Chesapeake Energy Corporation Reports Financial and Operational Results for the 2007 Fourth Quarter and Full Year

Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operating results for the 2007 fourth quarter and full year. For the 2007 fourth quarter, Chesapeake generated net income available to common shareholders of $158 million ($0.33 per fully diluted common share), operating cash flow of $1.3 billion (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $1.2 billion (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $2.1 billion and production of 204 billion cubic feet of natural gas equivalent (bcfe). For the 2007 full year, Chesapeake generated net income available to common shareholders of $1.2 billion ($2.62 per fully diluted common share), operating cash flow of $4.6 billion and ebitda of $4.7 billion on revenue of $7.8 billion and production of 714 bcfe. The company’s 2007 fourth quarter and full year net income available to common shareholders and ebitda include various items that are typically not included in published estimates of the company’s financial results by certain securities analysts. Excluding the items detailed below, Chesapeake generated adjusted net income to common shareholders in the 2007 fourth quarter of $466 million ($0.93 per fully diluted common share) and adjusted ebitda of $1.4 billion. For the 2007 full year, Chesapeake generated adjusted net income to common shareholders of $1.6 billion ($3.21 per fully diluted common share) and adjusted ebitda of $5.0 billion. The excluded items and their effects on 2007 fourth quarter and full year reported results are detailed as follows: an unrealized after-tax mark-to-market loss of $180 million in the fourth quarter and $257 million for the full year resulting from the company’s oil and natural gas and interest rate hedging programs; an after-tax gain of $51 million in the second quarter resulting from the sale of the company’s investment in Eagle Energy Partners I, L.P.; and a reduction of net income available to common shareholders of $128 million for the fourth quarter and full year resulting from exchanges of the company’s preferred stock for common stock that reduced future preferred stock dividend payment requirements. The excluded items do not affect the calculation of operating cash flow. A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 18-21 of this release. Key Operational and Financial Statistics Summarized Below for the 2007 Fourth Quarter, 2007 Third Quarter, 2006 Fourth Quarter and for the Full Years 2007 and 2006 The table below summarizes Chesapeake’s key results during the 2007 fourth quarter and compares them to the 2007 third quarter and the 2006 fourth quarter and also compares the 2007 full year to the 2006 full year.   Three Months Ended:   Full Year Ended: 12/31/07     9/30/07     12/31/06   12/31/07     12/31/06   Average daily production (in mmcfe) 2,219 2,026 1,653 1,957 1,585 Natural gas as % of total production 92 91 91 92 91 Natural gas production (in bcf) 187.8 170.3 138.8 655.0 526.5 Average realized natural gas price ($/mcf) (a) 8.11 7.41 9.03 8.14 8.76 Oil production (in mbbls) 2,735 2,680 2,217 9,882 8,654 Average realized oil price ($/bbl) (a) 72.58 69.25 59.95 67.50 59.14 Natural gas equivalent production (in bcfe) 204.2 186.4 152.1 714.3 578.4 Natural gas equivalent realized price ($/mcfe) (a) 8.43 7.76 9.11 8.40 8.86 Oil and natural gas marketing income ($/mcfe) .09 .10 .11 .10 .09 Service operations income ($/mcfe) .04 .06 .09 .06 .11 Production expenses ($/mcfe) (.88 ) (.89 ) (.82 ) (.90 ) (.85 ) Production taxes ($/mcfe) (.32 ) (.30 ) (.31 ) (.30 ) (.31 ) General and administrative costs ($/mcfe) (b) (.29 ) (.23 ) (.22 ) (.26 ) (.19 ) Stock-based compensation ($/mcfe) (.08 ) (.10 ) (.04 ) (.08 ) (.05 ) DD&A of oil and natural gas properties ($/mcfe) (2.55 ) (2.57 ) (2.51 ) (2.57 ) (2.35 ) D&A of other assets ($/mcfe) (.16 ) (.24 ) (.20 ) (.22 ) (.18 ) Interest expense ($/mcfe) (a) (.49 ) (.52 ) (.54 ) (.51 ) (.52 ) Operating cash flow ($ in millions) (c) 1,322 1,085 1,095 4,607 4,045 Operating cash flow ($/mcfe) 6.48 5.82 7.20 6.45 6.99 Adjusted ebitda ($ in millions) (d) 1,432 1,195 1,210 5,028 4,449 Adjusted ebitda ($/mcfe) 7.01 6.41 7.96 7.04 7.69 Net income to common shareholders ($ in millions) 158 346 446 1,229 1,904 Earnings per share – assuming dilution ($) .33 .72 .96 2.62 4.35 Adjusted net income to common shareholders ($ in millions) (e) 466 330 418 1,563 1,575 Adjusted earnings per share – assuming dilution ($) .93 .69 .90 3.21 3.61 (a) includes the effects of realized gains or (losses) from hedging, but does not include the effects of unrealized gains or (losses) from hedging (b) excludes expenses associated with non-cash stock-based compensation (c) defined as cash flow provided by operating activities before changes in assets and liabilities (d) defined as net income before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on pages 20-21 (e) defined as net income available to common shareholders, as adjusted to remove the effects of certain items detailed on pages 20-21 Average Realized Prices, Hedging Results and Hedging Positions Detailed Average prices realized during the 2007 fourth quarter (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $8.11 per thousand cubic feet of natural gas (mcf) and $72.58 per barrel of oil and natural gas liquids (bbl), for a realized natural gas equivalent price of $8.43 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains and losses from oil and natural gas hedging activities during the 2007 fourth quarter generated a $1.73 gain per mcf and a $13.66 loss per bbl for a 2007 fourth quarter realized hedging gain of $287 million, or $1.40 per mcfe. Excluding hedging activity, Chesapeake’s average realized pricing differentials to NYMEX during the 2007 fourth quarter were a negative $0.59 per mcf and a negative $4.44 per bbl. By comparison, average prices realized during the 2006 fourth quarter (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $9.03 per mcf and $59.95 per bbl, for a realized natural gas equivalent price of $9.11 per mcfe. Realized gains from oil and natural gas hedging activities during the 2006 fourth quarter generated a $3.14 gain per mcf and a $4.88 gain per bbl for a 2006 fourth quarter realized hedging gain of $447 million, or $2.94 per mcfe. Excluding hedging activity, Chesapeake’s average realized pricing differentials to NYMEX during the 2006 fourth quarter were a negative $0.67 per mcf and a negative $5.14 per bbl. For the 2007 full year, average prices realized (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $8.14 per mcf and $67.50 per bbl, for a realized natural gas equivalent price of $8.40 per mcfe. Realized gains and losses from oil and natural gas hedging activities during the 2007 full year generated a $1.85 gain per mcf and a $1.14 loss per bbl for a 2007 full year realized hedging gain of $1.2 billion, or $1.68 per mcfe. Excluding hedging activity, Chesapeake’s average realized pricing differentials to NYMEX during the 2007 full year were a negative $0.57 per mcf and a negative $3.67 per bbl. During 2006 and 2007, Chesapeake’s oil and natural gas hedging activities generated a total realized gain of $2.5 billion. By comparison, for the 2006 full year, average prices realized (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $8.76 per mcf and $59.14 per bbl, for a realized natural gas equivalent price of $8.86 per mcfe. Realized gains and losses from oil and natural gas hedging activities during the 2006 full year generated a $2.41 gain per mcf and a $1.72 loss per bbl for a 2006 full year realized hedging gain of $1.3 billion, or $2.17 per mcfe. Excluding hedging activity, Chesapeake’s average realized pricing differentials to NYMEX during the 2006 full year were a negative $0.89 per mcf and a negative $5.36 per bbl. The following tables compare Chesapeake’s open hedge position through swaps and collars as well as gains from lifted hedges as of February 21, 2008 to those previously announced as of November 6, 2007. Depending on changes in oil and natural gas futures markets and management’s view of underlying oil and natural gas supply and demand trends, Chesapeake may either increase or decrease its hedging positions at any time in the future without notice. Open Swap Positions as of February 21, 2008     Natural Gas Oil Quarter or Year % Hedged   $ NYMEX % Hedged   $ NYMEX 2008 Q1 76 % 8.64 68 % 73.97 2008 Q2 73 % 8.44 72 % 75.22 2008 Q3 69 % 8.60 72 % 75.11 2008 Q4 61 % 9.13 65 % 76.79 2008 Total 70 % 8.69 69 % 75.24 2009 Total 33 % 8.94 73 % 81.60 Open Natural Gas Collar Positions as of February 21, 2008       Average Average Floor Ceiling Quarter or Year % Hedged $ NYMEX $ NYMEX 2008 Q1 10 % 7.36 9.28 2008 Q2 1 % 7.50 9.68 2008 Q3 1 % 7.50 9.68 2008 Q4 1 % 7.50 9.68 2008 Total 3 % 7.41 9.40 2009 Total 5 % 8.14 10.82 Gains from Lifted Natural Gas Hedges as of February 21, 2008       Total Gain Assuming Natural Gas Production of: Gain Quarter or Year ($ millions) (bcf) ($ per mcf) 2008 Q1 156 184 0.85 2008 Q2 45 194 0.23 2008 Q3 41 205 0.20 2008 Q4 45 210 0.22 2008 Total 287 793 0.36 2009 Total 13 897 0.01 Open Swap Positions as of November 6, 2007     Natural Gas Oil Quarter or Year % Hedged   $ NYMEX % Hedged   $ NYMEX 2008 Q1 74 % 8.78 80 % 72.84 2008 Q2 69 % 8.49 78 % 72.59 2008 Q3 67 % 8.64 75 % 72.44 2008 Q4 61 % 9.16 66 % 73.48 2008 Total 68 % 8.76 75 % 72.82 2009 Total 28 % 8.87 73 % 78.81 Open Natural Gas Collar Positions as of November 6, 2007       Average Average Floor Ceiling Quarter or Year % Hedged $ NYMEX $ NYMEX 2008 Q1 10 % 7.36 9.28 2008 Q2 1 % 7.50 9.68 2008 Q3 1 % 7.50 9.68 2008 Q4 1 % 7.50 9.68 2008 Total 3 % 7.41 9.40 2009 Total 3 % 7.97 11.18 Gains from Lifted Natural Gas Hedges as of November 6, 2007       Total Gain Assuming Natural Gas Production of: Gain Quarter or Year ($ millions) (bcf) ($ per mcf) 2008 Q1 133 188 0.71 2008 Q2 39 194 0.20 2008 Q3 36 202 0.18 2008 Q4 37 209 0.18 2008 Total 245 793 0.31 2009 Total 13 897 0.01 Certain open natural gas swap positions include knockout swaps with knockout provisions at prices ranging from $5.45 to $6.50 covering 191 billion cubic feet of natural gas (bcf) in 2008 and $5.45 to $6.50 covering 214 bcf in 2009. Certain open natural gas collar positions include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 11 bcf in 2008 and $5.50 to $6.00 covering 46 bcf in 2009. Also, certain open oil swap positions include cap-swaps and knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $45.00 to $65.00 covering four million barrels of oil and natural gas liquids (mmbbls) in 2008 and from $52.50 to $60.00 covering seven mmbbls in 2009. The company’s updated forecasts for 2008 through 2009 are attached to this release in an Outlook dated February 21, 2008 labeled as Schedule "A”, which begins on page 23. This Outlook has been changed from the Outlook dated November 6, 2007 (attached as Schedule "B”, which begins on page 27) to reflect various updated information. Company Provides Update on 2008-2009 Financial Plan In September 2007, Chesapeake announced an enhanced financial plan designed to monetize latent balance sheet value and to fully fund its planned capital expenditures through at least 2009 without accessing public capital markets. Since then, the company has successfully implemented multiple aspects of the plan and anticipates further progress during 2008 and 2009. Chesapeake believes its planned future transactions in the asset and financial markets will allow it to monetize additional assets for approximately $3 billion by the end of 2009 that, in management's opinion, have not been adequately reflected in the company’s market valuation historically. Producing Property Monetizations and Asset Sales – On December 31, 2007, the company monetized certain Chesapeake-operated long-lived producing assets in Kentucky and West Virginia and retained drilling rights on the properties below currently producing intervals and outside of existing producing wellbores. Chesapeake received $1.1 billion for the sale of a volumetric production payment on the Appalachian assets covering proved reserves of approximately 208 bcfe and current production of approximately 55 million cubic feet of natural gas equivalent (mmcfe) per day. For accounting purposes, the transaction was treated as a sale and the company’s proved reserves were reduced accordingly. The company also plans to pursue additional monetizations of similarly mature properties in 2008 and 2009 and anticipates further proceeds of approximately $2.0 billion. In the 2008 first quarter, the company sold non-core oil and natural gas assets in the Rocky Mountains and in the southeastern Oklahoma Woodford Shale play for proceeds of approximately $250 million. The sales involved approximately six mmcfe of daily production and 32 bcfe of proved reserves. Midstream Partnership – Chesapeake is currently in the process of forming a private partnership to own a non-operating interest in its midstream natural gas assets outside of Appalachia, which consist primarily of gas gathering systems and processing assets. These assets currently generate annualized cash flow from operating activities in excess of $150 million and are expected to grow substantially over at least the next three years as the company expands its gathering systems in multiple operating areas, particularly in the Fort Worth Barnett and Arkansas Fayetteville Shale plays. The company anticipates raising $1 billion in the first half of 2008 by selling a minority interest in the partnership. Oil and Natural Gas Production Sets Record for 26th Consecutive Quarter and 18th Consecutive Year; 2007 Fourth Quarter Average Daily Production Increases 34% over the 2006 Fourth Quarter and Full Year 2007 Production Increases 23% over Full Year 2006 Daily production for the 2007 fourth quarter averaged 2.219 bcfe, an increase of 193 mmcfe, or 10%, over the 2.026 bcfe produced per day in the 2007 third quarter and an increase of 566 mmcfe, or 34%, over the 1.653 bcfe of daily production in the 2006 fourth quarter. Chesapeake’s 2007 fourth quarter production of 204.2 bcfe was comprised of 187.8 bcf (92% on a natural gas equivalent basis) and 2.74 mmbbls (8% on a natural gas equivalent basis). Chesapeake’s average daily production for the quarter of 2.219 bcfe consisted of 2.041 bcf and 29,728 bbls. The company’s sequential and year-over-year growth rates for its 2007 fourth quarter natural gas production were 10% and 35%, respectively, while the company’s sequential and year-over-year growth rates for its oil production were 2% and 23%, respectively. The 2007 fourth quarter was Chesapeake’s 26th consecutive quarter of sequential U.S. production growth. Over these 26 quarters, Chesapeake’s U.S. production has increased 467%, for an average compound quarterly growth rate of 7% and an average compound annual growth rate of 30%. Chesapeake’s daily production for the 2007 full year averaged 1.957 bcfe, an increase of 372 mmcfe, or 23%, over the 1.585 bcfe of daily production for the 2006 full year. Chesapeake’s 2007 full year production of 714.3 bcfe was comprised of 655.0 bcf (92% on a natural gas equivalent basis) and 9.882 mmbbls (8% on a natural gas equivalent basis). Chesapeake’s average daily production for the 2007 full year of 1.957 bcfe consisted of 1.794 bcf and 27,074 bbls. The company’s growth rate for its 2007 full year natural gas production was 24% and its growth rate for 2007 full year oil production was 14%. The 2007 full year was Chesapeake’s 18th consecutive year of sequential production growth. Oil and Natural Gas Proved Reserves Reach Record Level of 10.9 Tcfe; 2007 Full Year Drilling and Acquisition Costs Average $2.08 per Mcfe; Company Adds 1.9 Tcfe for a Reserve Replacement Rate of 369% Chesapeake began 2007 with estimated proved reserves of 8.956 trillion cubic feet of natural gas equivalent (tcfe) and ended the year with 10.879 tcfe, an increase of 1.923 tcfe, or 21%. During the year, Chesapeake replaced its 714 bcfe of production with an estimated 2.637 tcfe of new proved reserves for a reserve replacement rate of 369%. Reserve replacement through the drillbit was 2.468 tcfe, or 346% of production and 94% of the total increase (including 1.248 tcfe of positive performance revisions, of which 1.207 tcfe relate to infill drilling and increased density locations, and 97 bcfe of positive revisions resulting from oil and natural gas price increases between December 31, 2006 and December 31, 2007). Reserve replacement through the acquisition of proved reserves completed during the year was 377 bcfe, or 53% of production and 14% of the total increase. Divestments of proved reserves during the year totaled 208 bcfe for proceeds of $1.1 billion at a sales price of $5.49 per mcfe. Chesapeake’s total drilling and acquisition costs for the year were $2.08 per mcfe (excluding costs of $343 million for seismic, $1.1 billion for acquisition of unproved properties, $1.1 billion to acquire new leasehold, $254 million for capitalized interest on leasehold and unproved property and $159 million relating to tax basis step-up and asset retirement obligations, as well as positive revisions of proved reserves from higher oil and natural gas prices). Excluding these same items, Chesapeake’s exploration and development costs through the drillbit were $2.13 per mcfe during the year while reserve replacement costs through acquisitions of proved reserves were $1.78 per mcfe. A complete reconciliation of finding and acquisition costs and a roll-forward of proved reserves are presented on page 16 of this release. During 2007, Chesapeake continued the industry’s most active drilling program and drilled 1,992 gross (1,695 net) operated wells and participated in another 1,679 gross (224 net) wells operated by other companies. The company’s drilling success rate was 99% for company-operated wells and 97% for non-operated wells. Also during the year, Chesapeake invested $4.3 billion in operated wells (using an average of 140 operated rigs) and $0.7 billion in non-operated wells (using an average of 105 non-operated rigs). As of December 31, 2007, Chesapeake’s estimated future net cash flows from proved reserves, discounted at an annual rate of 10% before income taxes (PV-10), and after income taxes (standardized measure) were $20.6 billion and $15.0 billion, respectively, using field differential adjusted prices of $6.19 mcf (based on a NYMEX year-end price of $6.80 per mcf) and $90.58 per bbl (based on a NYMEX year-end price of $96.00 per bbl). Chesapeake’s current PV-10 changes by approximately $390 million for every $0.10 per mcf change in natural gas prices and approximately $56 million for every $1.00 per bbl change in oil prices. By comparison, the December 31, 2006 PV-10 and standardized measure of the company’s proved reserves were $13.6 billion and $10.0 billion, respectively, using field differential adjusted prices of $5.41 per mcf (based on a NYMEX year-end price of $5.64 per mcf) and $56.25 per bbl (based on a NYMEX year-end price of $61.15 per bbl). A reconciliation of PV-10 and standardized measure is presented on page 22 of this release. In addition to the PV-10 value of its proved reserves, the net book value of the company’s other assets (including gathering systems, compressors, land and buildings, investments, long-term derivative instruments and other non-current assets) was $3.2 billion as of December 31, 2007 and $2.8 billion as of December 31, 2006. Chesapeake’s Leasehold and 3-D Seismic Inventories Increase to 13 Million Net Acres and 19 Million Acres; Risked Unproved Reserves in the Company’s Inventory Reach 33 Tcfe While Unrisked Unproved Reserves Reach 100 Tcfe Since 2000, Chesapeake has invested $9.4 billion in new leasehold and 3-D seismic acquisitions and now owns the largest combined inventories of onshore leasehold (13.2 million net acres) and 3-D seismic (19.2 million acres) in the U.S. On this leasehold, Chesapeake has an estimated 3.9 tcfe of proved undeveloped reserves and approximately 33 tcfe of risked unproved reserves (100 tcfe of unrisked unproved reserves). The company is currently using 145 operated drilling rigs to further develop its inventory of approximately 36,300 net drillsites, representing more than a 10-year inventory of drilling projects. Chesapeake characterizes its drilling inventory by one of four play types: conventional gas resource, unconventional gas resource, emerging unconventional gas resource or Appalachian Basin gas resource. In these plays, Chesapeake uses a probability-weighted statistical approach to estimate the potential number of drillsites and unproved reserves associated with such drillsites. The following table summarizes Chesapeake’s ownership and activity in each gas resource play type and highlights notable projects in each play.                     Est. Risked Est. Est. Avg. Total Risked Unrisked Current Current CHK Drilling Net Average Reserves Proved Unproved Unproved Daily Operated Net Density Undrilled Well Cost Per Well Reserves Reserves Reserves Production Rig Play Area Acreage (Acres) Wells   ($000 ) (bcfe) (bcfe) (bcfe) (bcfe) (mmcfe) Count Conventional Southern Oklahoma 345,000 120 600 $ 3,500 2.20 849 800 3,200 200 7 South Texas 145,000 80 400 $ 3,300 2.00 428 500 1,900 130 5 Mountain Front 140,000 320 100 $ 9,000 5.00 217 300 1,100 95 2 Other Conventional 2,970,000 Various 3,900 Various Various 2,449 3,000 16,500 560 16 Conventional Sub-total 3,600,000 5,000 3,943 4,600 22,700 985 30   Unconventional Fort Worth Barnett Shale 260,000 50 3,550 $ 2,600 2.50 2,062 5,900 7,300 410 39 Fayetteville Shale (Core) 585,000 80 5,725 $ 3,000 2.00 335 9,300 21,500 100 11 Sahara 850,000 70 9,000 $ 880 0.55 1,050 3,500 4,000 180 12 Deep Haley 550,000 320 325 $ 12,000 6.00 291 1,300 7,300 100 9 Ark-La-Tex 220,000 55 950 $ 1,700 0.90 615 400 1,900 120 6 Granite, Atoka and Colony Washes 200,000 80 1,225 $ 4,000 2.30 881 1,800 2,500 160 11 Other Unconventional 935,000 Various 625 Various Various 196 600 700 30 8 Unconventional Sub-total 3,600,000 21,400 5,430 22,800 45,200 1,100 96   Emerging Unconventional Delaware Basin Shales 815,000 160 500 $ 6,500 3.00 15 1,200 11,700 ND 4 Deep Bossier 390,000 320 125 $ 10,000 5.00 22 400 4,500 ND 3 Ardmore Basin Woodford Shale 170,000 160 200 $ 3,400 1.70 32 300 1,300 ND 2 Alabama Shales 315,000 ND 100 ND ND 0 100 2,000 ND 1 Other Emerging Unconventional 310,000 Various 125 Various Various 3 300 2,500 ND 1 Emerging Unconventional Sub-total 2,000,000 1,050 72 2,300 22,000 25 11   Appalachia Marcellus Shale 1,030,000 160 1,400 $ 1,600 1.25 ND 1,400 5,700 ND 2 Lower Huron and Other 2,970,000 Various 7,450 Various Various ND 2,100 3,900 ND 6 Appalachia Sub-total 4,000,000 8,850 1,402 3,500 9,600 85 8                       Total 13,200,000   36,300     10,847 33,200 99,500 2,195 145 Note: Data above is pro forma for divestitures of approximately 32 bcfe of proved reserves and 37,000 net acres of leasehold post year-end 2007. The table also reflects the effects of the company’s VPP transaction that reduced Appalachian production and proved reserves by 55 mmcfe per day and 208 bcfe as of December 31, 2007. ND = Not disclosed Management Comments Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, "We are pleased to report outstanding financial and operational results for the 2007 fourth quarter and full year. We are particularly proud of our success through the drillbit that enabled the company to deliver reserve and production growth well above our expectations at very attractive finding costs. In addition, our unrivalled inventory of leasehold, 3-D seismic and undrilled locations combined with our talented, motivated, hard-working and growing employee workforce should provide many more years of increases in reserves, production and net asset value per share. Finally, we are also pleased with our progress in implementing the various elements of our enhanced financial plan that should enable Chesapeake to deliver superior growth and financial returns without accessing the public capital markets for the foreseeable future.” Conference Call Information A conference call to discuss this release has been scheduled for Friday morning, February 22, 2008, at 9:00 a.m. EST. The telephone number to access the conference call is 913-312-0822 or toll-free 888-230-5503. The passcode for the call is 4323736. We encourage those who would like to participate in the call to dial the access number between 8:50 and 8:55 a.m. EST. For those unable to participate in the conference call, a replay will be available for audio playback from noon EST on February 22, 2008, and will run through midnight EST on Friday, March 7, 2008. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 4323736. The conference call will also be webcast live on the Internet and can be accessed by going to Chesapeake’s website at www.chk.com and selecting the "News & Events” section. The webcast of the conference call will be available on our website for one year. This press release and the accompanying Outlooks include "forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of oil and natural gas reserves, expected oil and natural gas production and future expenses, projections of future oil and natural gas prices, planned capital expenditures for drilling, leasehold acquisitions and seismic data, and statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures concerning the fair value of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information. Factors that could cause actual results to differ materially from expected results are described in "Risks Related to our Business” under "Risk Factors” in the Offer to Exchange attached as an exhibit to each of the two Schedules TO we filed with the Securities and Exchange Commission on October 23, 2007. These risk factors include the volatility of oil and natural gas prices; the limitations our level of indebtedness may have on our financial flexibility; our ability to compete effectively against strong independent oil and natural gas companies and majors; the availability of capital on an economic basis, including planned asset monetization transactions, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and the amount and timing of development expenditures; uncertainties in evaluating oil and natural gas reserves of acquired properties and associated potential liabilities; our ability to effectively consolidate and integrate acquired properties and operations; unsuccessful exploration and development drilling; declines in the values of our oil and natural gas properties resulting in ceiling test write-downs; lower prices realized on oil and natural gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; the negative impact lower oil and natural gas prices could have on our ability to borrow; drilling and operating risks, including potential environmental liabilities; production interruptions that could adversely affect our cash flow; and pending or future litigation. Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. The SEC has generally permitted oil and natural gas companies, in filings made with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the term "unproved” to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third-party engineers or appraisers. Chesapeake Energy Corporation is the largest independent and third-largest overall producer of natural gas in the U.S. Headquartered in Oklahoma City, the company's operations are focused on exploratory and developmental drilling and corporate and property acquisitions in the Mid-Continent, Fort Worth Barnett Shale, Fayetteville Shale, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast, Ark-La-Tex and Appalachian Basin regions of the United States. The company’s Internet address is www.chk.com. CHESAPEAKE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions, except per share and unit data) (unaudited)     THREE MONTHS ENDED: December 31, December 31, 2007   2006     $     $/mcfe   $     $/mcfe   REVENUES: Oil and natural gas sales 1,460 7.15 1,429 9.39 Oil and natural gas marketing sales 594 2.91 406 2.67 Service operations revenue   35   0.17     33   0.22   Total Revenues   2,089   10.23     1,868   12.28     OPERATING COSTS: Production expenses 180 0.88 125 0.82 Production taxes 64 0.32 47 0.31 General and administrative expenses 75 0.37 40 0.26 Oil and natural gas marketing expenses 575 2.81 390 2.57 Service operations expense 27 0.13 19 0.12 Oil and natural gas depreciation, depletion and amortization 521 2.55 382 2.51 Depreciation and amortization of other assets   33   0.16     30   0.20   Total Operating Costs   1,475   7.22     1,033   6.79     INCOME FROM OPERATIONS   614   3.01     835   5.49     OTHER INCOME (EXPENSE): Interest and other income 3 0.01 6 0.04 Interest expense   (128 ) (0.63 )   (81 ) (0.53 ) Total Other Income (Expense)   (125 ) (0.62 )   (75 ) (0.49 )   INCOME BEFORE INCOME TAXES 489 2.39 760 5.00   Income Tax Expense: Current 9 0.04 5 0.03 Deferred   177   0.87     284   1.87   Total Income Tax Expense   186   0.91     289   1.90     NET INCOME   303   1.48     471   3.10     Preferred stock dividends (17 ) (0.08 ) (25 ) (0.17 ) Loss on exchange/conversion of preferred stock   (128 ) (0.63 )   —   —     NET INCOME AVAILABLE TO COMMON SHAREHOLDERS   158   0.77     446   2.93     EARNINGS PER COMMON SHARE:   Basic $ 0.34   $ 1.05   Assuming dilution $ 0.33   $ 0.96     WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions)   Basic   468     426   Assuming dilution   476     491   CHESAPEAKE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions, except per share and unit data) (unaudited)     TWELVE MONTHS ENDED: December 31, December 31, 2007   2006     $     $/mcfe   $     $/mcfe   REVENUES: Oil and natural gas sales 5,624 7.88 5,619 9.71 Oil and natural gas marketing sales 2,040 2.86 1,577 2.73 Service operations revenue   136   0.19     130   0.23   Total Revenues   7,800   10.93     7,326   12.67     OPERATING COSTS: Production expenses 640 0.90 490 0.85 Production taxes 216 0.30 176 0.31 General and administrative expenses 243 0.34 139 0.24 Oil and natural gas marketing expenses 1,969 2.76 1,522 2.63 Service operations expense 94 0.13 68 0.12 Oil and natural gas depreciation, depletion and amortization 1,835 2.57 1,359 2.35 Depreciation and amortization of other assets 154 0.22 104 0.18 Employee retirement expense   —   —     55   0.09   Total Operating Costs   5,151   7.22     3,913   6.77     INCOME FROM OPERATIONS   2,649   3.71     3,413   5.90     OTHER INCOME (EXPENSE): Interest and other income 15 0.02 26 0.05 Interest expense (406 ) (0.57 ) (301 ) (0.52 ) Gain on sale of investment   83   0.12     117   0.20   Total Other Income (Expense)   (308 ) (0.43 )   (158 ) (0.27 )   INCOME BEFORE INCOME TAXES 2,341 3.28 3,255 5.63   Income Tax Expense: Current 29 0.04 5 0.01 Deferred   861   1.21     1,247   2.16   Total Income Tax Expense   890   1.25     1,252   2.17     NET INCOME   1,451   2.03     2,003   3.46     Preferred stock dividends (94 ) (0.13 ) (89 ) (0.15 ) Loss on exchange/conversion of preferred stock   (128 ) (0.18 )   (10 ) (0.02 )   NET INCOME AVAILABLE TO COMMON SHAREHOLDERS   1,229   1.72     1,904   3.29     EARNINGS PER COMMON SHARE:   Basic $ 2.69   $ 4.78   Assuming dilution $ 2.62   $ 4.35     WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions)   Basic   456     398   Assuming dilution   487     459   CHESAPEAKE ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS (in millions) (unaudited)   December 31, December 31,   2007   2006   Cash $ 1 $ 3 Other current assets   1,395   1,151 Total Current Assets   1,396   1,154   Property and equipment (net) 28,337 21,904 Other assets   1,001   1,359 Total Assets $ 30,734 $ 24,417   Current liabilities $ 2,760 $ 1,890 Long-term debt, net 10,950 7,376 Asset retirement obligation 236 193 Other long-term liabilities 692 390 Deferred tax liability   3,966   3,317 Total Liabilities 18,604 13,166   Stockholders’ Equity   12,130   11,251   Total Liabilities & Stockholders’ Equity $ 30,734 $ 24,417   Common Shares Outstanding   511   457 CHESAPEAKE ENERGY CORPORATION CAPITALIZATION (in millions) (unaudited)       December 31, % of Total Book December 31, % of Total Book   2007 Capitalization   2006 Capitalization   Long-term debt, net $ 10,950 47 $ 7,376 40 Stockholders' equity   12,130 53   11,251 60 Total $ 23,080 100 $ 18,627 100 CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF 2007 ADDITIONS TO OIL AND NATURAL GAS PROPERTIES ($ in millions, except per unit data) (unaudited)   Reserves Cost   (in mmcfe)   $/mcfe   Exploration and development costs $ 5,055 2,371,063 (a) 2.13 Acquisition of proved properties   671   377,230   1.78 Subtotal   5,726   2,748,293   2.08   Divestitures (1,142 ) (208,141 ) (5.49 ) Geological and geophysical costs   343   —   Adjusted subtotal   4,927   2,540,152   1.94   Revisions – price — 97,118   Leasehold acquisition costs 886 — Lease brokerage costs and recording fees 224 — Acquisition of unproved properties and other 1,101 — Capitalized interest on leasehold and unproved property   254   —   Adjusted subtotal   7,392   2,637,270   2.80   Tax basis step-up 131 — Asset retirement obligation and other   29   —   Total $ 7,552   2,637,270   2.86 (a) Includes 1,248 bcfe of positive performance revisions (1,207 bcfe relating to infill drilling and increased density locations and 41 bcfe of other performance related revisions) and excludes positive revisions of 97 bcfe resulting from oil and natural gas price increases between December 31, 2006 and 2007. CHESAPEAKE ENERGY CORPORATION ROLL-FORWARD OF PROVED RESERVES TWELVE MONTHS ENDED DECEMBER 31, 2007 (unaudited)   Mmcfe   Beginning balance, 01/01/07 8,955,614 Extensions and discoveries 1,122,986 Acquisitions 377,230 Divestitures (208,141 ) Revisions – performance 1,248,077 Revisions – price 97,118 Production (714,261 ) Ending balance, 12/31/07 10,878,623     Reserve replacement 2,637,270 Reserve replacement ratio (a) 369 % (a) The company uses the reserve replacement ratio as an indicator of the company’s ability to replenish annual production volumes and grow its reserves, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA – OIL AND NATURAL GAS SALES AND INTEREST EXPENSE (unaudited)   THREE MONTHS ENDED TWELVE MONTHS ENDED December 31, December 31,   2007       2006     2007       2006   Oil and Natural Gas Sales ($ in millions): Oil sales $ 236 $ 122 $ 678 $ 527 Oil derivatives – realized gains (losses) (38 ) 11 (11 ) (15 ) Oil derivatives – unrealized gains (losses)   (180 )   4     (235 )   28     Total Oil Sales   18     137     432     540     Natural gas sales 1,199 817 4,117 3,343 Natural gas derivatives – realized gains (losses) 324 436 1,214 1,269 Natural gas derivatives – unrealized gains (losses)   (81 )   39     (139 )   467     Total Natural Gas Sales   1,442     1,292     5,192     5,079     Total Oil and Natural Gas Sales $ 1,460   $ 1,429   $ 5,624   $ 5,619     Average Sales Price – excluding gains (losses) on derivatives: Oil ($ per bbl) $ 86.24 $ 55.07 $ 68.64 $ 60.86 Natural gas ($ per mcf) $ 6.38 $ 5.89 $ 6.29 $ 6.35 Natural gas equivalent ($ per mcfe) $ 7.03 $ 6.17 $ 6.71 $ 6.69   Average Sales Price – excluding unrealized gains (losses) on derivatives): Oil ($ per bbl) $ 72.58 $ 59.95 $ 67.50 $ 59.14 Natural gas ($ per mcf) $ 8.11 $ 9.03 $ 8.14 $ 8.76 Natural gas equivalent ($ per mcfe) $ 8.43 $ 9.11 $ 8.40 $ 8.86   Interest Expense ($ in millions): Interest $ 99 $ 79 $ 365 $ 301 Derivatives – realized (gains) losses 1 3 1 2 Derivatives – unrealized (gains) losses   28     (1 )   40     (2 ) Total Interest Expense $ 128   $ 81   $ 406   $ 301     CHESAPEAKE ENERGY CORPORATION        CONDENSED CONSOLIDATED CASH FLOW DATA        (in millions)        (unaudited)     THREE MONTHS ENDED: December 31, December 31,   2007     2006     Beginning cash $ 2 $ 1 Cash provided by operating activities 1,544 1,861 Cash (used in) investing activities (1,434 ) (2,274 ) Cash provided by financing activities (111 ) 415 Ending cash 1 3       TWELVE MONTHS ENDED: December 31, December 31,   2007     2006     Beginning cash $ 3 $ 60 Cash provided by operating activities 4,932 4,843 Cash (used in) investing activities (7,922 ) (8,942 ) Cash provided by financing activities 2,988 4,042 Ending cash 1 3 CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF OPERATING CASH FLOW AND EBITDA (in millions) (unaudited)       THREE MONTHS ENDED: December 31, September 30, December 31,   2007     2007     2006     CASH PROVIDED BY OPERATING ACTIVITIES $ 1,544 $ 1,267 $ 1,861   Adjustments: Changes in assets and liabilities   (222 )   (182 )   (766 )   OPERATING CASH FLOW(a) $ 1,322   $ 1,085   $ 1,095   (a) Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of an oil and natural gas company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. THREE MONTHS ENDED:   December 31,   September 30,   December 31,   2007   2007   2006   NET INCOME $ 303 $ 372 $ 471   Income tax expense 186 228 289 Interest expense 128 116 81 Depreciation and amortization of other assets 33 45 30 Oil and natural gas depreciation, depletion and amortization   521   479   382   EBITDA(b) $ 1,171 $ 1,240 $ 1,253 (b) Ebitda represents net income before income tax expense, interest expense, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreement and is used in the financial covenants in our bank credit agreement and our senior note indentures. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP. Ebitda is reconciled to cash provided by operating activities as follows: THREE MONTHS ENDED: December 31, September 30, December 31,   2007     2007     2006     CASH PROVIDED BY OPERATING ACTIVITIES $ 1,544 $ 1,267 $ 1,861   Changes in assets and liabilities (222 ) (182 ) (766 ) Interest expense 128 116 81 Unrealized gains (losses) on oil and natural gas derivatives (261 ) 45 43 Other non-cash items   (18 )   (6 )   34     EBITDA $ 1,171   $ 1,240   $ 1,253   CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF OPERATING CASH FLOW AND EBITDA (in millions) (unaudited)       TWELVE MONTHS ENDED: December 31, December 31, December 31,   2007     2006     2005   CASH PROVIDED BY OPERATING ACTIVITIES $ 4,932 $ 4,843 $ 2,407   Adjustments: Changes in assets and liabilities   (325 )   (798 )   19   OPERATING CASH FLOW(a) $ 4,607   $ 4,045   $ 2,426 (a) Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of an oil and natural gas company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity. TWELVE MONTHS ENDED:   December 31,   December 31,   December 31,   2007   2006   2005   NET INCOME $ 1,451 $ 2,003 $ 948   Income tax expense 890 1,252 545 Interest expense 406 301 220 Depreciation and amortization of other assets 154 104 51 Oil and natural gas depreciation, depletion and amortization   1,835   1,359   894   EBITDA(b) $ 4,736 $ 5,019 $ 2,658 (b) Ebitda represents net income before income tax expense, interest expense, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreement and is used in the financial covenants in our bank credit agreement and our senior note indentures. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP. Ebitda is reconciled to cash provided by operating activities as follows: TWELVE MONTHS ENDED: December 31,   December 31,   December 31,   2007     2006     2005     CASH PROVIDED BY OPERATING ACTIVITIES $ 4,932 $ 4,843 $ 2,407   Changes in assets and liabilities (325 ) (798 ) 19 Interest expense 406 301 220 Unrealized gains (losses) on oil and natural gas derivatives (375 ) 496 41 Other noncash items   98     177     (29 )   EBITDA $ 4,736   $ 5,019   $ 2,658   CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS ($ in millions, except per share data) (unaudited)       December 31, September 30, December 31, THREE MONTHS ENDED:   2007   2007     2006     Net income available to common shareholders $ 158 $ 346 $ 446   Adjustments: Loss on conversion/exchange of preferred stock 128 — — Unrealized (gains) losses on derivatives, net of tax   180   (16 )   (27 )   Adjusted net income available to common shareholders1 466 330 419 Preferred dividends   17   26     25     Total adjusted net income $ 483 $ 356   $ 444     Weighted average fully diluted shares outstanding2 520 517 491   Adjusted earnings per share assuming dilution $ 0.93 $ 0.69   $ 0.90   1 Adjusted net income available to common and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because: a. Management uses adjusted net income available to common to evaluate the company’s operational trends and performance relative to other oil and natural gas producing companies. b. Adjusted net income available to common is more comparable to earnings estimates provided by securities analysts. c. Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. 2 Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP. CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED EBITDA ($ in millions) (unaudited)       December 31, September 30, December 31, THREE MONTHS ENDED:   2007   2007     2006     EBITDA $ 1,171 $ 1,240 $ 1,253   Adjustments, before tax: Unrealized (gains) losses on oil and natural gas derivatives   261   (45 )   (43 )   Adjusted ebitda1 $ 1,432 $ 1,195   $ 1,210   1 Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to ebitda because: a. Management uses adjusted ebitda to evaluate the company’s operational trends and performance relative to other oil and natural gas producing companies. b. Adjusted ebitda is more comparable to estimates provided by securities analysts. c. Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS ($ in millions, except per share data) (unaudited)       December 31, December 31, December 31, TWELVE MONTHS ENDED:   2007     2006     2005     Net income available to common shareholders $ 1,229 $ 1,904 $ 880   Adjustments: Loss on conversion/exchange of preferred stock 128 10 26 Unrealized (gains) losses on derivatives, net of tax 257 (308 ) (27 ) Gain on sale of investment, net of tax (51 ) (73 ) — Employee retirement expense, net of tax — 34 — Cumulative impact of income tax rate change — 15 — Loss on repurchases or exchanges of senior notes, net of tax — — 45 Reversal of severance tax accrual, net of tax   —     (7 )   —     Adjusted net income available to common shareholders1 1,563 1,575 924 Preferred dividends   94     89     42     Total adjusted net income $ 1,657   $ 1,664   $ 966     Weighted average fully diluted shares outstanding2 517 461 375   Adjusted earnings per share assuming dilution $ 3.21   $ 3.61   $ 2.57   1 Adjusted net income available to common and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because: a. Management uses adjusted net income available to common to evaluate the company’s operational trends and performance relative to other oil and natural gas producing companies. b. Adjusted net income available to common is more comparable to earnings estimates provided by securities analysts. c. Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. 2 Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP. CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED EBITDA ($ in millions) (unaudited)     December 31, December 31, December 31, TWELVE MONTHS ENDED:   2007     2006     2005     EBITDA $ 4,736 $ 5,019 $ 2,658   Adjustments, before tax: Unrealized (gains) losses on oil and natural gas derivatives 375 (496 ) (41 ) Reversal of severance tax accrual — (12 ) — Gain on sale of investment (83 ) (117 ) — Employee retirement expense — 55 — Loss on repurchase or exchange of senior notes   —     —     70     Adjusted EBITDA1 $ 5,028   $ 4,449   $ 2,687   1 Adjusted EBITDA excludes certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to EBITDA because: a. Management uses adjusted EBITDA to evaluate the company’s operational trends and performance relative to other oil and natural gas producing companies. b. Adjusted EBITDA is more comparable to earnings estimates provided by securities analysts. c. Items excluded generally are one-time items, or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF PV-10 ($ in millions) (unaudited)       December 31, 2007 December 31, 2006   Standardized measure of discounted future net cash flows $ 14,962 $ 10,007   Discounted future cash flows for income taxes   5,611   3,640   Discounted future net cash flows before income taxes (PV-10) $ 20,573 $ 13,647 PV-10 is discounted (at 10%) future net cash flows before income taxes. The standardized measure of discounted future net cash flows includes the effects of estimated future income tax expenses and is calculated in accordance with SFAS 69. Management uses PV-10 as one measure of the value of the company's current proved reserves and to compare relative values among peer companies without regard to income taxes. We also understand that securities analysts and rating agencies use this measure in similar ways. While PV-10 is based on prices, costs and discount factors which are consistent from company to company, the standardized measure is dependent on the unique tax situation of each individual company. The company’s December 31, 2007 PV-10 and standardized measure were calculated using field differential adjusted prices of $6.19 mcf (based on a NYMEX year-end price of $6.80 per mcf) and $90.58 per bbl (based on a NYMEX year-end price of $96.00 per bbl). The company’s December 31, 2006 PV-10 and standardized measure were calculated using field differential adjusted prices of $5.41 per mcf (based on a NYMEX year-end price of $5.64 per mcf) and $56.25 per bbl (based on a NYMEX year-end price of $61.15 per bbl). SCHEDULE "A” CHESAPEAKE’S OUTLOOK AS OF FEBRUARY 21, 2008 Quarter Ending March 31, 2008 and Years Ending December 31, 2008 and 2009. We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance. As of February 21, 2008, we are using the following key assumptions in our projections for the first quarter of 2008 and the full years 2008 and 2009. The primary changes from our November 6, 2007 Outlook are in italicized bold and are explained as follows: 1) We are providing our first guidance for the 2008 first quarter and increasing our prior production guidance for the full years 2008 and 2009. Guidance in this Outlook excludes production expected to be sold in conjunction with various anticipated monetization transactions in 2008 and 2009, whereas guidance issued on November 6, 2007 included such volumes; 2) Projected effects of changes in our hedging positions have been updated; 3) Certain cost assumptions, shares outstanding and budgeted capital expenditure assumptions have been updated; and 4) Our projected book tax rate has been updated.   Quarter Ending 3/31/2008   Year Ending12/31/2008   Year Ending12/31/2009 Estimated Production(a) Oil – mbbls 2,675 10,500 11,000 Natural gas – bcf 182 – 186 788 – 798 892 – 902 Natural gas equivalent – bcfe 198 – 202 851 – 861 958 – 968   Daily natural gas equivalent midpoint – mmcfe 2,200 2,340 2,640   NYMEX Prices (b) (for calculation of realized hedging effects only): Oil - $/bbl $ 80.98 $ 76.49 $ 75.00 Natural gas - $/mcf $ 7.55 $ 7.51 $ 7.50   Estimated Realized Hedging Effects (based on assumed NYMEX prices above): Oil - $/bbl $ (6.98 ) $ (2.11 ) $ 6.00 Natural gas - $/mcf $ 1.84 $ 1.39 $ 0.63   Estimated Differentials to NYMEX Prices: Oil - $/bbl 7 - 9 % 7 - 9 % 7 - 9 % Natural gas - $/mcf 10 - 14 % 10 - 14 % 10 - 14 %   Operating Costs per Mcfe of Projected Production: Production expense $ 0.90 – 1.00 $ 0.90 – 1.00 $ 0.90 – 1.00 Production taxes (generally 5% of O&G revenues) (c) $ 0.32 – 0.37 $ 0.32 – 0.37 $ 0.32 – 0.37 General and administrative(d) $ 0.33 – 0.37 $ 0.33 – 0.37 $ 0.33 – 0.37 Stock-based compensation (non-cash) $ 0.08 – 0.10 $ 0.10 – 0.12 $ 0.10 – 0.12 DD&A of oil and natural gas assets $ 2.50 – 2.70 $ 2.50 – 2.70 $ 2.50 – 2.70 Depreciation of other assets $ 0.20 – 0.24 $ 0.20 – 0.24 $ 0.20 – 0.24 Interest expense(e) $ 0.50 – 0.55 $ 0.50 – 0.55 $ 0.50 – 0.55 Other Income per Mcfe: Oil and natural gas marketing income $ 0.09 – 0.11 $ 0.09 – 0.11 $ 0.09 – 0.11 Service operations income $ 0.04 – 0.06 $ 0.04 – 0.06 $ 0.04 – 0.06   Book Tax Rate (˜ 97% deferred) 38.5 % 38.5 % 38.5 % Equivalent Shares Outstanding – in millions: Basic 493 496 504 Diluted 525 526 534 Budgeted Capital Expenditures, net – in millions: Drilling $ 1,100 – 1,200 $ 4,400 – 4,800 $ 4,400 – 4,800 Leasehold and property acquisition costs $ 400 – 450 $ 1,200 – 1,400 $ 1,200 – 1,400 Monetization of oil and gas properties(a) — $ (1,000 ) $ (1,000 ) Geological and geophysical costs $ 75   $ 250 – 300   $ 250 – 300   Total budgeted capital expenditures, net $ 1,575 – 1,725 $ 4,850 – $5,500 $ 4,850 – $5,500 (a) The 2008 and 2009 forecasts assume that the company monetizes $2 billion of producing properties in multiple transactions in the second and fourth quarters of 2008 and 2009. (b) NYMEX oil prices have been updated for actual contract prices through January 2008 and NYMEX natural gas prices have been updated for actual contract prices through February 2008. (c) Severance tax per mcfe is based on NYMEX prices of: $80.98 per bbl of oil and $7.00 to $8.00 per mcf of natural gas during Q1 2008; $76.49 per bbl of oil and $7.40 to $8.40 per mcf of natural gas during calendar 2008; and $75.00 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during calendar 2009. (d) Excludes expenses associated with non-cash stock compensation. (e) Does not include gains or losses on interest rate derivatives (SFAS 133). Commodity Hedging Activities The company utilizes hedging strategies to hedge the price of a portion of its future oil and natural gas production. These strategies include: (i) For swap instruments, Chesapeake receives a fixed price and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. (ii) For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a "cap" limiting the counterparty's exposure. In other words, there is no limit to Chesapeake's exposure but there is a limit to the downside exposure of the counterparty. (iii) For knockout swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain predetermined knockout prices. (iv) For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake. (v) Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party. (vi) A three-way collar contract consists of a standard collar contract plus a written put option with a strike price below the floor price of the collar. In addition to the settlement of the collar, the put option requires Chesapeake to make a payment to the counterparty equal to the difference between the put option price and the settlement price if the settlement price for any settlement period is below the put option strike price. (vii) Basis protection swaps are arrangements that guarantee a price differential for oil or natural gas from a specified delivery point. For Mid-Continent basis protection swaps, which have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian basis protection swaps, which have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract. Commodity markets are volatile, and as a result, Chesapeake’s hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction. Chesapeake enters into oil and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and natural gas prices. Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to oil and natural gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and natural gas sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these nonqualifying derivatives that occur prior to their maturity (i.e., because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within oil and natural gas sales. Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and natural gas sales. Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas swaps:     Open Swapsin Bcf’s   Avg. NYMEX Strike Price of Open Swaps   Assuming Natural Gas Production in Bcf’s of:   Open Swap Positions as a % of Estimated Total Natural Gas Production   Total Gains from Lifted Swaps ($ millions)   Total Lifted Gain per Mcf of EstimatedTotal Natural Gas Production Q1 2008 131.0 $ 8.59 184 71 % $ 156.4 $ 0.85 Q2 2008 133.0 $ 8.51 194 69 % $ 44.5 $ 0.23 Q3 2008 132.5 $ 8.69 205 65 % $ 40.5 $ 0.20 Q4 2008 119.5 $ 9.23 210 57 % $ 45.3 $ 0.22 Total 2008(1) 516.0 $ 8.74 793 65 % $ 286.7 $ 0.36               Total 2009(1) 276.0 $ 9.04 897 31 % $ 12.8 $ 0.01 (1) Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $5.45 to $6.50 covering 191 bcf in 2008 and $5.45 to $6.50 covering 214 bcf in 2009. The company currently has the following open natural gas collars in place:     Open Collarsin Bcf’s   Avg. NYMEX Floor Price   Avg. NYMEX Ceiling Price   Assuming Natural Gas Production in Bcf’s of:   Open Collars as a % of Estimated Total Natural Gas Production Q1 2008 18.5 $ 7.36 $ 9.28 184 10 % Q2 2008 2.7 $ 7.50 $ 9.68 194 1 % Q3 2008 2.8 $ 7.50 $ 9.68 205 1 % Q4 2008 2.8 $ 7.50 $ 9.68 210 1 % Total 2008(1) 26.8 $ 7.41 $ 9.40 793 3 %             Total 2009(1) 45.7 $ 8.14 $ 10.82 897 5 % (1) Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 11 bcf in 2008 and $5.50 to $6.00 covering 46 bcf in 2009. Note: Not shown above are written call options covering 110 bcf of production in 2008 at a weighed average price of $10.26 for a weighted average premium of $0.66 and 142 bcf of production in 2009 at a weighed average price of $11.18 for a weighted average premium of $0.48. The company has the following natural gas basis protection swaps in place: Mid-Continent   Appalachia Volume in Bcf’s   NYMEX less1: Volume in Bcf’s   NYMEX plus1: 2008 132.4 0.36 23.0 0.33 2009 91.1 0.33 16.9 0.28 2010 — — 10.2 0.26 2011 — — 12.1 0.25 2012 10.7   0.34 —   — Totals 234.2 $ 0.35 62.2 $ 0.29 1 weighted average We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition in November 2005. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($173 million as of December 31, 2007). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR. Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative Instruments and Hedging Activities,” the assumed CNR derivative instruments are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows. The following details the CNR derivatives (natural gas swaps) we have assumed:     Open Swaps in Bcf’s   Avg. NYMEX Strike Price Of Open Swaps (per Mcf)   Avg. Fair Value Upon Acquisition of Open Swaps (per Mcf)   Initial Liability Acquired (per Mcf)   Assuming Natural Gas Production in Bcf’s of:   Open Swap Positions as a % of Estimated Total Natural Gas Production Q1 2008 9.5 $ 4.68 $ 9.42 ($4.74 ) 184 5 % Q2 2008 9.5 $ 4.68 $ 7.41 ($2.73 ) 194 5 % Q3 2008 9.7 $ 4.68 $ 7.41 ($2.74 ) 205 5 % Q4 2008 9.7 $ 4.66 $ 7.84 ($3.17 ) 210 5 % Total 2008 38.4 $ 4.68 $ 8.02 ($3.34 ) 793 5 %               Total 2009 18.3 $ 5.18 $ 7.28 ($2.10 ) 897 2 % Note: Not shown above are collars covering 3.7 bcf of production in 2009 at an average floor and ceiling of $4.50 and $6.00. The company also has the following crude oil swaps in place:     Open Swaps in mbbls   Avg. NYMEX Strike Price   Assuming Oil Production in mbbls of:   Open Swap Positions as a % of Estimated Total Oil Production   Total Losses from Lifted Swaps ($ millions)   Total Lifted Losses per bbl of EstimatedTotal Oil Production Q1 2008 1,823 73.97 2,675 68 % $ (3.2 ) $ (1.21 ) Q2 2008 1,866 75.22 2,605 72 % $ (4.7 ) $ (1.81 ) Q3 2008 1,886 75.11 2,610 72 % $ (4.6 ) $ (1.76 ) Q4 2008 1,702   76.79 2,610 65 % $ (4.7 ) $ (1.82 ) Total 2008(1) 7,277 $ 75.24 10,500 69 % $ (17.2 ) $ (1.65 )               Total 2009(1) 8,030 $ 81.60 11,000 73 %   —     —   (1) Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $45.00 to $60.00 covering 4,090 mbbls in 2008 and from $52.50 to $60.00 covering 7,483 mbbls in 2009. Note: Not shown above are written call options covering 2,564 mbbls of production in 2008 at a weighted average price of $82.50 for a weighted average premium of $3.17 and 2,555 mbbls of production in 2009 at a weighed average price of $82.14 for a weighted average premium of $4.98. SCHEDULE "B” CHESAPEAKE’S PREVIOUS OUTLOOK AS OF NOVEMBER 6, 2007 (PROVIDED FOR REFERENCE ONLY) NOW SUPERSEDED BY OUTLOOK AS OF FEBRUARY 21, 2008 Quarter Ending December 31, 2007 and Years Ending December 31, 2007, 2008 and 2009. We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance. As of November 6, 2007, we are using the following key assumptions in our projections for the fourth quarter of 2007 and the full years 2007, 2008 and 2009. The primary changes from our September 4, 2007 Outlook are in italicized bold and are explained as follows: 1) We are increasing our prior production guidance for the 2007 fourth quarter and for 2008 and 2009; 2) Production assumptions have been updated; 3) Projected effects of changes in our hedging positions have been updated; and 4) Certain cost assumptions, shares outstanding and budgeted capital expenditure assumptions have been updated.   Quarter Ending12/31/2007   Year Ending12/31/2007   Year Ending12/31/2008   Year Ending12/31/2009 Estimated Production(a) Oil – mbbls 2,500 9,600 10,500 11,000 Natural gas – bcf 181.5 – 183.5 649 – 651 788 – 798 892 – 902 Natural gas equivalent – bcfe 196.5 – 198.5 707 – 709 851 – 861 958 – 968 Daily natural gas equivalent midpoint – in mmcfe 2,150 1,940 2,340 2,640   NYMEX Prices (b) (for calculation of realized hedging effects only): Oil - $/bbl $ 79.84 $ 69.60 $ 75.00 $ 75.00 Natural gas - $/mcf $ 7.07 $ 6.89 $ 7.50 $ 7.50   Estimated Realized Hedging Effects (based on assumed NYMEX prices above): Oil - $/bbl $ (5.40 ) $ 1.28 $ (0.44 ) $ 3.88 Natural gas - $/mcf $ 1.68 $ 1.84 $ 1.36 $ 0.53   Estimated Differentials to NYMEX Prices: Oil - $/bbl 7 - 9 % 7 - 9 % 7 - 9 % 7 - 9 % Natural gas - $/mcf 10 - 14 % 10 - 14 % 10 - 14 % 10 - 14 %   Operating Costs per Mcfe of Projected Production: Production expense $ 0.90 – 1.00 $ 0.90 – 1.00 $ 0.90 – 1.00 $ 0.90 – 1.00 Production taxes (generally 5.5% of O&G revenues) (c) $ 0.35 – 0.40 $ 0.35 – 0.40 $ 0.35 – 0.40 $ 0.35 – 0.40 General and administrative $ 0.25 – 0.30 $ 0.25 – 0.30 $ 0.25 – 0.30 $ 0.25 – 0.30 Stock-based compensation (non-cash) $ 0.08 – 0.10 $ 0.08 – 0.10 $ 0.10 – 0.12 $ 0.10 – 0.12 DD&A of oil and natural gas assets $ 2.60 – 2.70 $ 2.50 – 2.70 $ 2.50 – 2.70 $ 2.50 – 2.70 Depreciation of other assets $ 0.18 – 0.20 $ 0.20 – 0.24 $ 0.26 – 0.30 $ 0.26 – 0.30 Interest expense(d) $ 0.55 – 0.60 $ 0.55 – 0.60 $ 0.55 – 0.60 $ 0.55 – 0.60 Other Income per Mcfe: Oil and natural gas marketing income $ 0.04 – 0.06 $ 0.08 – 0.10 $ 0.07 – 0.09 $ 0.07 – 0.09 Service operations income $ 0.04 – 0.06 $ 0.05 – 0.07 $ 0.05 – 0.07 $ 0.05 – 0.07   Book Tax Rate (˜ 97% deferred) 38 % 38 % 38 % 38 % Equivalent Shares Outstanding – in millions: Basic 480 459 496 504 Diluted 520 519 525 532 Budgeted Capital Expenditures, net – in millions: Drilling $ 1,000 – 1,100 $ 4,250 – 4,450 $ 4,000 – 4,200 $ 4,000 – 4,200 Leasehold and property acquisition costs $ 300 – 350 $ 1,200 – 1,400 $ 1,200 – 1,400 $ 1,200 – 1,400 Monetization of oil and gas properties(a) $ (1,000 - 1,200 ) $ (1,000 - 1,200 ) $ (1,000 - 1,200 ) $ (1,000 - 1,200 ) Geological and geophysical costs $ 50 – 75   $ 250 – 300   $ 200 – 250   $ 200 – 250   Total budgeted capital expenditures, net $ 325 – 350 $ 4,700 – 4,950 $ 4,400 – $4,650 $ 4,400 – $4,650 (a) The 2008 and 2009 forecasts assume that the company monetizes producing properties in multiple transactions beginning late in the fourth quarter of 2007. For accounting purposes, the company anticipates that the proposed monetization transactions will be treated as prepaid sales rather than property sales. As a result, Chesapeake’s forecast does not reflect a reduction of production volumes from the monetized properties. (b) Oil NYMEX prices have been updated for actual contract prices through October 2007 and natural gas NYMEX prices have been updated for actual contract prices through November 2007. (c) Severance tax per mcfe is based on NYMEX prices of: $79.84 per bbl of oil and $6.70 to $7.80 per mcf of natural gas during Q4 2007; $69.60 per bbl of oil and $6.80 to $7.90 per mcf of natural gas during calendar 2007; and $75.00 per bbl of oil and $6.80 to $7.90 per mcf of natural gas during calendar 2008 and 2009. (d) Does not include gains or losses on interest rate derivatives (SFAS 133). Commodity Hedging Activities The company utilizes hedging strategies to hedge the price of a portion of its future oil and natural gas production. These strategies include: (i) For swap instruments, Chesapeake receives a fixed price and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. (ii) For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a "cap" limiting the counterparty's exposure. In other words, there is no limit to Chesapeake's exposure but there is a limit to the downside exposure of the counterparty. (iii) For knockout swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain predetermined knockout prices. (iv) For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake. (v) Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party. (vi) A three-way collar contract consists of a standard collar contract plus a written put option with a strike price below the floor price of the collar. In addition to the settlement of the collar, the put option requires Chesapeake to make a payment to the counterparty equal to the difference between the put option price and the settlement price if the settlement price for any settlement period is below the put option strike price. (vii) Basis protection swaps are arrangements that guarantee a price differential for oil or natural gas from a specified delivery point. For Mid-Continent basis protection swaps, which have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian basis protection swaps, which have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract. Commodity markets are volatile, and as a result, Chesapeake’s hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction. Chesapeake enters into oil and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and natural gas prices. Accordingly, associated gains or loses from the derivative transactions are reflected as adjustments to oil and natural gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and natural gas sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these nonqualifying derivatives that occur prior to their maturity (i.e., because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within oil and natural gas sales. Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and natural gas sales. Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas swaps:     Open Swapsin Bcf’s   Avg. NYMEX Strike Price of Open Swaps   Assuming Natural Gas Production in Bcf’s of:   Open Swap Positions as a % of Estimated Total Natural Gas Production   Total Gains from Lifted Swaps ($ millions)   Total Lifted Gain per Mcf of EstimatedTotal Natural Gas Production Q4 2007(1) 141.4 $ 7.77 182.5 78 % $ 158.1 $ 0.87 Q1 2008 130.5 $ 8.74 188 69 % $ 133.0 $ 0.71 Q2 2008 125.4 $ 8.57 194 65 % $ 38.8 $ 0.20 Q3 2008 124.9 $ 8.74 202 62 % $ 35.9 $ 0.18 Q4 2008 117.6 $ 9.27 209 56 % $ 37.7 $ 0.18 Total 2008(1) 498.4 $ 8.82 793 63 % $ 245.4 $ 0.31               Total 2009(1) 233.5 $ 8.98 897 26 % $ 12.5 $ 0.01 (1) Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $5.25 to $6.25 covering 17 bcf in Q4 2007, $5.45 to $6.50 covering 186 bcf in 2008 and $5.45 to $6.50 covering 152 bcf in 2009. The company currently has the following open natural gas collars in place:     Open Collarsin Bcf’s   Avg. NYMEX Floor Price   Avg. NYMEX Ceiling Price   Assuming Natural Gas Production in Bcf’s of:   Open Collars as a % of Estimated Total Natural Gas Production Q4 2007(1) 19.6 $ 7.13 $ 8.88 182.5 11 % Q1 2008 18.5 $ 7.36 $ 9.28 188 10 % Q2 2008 2.7 $ 7.50 $ 9.68 194 1 % Q3 2008 2.8 $ 7.50 $ 9.68 202 1 % Q4 2008 2.8 $ 7.50 $ 9.68 209 1 % Total 2008(1) 26.8 $ 7.41 $ 9.40 793 3 %             Total 2009(1) 27.4 $ 7.97 $ 11.18 897 3 % (1) Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 14 bcf in Q4 2007, $5.00 to $6.00 covering 11 bcf in 2008 and $5.50 to $6.00 covering 27 bcf in 2009. Note: Not shown above are written call options covering 7 bcf of production in Q4 2007 at a weighted average price of $7.85 for a weighted average premium of $1.13, 110 bcf of production in 2008 at a weighed average price of $10.26 for a weighted average premium of $0.66 and 119 bcf of production in 2009 at a weighed average price of $11.12 for a weighted average premium of $0.54. The company has the following natural gas basis protection swaps in place:   Mid-Continent   Appalachia Volume in Bcf’s   NYMEX less(a): Volume in Bcf’s   NYMEX plus(a): Q4 2007 33.3 0.26 9.2 0.35 2008 118.6 0.27 43.9 0.35 2009 86.6 0.29 36.5 0.31 2010 — — 29.2 0.31 2011 — — 29.2 0.32 2012 10.7   0.34 —   — Totals 249.2 $ 0.28 148.0 $ 0.33 (a) weighted average We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition in November 2005. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($216 million as of September 30, 2007). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR. Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative Instruments and Hedging Activities,” the assumed CNR derivative instruments are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows. The following details the CNR derivatives (natural gas swaps) we have assumed:     Open Swaps in Bcf’s   Avg. NYMEX Strike Price Of Open Swaps (per Mcf)   Avg. Fair Value Upon Acquisition of Open Swaps (per Mcf)   Initial Liability Acquired (per Mcf)   Assuming Natural Gas Production in Bcf’s of:   Open Swap Positions as a % of Estimated Total Natural Gas Production Q4 2007 10.6 $ 4.82 $ 8.87 ($4.05 ) 182.5 6 % Q1 2008 9.5 $ 4.68 $ 9.42 ($4.74 ) 188 5 % Q2 2008 9.5 $ 4.68 $ 7.41 ($2.73 ) 194 5 % Q3 2008 9.7 $ 4.68 $ 7.41 ($2.74 ) 202 5 % Q4 2008 9.7 $ 4.66 $ 7.84 ($3.17 ) 209 5 % Total 2008 38.4 $ 4.68 $ 8.02 ($3.34 ) 793 5 %               Total 2009 18.3 $ 5.18 $ 7.28 ($2.10 ) 897 2 % Note: Not shown above are collars covering 3.7 bcf of production in 2009 at an average floor and ceiling of $4.50 and $6.00. The company also has the following crude oil swaps in place:     Open Swaps in mbbls   Avg. NYMEX Strike Price   Assuming Oil Production in mbbls of:   Open Swap Positions as a % of Estimated Total Oil Production   Total Gains from Lifted Swaps ($ millions)   Total Lifted Gain per bbl of EstimatedTotal Oil Production Q4 2007(1) 1,564 $ 72.84 2,500 63 % $ (0.5 ) $ (0.21 ) Q1 2008 1,971 72.84 2,470 80 % $ 1.2 $ 0.49 Q2 2008 2,002 72.59 2,560 78 % $ 1.2 $ 0.47 Q3 2008 2,024 72.44 2,690 75 % $ 1.2 $ 0.45 Q4 2008 1,840   73.48 2,780 66 % $ 1.2   $ 0.43   Total 2008(1) 7,837 $ 72.82 10,500 75 % $ 4.8   $ 0.46                 Total 2009(1) 8,030 $ 78.81 11,000 73 %   —     —   (1) Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $45.00 to $60.00 covering 736 mbbls in Q4 2007 and 3,478 mbbls in 2008 and from $52.50 to $60.00 covering 7,483 mbbls in 2009. Note: Not shown above are written call options covering 920 mbbls of production in Q4 2007 at a weighted average price of $79.85 for a weighted average premium of $1.00, 2,564 mbbls of production in 2008 at a weighted average price of $82.50 for a weighted average premium of $3.17 and 2,190 mbbls of production in 2009 at a weighed average price of $75.00 for a weighted average premium of $5.47.