenture on parity with other secured debt. Potential start of DOE funding in second quarter of 2012. DOE Loan Guarantees for Vogtle 3 & 4

5.95% 30 Yr Bullet 5.39% 30 Yr Bullet Vogtle 3 & 4 CWIP through 6/30/2011 total $1,108 Million. $1,150 million issued to date (~27% of estimated total project cost) @ weighted average interest rate of 5.55%. DOE financing available only after receipt of COL. Oglethorpe is using commercial paper program for interim financing between permanent debt issuances shown below. 18 Vogtle Units 3 & 4 Financing Plan 5.25% 39 Yr Bullet First Mortgage Bonds To Be Issued New DOE Loans

RUS Loan Status (a) Project has been indefinitely deferred. RUS is currently completing NEPA process which would enable site development in the future, if desired. Purpose/Use of Proceeds Amount Advanced (to date) Remaining Amount Approved Loans General Improvements 92,000,000 $ 42,240,000 $ 49,760,000 $ General & Environmental Improvements 441,522,000 $ 278,858,000 $ 162,664,000 $ General & Environmental Improvements 310,228,000 $ 65,902,000 $ 244,326,000 $ Hawk Road Energy Facility 203,100,000 $ 106,648,215 $ 96,451,785 $ Hartwell Energy Facility 170,000,000 $ 170,000,000 $ - $ General Improvements 127,703,000 $ - $ 127,703,000 $ 1,344,553,000 $ 663,648,215 $ 680,904,785 $ Submitted Loan Application Warren Biomass Facility (a) 459,000,000 $ Murray Units I and II 535,000,000 $ 994,000,000 $ 

Liquidity Facility Upsizing and Restructuring Bank of America, N.A. (Admin. Agent) $210 CoBank $150 SunTrust Bank $130 Wells Fargo Bank $125 Royal Bank of Canada $110 Bank of Montreal $100 Bank of Tokyo - Mitsubishi $100 Mizuho $80 JPMorgan Chase $60 Fifth Third Bank $50 Goldman Sachs Bank $50 US Bank $50 RBC Bank (USA) $40 Chang Hwa Commercial Bank $10 Bank of America, N.A. (Admin. Agent) 210 $ CoBank 150 $ SunTrust Bank 130 $ Wells Fargo Bank 125 $ Royal Bank of Canada 110 $ Bank of Montreal 100 $ Bank of Tokyo - Mitsubishi 100 $ Mizuho 80 $ JPMorgan Chase 60 $ Fifth Third Bank 50 $ Goldman Sachs Bank 50 $ US Bank 50 $ RBC Bank (USA) 40 $ Chang Hwa Commercial Bank 10 $ 

Oglethorpe’s Available Liquidity Position is Strong Borrowings Detail $252.7 MM Letter of Credit Support for VRDBs/Murray $273.6 MM Murray Acquisition Interim Financing as of August 25, 2011 Represents 767 days of liquidity. 0 500 1,000 1,500 2,000 Total Credit Facilities Less Borrowings Available Line Capacity Cash (Excluding $16 Million in RUS Cushion of Credit) Total Liquidity $1,865 - $526 $1,339 $587 $1,926 (Millions)

Fixed costs: Members billed based on board-approved annual budget and budget revisions throughout the year, if necessary. Prior period adjustment mechanism covers any year-end shortfall below required 1.10 MFI (board approval not required). Energy costs: Actual costs are passed through. Monthly true-up of estimate vs. actual. New rate management programs under development to allow Members to expense interest during construction on Vogtle 3&4 prior to commercial operation and to expense Murray carrying costs. Rate Structure Assures Recovery of All Costs + Margin Note: First Mortgage Indenture requires an MFI ratio of least 1.10x MFI coverage requirement of 1.10x under First Mortgage Indenture. Budget of 1.14x MFI for 2010 and 2011. Formulary rate under Wholesale Power Contract. Designed to recover all costs, plus margin, without any further regulatory approval. Annual budget and adjustments to rate to reflect budget changes are generally not subject to approval of RUS or any other regulatory authority. Changes to rate schedule are subject to RUS approval. (Budgeted) Margin Coverage $20.0 $18.4 $17.5 $16.9 $17.2 $17.7 $18.2 $19.1 $19.3 $26.4 $33.7 $38.0 $0.0 $10.0 $20.0 $30.0 $40.0 Net Margin (Mn) 1.06 1.08 1.10 1.12 1.14 1.16 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.12 1.14 1.14 MFI Coverage

Income Statement Excerpts Key Point: Through June, net margin equates to 75% of targeted annual margin ($38.0 million to achieve 1.14 MFI). This is typical for Oglethorpe and consistent with management’s practices of budgeting conservatively and making adjustments to the budget (typically toward the end of the year) to exactly match actual expenses + margin. (a) Margins for Interest ratio is calculated on an annual basis and is determined by dividing Oglethorpe’s Margins for Interest by Interest Charges, both as defined in Oglethorpe’s First Mortgage Indenture. The Indenture obligates Oglethorpe to establish and collect rates that, subject to any necessary regulatory approvals, are reasonably expected to yield a Margins for Interest ratio equal to at least 1.10x for each fiscal year. In addition, the Indenture requires a showing of Oglethorpe’s having met this requirement for certain historical periods as a condition for issuing additional obligations under the Indenture. For 2009 and 2010, Oglethorpe increased its Margins for Interest ratio to 1.12x and 1.14x, respectively, above the minimum 1.10x ratio required by the Indenture. For 2011, Oglethorpe again budgeted a Margins for Interest ratio of 1.14x. Oglethorpe’s Board of Directors will continue to evaluate margin coverage throughout the generation expansion period and may chose to change the targeted Margins for Interest ratio in the future. December 31, ($ in thousands) 2011 2010 2010 2009 2008 Statement of Revenues and Expenses: Operating Revenues: Sales to Members $597,224 $629,791 $1,292,514 $1,144,012 $1,237,649 Sales to Non-Members $52,353 $392 $1,478 $1,249 $1,111 Operating Expenses $519,940 $504,518 $1,054,743 $921,139 $1,041,681 Other Income $19,643 $21,335 $43,651 $42,728 $43,381 Net Interest Charges ($120,452) ($124,996) ($249,167) ($240,460) ($221,201) Net Margin $28,828 $22,004 $33,733 $26,390 $19,259 Margins for Interest Ratio (a) n/a n/a 1.14x 1.12x 1.10x June 30,

Balance Sheet Excerpts (a) The equity ratio is calculated, pursuant to Oglethorpe’s First Mortgage Indenture, by dividing patronage capital and membership fees by total capitalization plus long-term debt due within one year (Total Long-Term Debt and Equities in the table above). Oglethorpe has no financial covenant that requires it to maintain a minimum equity ratio; however, a covenant in the Indenture restricts distributions of equity (patronage capital) to its Members if its equity ratio is below 20%. Oglethorpe also has a covenant in a credit agreement that currently requires a minimum total patronage capital of $575 million. The equity ratio is less than that of many investor-owned utilities because Oglethorpe operates on a not-for-profit basis and has a significant amount of authority to set and change rates to ensure sufficient cost recovery to produce margins to meet financial coverage requirements. June 30, ($ in thousands) 2011 2010 2009 2008 Balance Sheet Data: Assets: Electric Plant in Service $7,294,325 $6,672,253 $6,550,938 $5,906,865 Construction Work in Progress $1,497,072 $1,195,475 $628,824 $307,464 Total Electric Plant $5,799,019 $5,015,560 $4,400,496 $3,639,395 Cash and Cash Equivalents $417,946 $672,212 $579,069 $167,659 Total Assets $7,592,470 $6,997,062 $6,370,234 $5,044,452 Capitalization: Patronage Capital and Membership Fees $624,780 $595,952 $562,219 $535,829 Accumulated Other Comprehensive Loss $123 ($469) ($1,253) ($1,348) Subtotal $624,903 $595,483 $560,966 $534,481 Long-term Debt and Obligations under Capital Leases $5,406,104 $4,836,415 $4,387,926 $3,514,923 Obligation under Rocky Mountain Transactions $127,740 $123,573 $115,641 $108,219 Long-term Debt and Capital Leases due within one year $134,309 $170,947 $119,241 $110,647 Total Long-Term Debt and Equities $6,293,056 $5,726,418 $5,183,774 $4,268,270 Equity Ratio (a) 9.9% 10.4% 10.8% 12.6% December 31,

Liquidity Margins for Interest Revenue Summary Interim Financing Long Term Debt Balance Sheet Electric Plant Average Cost of Funds: 0.869% (dollars in millions) LT Debt Outstanding (06.30.2011): $5.1 billion Weighted Average Cost: 5.013% Equity ratio: 9.9% Note: Includes Sinking Fund and Debt Service Adder 2011 1.14 MFI June 30, 2011 June 30, 2011 Actuals Forecast 25

Completed to date in 2011 $180 million Tax-Exempt refinancing. (March) $260 million Bank term loan for Murray acquisition. (April) Funded RUS loans for Hartwell and Hawk Road acquisitions. (June) Closed on new $1.265 billion revolving credit facility. (June) $300 million 39-year FMB issuance for Vogtle. (August) Upcoming in 2011 Working with DOE to finalize loan guarantee (4th Quarter); funding not expected until 2012. Completing increase of CFC unsecured credit facility from $50 million to $110 million. (October) Significant Financing Activity

Oglethorpe is a Strong, Stable Credit One of the largest electric cooperatives in the United States. Oglethorpe has long-term, take-or-pay Wholesale Power Contracts with its Members through 2050. Members' obligations under the Wholesale Power Contracts are joint and several. Primarily residential customer base — approximately 2/3 of Members’ MWh sales and operating revenue. Oglethorpe’s formulary rate structure assures cost recovery. Inputs to rate formula are not subject to any regulatory approval. Changes to formulary rate schedule are subject to RUS approval. Members are not subject to regulation for rate setting purposes. Strong liquidity position. Well diversified power supply portfolio. Substantial value in existing resources. Strong, consistent operational and financial performance. Strong emphasis on risk management and corporate compliance.

Additional Information A link to this presentation will be posted on Oglethorpe’s website www.opc.com. Oglethorpe’s SEC filings, including its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K are made available on its website. For additional information please contact: Name Title Email Address Phone Number Betsy Higgins Executive Vice President and Chief Financial Officer betsy.higgins@opc.com 770-270-7168 Tom Brendiar Director, Bank and Investor Relations tom.brendiar@opc.com 770-270-7173 Joe Rick Director, Capital Markets joe.rick@opc.com 770-270-7240