Chesapeake Energy Corporation Reports Strong Operating and Financial Results for the 2005 Third Quarter

OKLAHOMA CITY, Oct. 31 /PRNewswire-FirstCall/ -- Chesapeake Energy Corporation today reported financial and operating results for the third quarter of 2005. For the quarter, Chesapeake generated net income available to common shareholders of $149.1 million ($0.43 per fully diluted common share), operating cash flow of $635.2 million (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $581.4 million (defined as income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $1.083 billion and production of 120.4 billion cubic feet of natural gas equivalent (bcfe).

The company's 2005 third quarter net income available to common shareholders and ebitda include certain items that are not typically included in published estimates of the company's financial results by many securities analysts. Such items and their after-tax effects on third quarter reported results are described as follows:

* an unrealized mark-to-market loss of $66.8 million resulting from the company's oil, natural gas and interest rate hedging programs; * a $0.5 million loss resulting from the early extinguishment of certain Chesapeake debt securities; and * a reduction of net income available to common shareholders of $17.7 million resulting from a loss on the exchange of approximately $134 million of Chesapeake's 4.125% cumulative convertible preferred stock into 8.5 million shares of the company's common stock and $70 million of Chesapeake's 5.0% (series 2003) cumulative convertible preferred stock into 4.4 million shares of the company's common stock through unsolicited transactions with holders of the preferred stock.

Adjusted for the above-mentioned items, Chesapeake's net income to common shareholders in the 2005 third quarter would have been $234.1 million ($0.65 per fully diluted common share) and ebitda would have been $686.2 million. The foregoing items do not affect the calculation of operating cash flow. A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income available to common shareholders to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 13-15 of this release.

Oil and Natural Gas Production Sets Record for 17th Consecutive Quarter; 2005 Third Quarter Average Daily Production Increases 28% Over 2004 Third Quarter and 5% Over 2005 Second Quarter

Daily production for the 2005 third quarter averaged 1.308 bcfe, an increase of 284 million cubic feet of natural gas equivalent (mmcfe), or 27.7%, over the 1.024 bcfe produced per day in the 2004 third quarter and an increase of 64 mmcfe, or 5.1%, over the 1.244 bcfe produced per day in the 2005 second quarter. Of the 64 mmcfe daily increase in sequential quarterly production, 53% came from organic growth and 47% from acquisition growth, making the company's quarterly organic growth rate 2.9%, its year-to-date organic growth rate 8.0% and its annualized 2005 organic growth rate 10.7%. The company's 2005 third quarter production exceeded its September 7, 2005 forecasted mid-point production by 0.9 bcfe, or 0.7%, because of stronger than projected drilling and operational results. The effects of Hurricane Rita reduced Chesapeake's third quarter production by 0.3 bcfe as a result of onshore facility shut-ins.

Chesapeake's 2005 third quarter production of 120.4 bcfe was comprised of 108.8 billion cubic feet of natural gas (bcf) (90% on a natural gas equivalent basis) and 1.93 million barrels of oil and natural gas liquids (10% on a natural gas equivalent basis). Chesapeake's average daily production rate of 1.308 bcfe consisted of 1.183 bcf of gas and 20,935 barrels of oil and natural gas liquids (bbl).

The 2005 third quarter was Chesapeake's 17th consecutive quarter of production growth. During these 17 quarters, Chesapeake's U.S. production has increased 234%, for an average compound quarterly growth rate of 7.4% and an average compound annual growth rate of 33%.

Oil and Natural Gas Proved Reserves Reach Record Level of 6.2 Tcfe; First Nine Months 2005 Drilling and Acquisition Costs are $1.47 per Mcfe as Company Adds 1.311 Tcfe and Replaces Production by 488%

Chesapeake began 2005 with estimated proved reserves of 4.902 trillion cubic feet of natural gas equivalent (tcfe) and ended the third quarter with an internally estimated 6.213 tcfe, an increase of 1.311 tcfe, or 27%. During the 2005 first nine months, the company replaced its 338 bcfe of production with an estimated 1.649 tcfe of new proved reserves, for a reserve replacement rate of 488% at a drilling and acquisition cost of $1.47 per mcfe. Reserve replacement through the drillbit was 929 bcfe, or 275% of production (including a negative 19 bcfe from performance revisions and a positive 94 bcfe from oil and natural gas price increases), or 56% of the total increase, at a cost of $1.42 per mcfe. Reserve replacement through acquisitions was 720 bcfe, or 213% of production, or 44% of the total increase, at a cost of $1.54 per mcfe. The above figures do not include the impact of the pending CNR acquisition, which should close by December 1, 2005 and will increase Chesapeake's proved reserves by an internally estimated 1.1 tcfe.

Total costs incurred to acquire and develop proved reserves during the first nine months of 2005 were $2.23 per mcfe. These total costs include drilling, completion, acquisition, seismic, leasehold, capitalized internal costs, non-cash tax basis step-up from various corporate acquisitions ($253 million, or $0.15 per mcfe), asset retirement obligations and all other capitalized miscellaneous costs. These costs exclude future development costs of proved undeveloped reserves, but include costs associated with acquisition of unproved properties on which proved reserves have not been booked. A complete reconciliation of finding and acquisition cost information and a roll-forward of proved reserves is presented on page 11 of this release.

As of September 30, 2005, the company's estimated future net cash flows discounted at 10% before taxes (PV-10) from its proved reserves were $28.6 billion using field differential adjusted prices of $62.01 per bbl (based on a NYMEX quarter-end price of $66.38 per bbl) and $11.36 per mcf (based on a NYMEX quarter-end price of $14.20 per mcf). Chesapeake's PV-10 changes by approximately $267 million for every $0.10 per mcf change in gas prices and approximately $49 million for every $1.00 per bbl change in oil prices. The above figures do not include the impact of the pending CNR acquisition, which would have added approximately $4.2 billion to the PV-10 total above had Chesapeake owned the CNR assets as of September 30, 2005.

Key Operational and Financial Statistics are Summarized Below for the 2005 Third and Second Quarters and the 2004 Third Quarter

The table below summarizes Chesapeake's key results during the 2005 third quarter and compares them to results from the 2005 second quarter and the 2004 third quarter:

Three Months Ended 9/30/05 6/30/05 9/30/04 Average daily production (in mmcfe) 1,308 1,244 1,024 Gas as % of total production 90 89 88 Natural gas production (in bcf) 108.8 101.1 83.2 Average realized gas price ($/mcf) (A) 6.64 5.95 5.17 Oil production (in mbbls) 1,926 2,012 1,834 Average realized oil price ($/bbl) (A) 53.30 42.82 29.15 Natural gas equivalent production (in bcfe) 120.4 113.2 94.2 Gas equivalent realized price ($/mcfe) (A) 6.85 6.08 5.13 Net marketing income ($/mcfe) .07 .05 .04 General and administrative costs ($/mcfe) (B) (.09) (.08) (.09) Stock-based compensation ($/mcfe) (.04) (.02) (.01) Production taxes ($/mcfe) (.44) (.42) (.33) Production expenses ($/mcfe) (.67) (.64) (.57) Interest expense ($/mcfe) (A) (.48) (.48) (.45) DD&A of oil and gas properties ($/mcfe) (1.92) (1.85) (1.63) D & A of other assets ($/mcfe) (.11) (.10) (.08) Operating cash flow ($ in millions) (C) 635.2 513.3 353.4 Operating cash flow ($/mcfe) 5.28 4.53 3.75 Ebitda ($ in millions) (D) 581.4 580.2 361.3 Ebitda ($/mcfe) 4.83 5.13 3.83 Net income to common shareholders ($ in millions) 149.1 179.2 85.6 (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 income before income taxes, interest expense, and depreciation, depletion and amortization expense

Oil and Natural Gas Price Realizations Detailed, Hedging Positions Updated,

Outlooks for 2005 and 2006 Updated and Initial Outlook for 2007 Provided

Average prices realized during the 2005 third quarter (including realized gains or losses from oil and gas derivatives, but excluding unrealized gains or losses on such derivatives) were $53.30 per bbl and $6.64 per thousand cubic feet (mcf), for a realized gas equivalent price of $6.85 per mcfe. Chesapeake's average realized pricing differentials to NYMEX during the third quarter were a negative $4.81 per bbl and a negative $1.14 per mcf. Oil and natural gas hedging activities during the quarter decreased oil and gas sales by $122.6 million, or $5.68 per bbl and $1.03 per mcf, or $1.02 per mcfe.

Chesapeake has added to its 2005, 2006, 2007 and 2008 oil and natural gas hedge positions previously provided in our Outlook dated October 3, 2005. The following tables compare Chesapeake's hedged production volumes through swaps as of October 31, 2005 to those as of October 3, 2005:

Swap Positions as of October 31, 2005 Oil Natural Gas Quarter or Year % Hedge $ NYMEX % Hedged $ NYMEX 2005 3Q 46% $51.66 68% $6.49 2005 4Q 55% $54.97 73% $8.14 2006 1Q 54% $59.71 55% $9.89 2006 2Q 53% $59.60 41% $8.01 2006 3Q 50% $59.83 40% $8.00 2006 4Q 47% $59.45 34% $8.21 2006 Total 51% $59.65 42% $8.63 2007 8% $54.29 7% $9.16 2008 --- --- 2% $8.37 Swap Positions as of October 3, 2005 Oil Natural Gas Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX 2005 3Q 46% $51.66 68% $6.49 2005 4Q 55% $54.97 70% $7.92 2006 1Q 54% $59.64 48% $9.23 2006 2Q 53% $59.57 35% $7.60 2006 3Q 50% $59.85 34% $7.61 2006 4Q 47% $59.55 28% $7.70 2006 Total 51% $59.65 36% $8.14 2007 8% $54.29 3% $8.28

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.

The company's updated 2005, 2006 and 2007 forecasts are attached to this release in an Outlook dated October 31, 2005 labeled as Schedule "A". This Outlook has been changed from the Outlook dated October 3, 2005 (attached as Schedule "B" for investors' convenience) to reflect updated information resulting from the company's operational performance during the third quarter. In addition, the company is providing its initial 2007 forecast, which features projected organic growth of 7% and relatively modest operating cost increases.

Pro forma for Pending CNR Acquisition Company's U.S. Leasehold and 3-D Seismic

Inventories Increase to 8.0 Million and 11.0 Million Net Acres; Proved and Non-Proven Reserves on the Company's Extensive Leasehold Now Exceed 14 Tcfe

Chesapeake's exploratory and development drilling programs and production enhancement operations continue to produce operational results that exceed the company's forecasts and distinguish the company among its peers. During the 2005 third quarter, Chesapeake drilled 241 gross (186 net) operated wells and participated in another 278 gross (32 net) wells operated by other companies. The company's drilling success rate was 97% for both company-operated wells and non-operated wells. During the quarter, Chesapeake invested $390 million in operated wells (using an average of 72 operated rigs), $75 million in non- operated wells (using an average of 65 non-operated rigs) and $91 million in acquiring new 3-D seismic data and new leasehold (excluding leasehold acquired through acquisitions).

During the past seven years and pro forma for the pending CNR acquisition, Chesapeake has built what it believes to be the largest inventories of onshore leasehold (8.0 million net acres) and 3-D seismic (11.0 million acres) in the U.S. On this leasehold, the company has identified more than a 10-year inventory of approximately 25,000 drillsites on which it believes it can develop approximately 2.6 tcfe of proved undeveloped reserves and approximately 7.0 tcfe of non-proven reserves.

Chesapeake characterizes its drilling activity by one of four play types: conventional gas resource, unconventional gas resource, emerging gas resource and Appalachian Basin gas resource. The company's leasehold and proved undeveloped and non-proven reserve totals are set forth below:

* 2.6 million net acres in its traditional conventional areas (i.e., much of the Mid-Continent, Permian, Gulf Coast, South Texas and other areas) on which it has identified approximately 2,300 drillsites, 1.0 tcfe of proved undeveloped reserves and approximately 1.0 tcfe of non-proven reserves; * 1.0 million net acres in its unconventional gas resource areas (i.e., Sahara, Granite/Cherokee/Atoka Washes, Hartshorne CBM, Barnett Shale and Ark-La-Tex tight sands) on which it has identified approximately 12,000 drillsites, 1.2 tcfe of proved undeveloped reserves and approximately 3.4 tcfe of non-proven reserves; * 0.9 million net acres in its emerging gas resource areas (i.e., Fayetteville Shale, Caney/Woodford Shales, Haley Deep and others) on which it has identified approximately 1,200 drillsites, 0.1 tcfe of proved undeveloped reserves and approximately 1.2 tcfe of non-proven reserves; and * 3.5 million net acres in the Appalachian Basin, where play types range from conventional to unconventional to emerging gas resource. On the significant acreage base it is acquiring from CNR, Chesapeake has identified approximately 9,400 drillsites, 0.3 tcfe of proved undeveloped reserves and more than 1.4 tcfe of non-proven reserves.

Chesapeake continues to actively acquire more acreage throughout its operating areas with almost 500,000 acres acquired in the 2005 third quarter through an aggressive land acquisition program that is utilizing more than 600 landmen in the field. In addition to the pending CNR transaction through which the company will acquire 3.5 million net acres in the U.S. and 0.6 million net acres in Canada, Chesapeake's most significant land acquisition activities during the quarter took place in the Arkansas Fayetteville Shale play where the company has increased its acreage holdings to 600,000 net acres from the 200,000 net acres of leasehold previously disclosed. Chesapeake's initial six-well drilling program in the Fayetteville Shale is now underway.

Management Comments

Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "Today's announcement of very strong operational and financial results for the 2005 third quarter provides ongoing confirmation that Chesapeake's business strategy continues to create significant shareholder value. This strategy has generated a 90% increase in our common stock price during the past year and more than a 25-fold increase since our IPO in February 1993 through:

* delivering consistent and value-added growth through a balance of acquisitions and exploratory and developmental drilling; * focusing on natural gas to take advantage of strong long-term natural gas supply/demand fundamentals; and * building dominant regional scale to achieve low operating costs and high returns.

We believe Chesapeake's management team can continue the successful execution of the company's distinctive business strategy and continue to deliver significant shareholder value for years to come."

Conference Call Information

A conference call has been scheduled for Tuesday morning, November 1, 2005 at 9:00 a.m. EST to discuss this earnings release. The telephone number to access the conference call is 719.457.2630. For those unable to participate in the conference call, a replay will be available from 12:00 noon EST, November 1, 2005 through midnight EST on Monday, November 14, 2005. The number to access the conference call replay is 719.457.0820 and the passcode is 2076841. The conference call will also be simulcast live on the Internet and can be accessed at http://www.chkenergy.com/ by selecting "Conference Calls" under the "Investor Relations" section. The webcast of the conference call will be available on the 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 gas reserves, expected oil and gas production and future expenses, projections of future oil and 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, including the acquisition of CNR. 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.

Factors that could cause actual results to differ materially from expected results are described under "Risk Factors" in item 1 of our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 9, 2005. They include the volatility of oil and gas prices; adverse effects our level of indebtedness could have on our operations and future growth; our ability to compete effectively against strong independent oil and gas companies and majors; the availability of capital on an economic basis to fund reserve replacement costs; uncertainties inherent in estimating quantities of oil and gas reserves and projecting future rates of production and the timing of development expenditures; our ability to replace reserves and sustain production; uncertainties in evaluating oil and gas reserves of acquired properties and associated potential liabilities; unsuccessful exploration and development drilling; declines in the values of our oil and gas properties resulting in ceiling test write-downs; lower prices realized on oil and gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; and drilling and operating risks. We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.

Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Also, our internal estimates of reserves, particularly those in the properties recently acquired or proposed to be acquired where we may have limited review of data or experience with the reserves, may be subject to revision and may be different from estimates by our external reservoir engineers at year-end. 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 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 terms "probable", "possible" or "non-proven" 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 being actually realized by the company. While we believe our calculations of non-proven drillsites and estimation of non-proven reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers.

Pro forma for the acquisition of Columbia Natural Resources, LLC and its affiliates, Chesapeake Energy Corporation is the second largest independent producer of natural gas in the U.S. Headquartered in Oklahoma City, the company's operations are focused on exploratory and developmental drilling and property acquisitions in the Mid-Continent, Permian Basin, South Texas, Texas Gulf Coast, Barnett Shale, Ark-La-Tex and Appalachian Basin regions of the United States. The company's Internet address is http://www.chkenergy.com/ .

CHESAPEAKE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS ($ in 000's, except per share data) (unaudited) Three Months Ended Three Months Ended September 30, 2005 September 30, 2004 $ $/mcfe $ $/mcfe REVENUES: Oil and gas sales 720,928 5.99 450,936 4.79 Oil and gas marketing sales 361,915 3.01 178,860 1.90 Total Revenues 1,082,843 9.00 629,796 6.69 OPERATING COSTS: Production expenses 80,765 0.67 54,102 0.57 Production taxes 53,102 0.44 30,872 0.33 General and administrative expenses: General and administrative (excluding stock- based compensation) 10,536 0.09 8,361 0.09 Stock-based compensation 5,249 0.04 584 0.01 Oil and gas marketing expenses 353,510 2.94 175,426 1.86 Oil and gas depreciation, depletion, and amortization 231,145 1.92 153,586 1.63 Depreciation and amortization of other assets 12,902 0.11 7,700 0.08 Total Operating Costs 747,209 6.21 430,631 4.57 INCOME FROM OPERATIONS 335,634 2.79 199,165 2.12 OTHER INCOME (EXPENSE): Interest and other income 2,428 0.02 885 0.01 Interest expense (58,593) (0.48) (48,689) (0.52) Loss on repurchases or exchanges of Chesapeake debt (747) (0.01) --- --- Total Other Income (Expense) (56,912) (0.47) (47,804) (0.51) Income Before Income Taxes 278,722 2.32 151,361 1.61 Income Tax Expense: Current --- --- --- --- Deferred 101,734 0.85 54,489 0.58 Total Income Tax Expense 101,734 0.85 54,489 0.58 NET INCOME 176,988 1.47 96,872 1.03 Preferred stock dividends (10,204) (0.08) (11,287) (0.12) Loss on conversion/ exchange of preferred stock (17,725) (0.15) --- --- NET INCOME AVAILABLE TO COMMON SHAREHOLDERS 149,059 1.24 85,585 0.91 EARNINGS PER COMMON SHARE: Basic $0.46 $0.33 Assuming dilution $0.43 $0.29 WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in 000's): Basic 322,101 257,096 Assuming dilution 367,639 338,285 CHESAPEAKE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS ($ in 000's, except per share data) (unaudited) Nine Months Ended Nine Months Ended September 30, 2005 September 30, 2004 $ $/mcfe $ $/mcfe REVENUES: Oil and gas sales 2,032,271 6.01 1,270,394 4.89 Oil and gas marketing sales 882,040 2.61 496,823 1.91 Total Revenues 2,914,311 8.62 1,767,217 6.80 OPERATING COSTS: Production expenses 222,660 0.66 148,500 0.57 Production taxes 136,313 0.40 68,559 0.26 General and administrative expenses: General and administrative (excluding stock- based compensation) 29,468 0.09 23,947 0.09 Stock-based compensation 10,172 0.03 3,125 0.01 Oil and gas marketing expenses 860,789 2.55 486,205 1.88 Oil and gas depreciation, depletion, and amortization 621,484 1.84 410,237 1.58 Depreciation and amortization of other assets 34,791 0.10 20,155 0.08 Total Operating Costs 1,915,677 5.67 1,160,728 4.47 INCOME FROM OPERATIONS 998,634 2.95 606,489 2.33 OTHER INCOME (EXPENSE): Interest and other income 7,790 0.02 3,563 0.01 Interest expense (155,623) (0.46) (124,040) (0.47) Loss on repurchases or exchanges of Chesapeake debt (70,047) (0.20) (6,925) (0.03) Total Other Income (Expense) (217,880) (0.64) (127,402) (0.49) Income Before Income Taxes 780,754 2.31 479,087 1.84 Income Tax Expense: Current --- --- --- --- Deferred 284,977 0.84 172,470 0.66 Total Income Tax Expense 284,977 0.84 172,470 0.66 NET INCOME 495,777 1.47 306,617 1.18 Preferred stock dividends (25,526) (0.08) (30,799) (0.12) Loss on conversion/ exchange of preferred stock (22,468) (0.07) --- --- NET INCOME AVAILABLE TO COMMON SHAREHOLDERS 447,783 1.32 275,818 1.06 EARNINGS PER COMMON SHARE: Basic $1.42 $1.13 Assuming dilution $1.32 $0.96 WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in 000's): Basic 314,425 245,087 Assuming dilution 352,210 320,089 CHESAPEAKE ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS (in 000's) (unaudited) September 30, December 31, 2005 2004 Cash $127,102 $6,896 Other current assets 1,216,464 560,644 Total Current Assets 1,343,566 567,540 Property and equipment (net) 10,677,424 7,444,384 Other assets 344,639 232,585 Total Assets $12,365,629 $8,244,509 Current liabilities $2,042,478 $963,953 Long term debt 4,250,160 3,075,109 Asset retirement obligation 86,022 73,718 Other long term liabilities 121,521 34,973 Deferred tax liability 1,659,128 933,873 Total Liabilities 8,159,309 5,081,626 STOCKHOLDERS' EQUITY 4,206,320 3,162,883 TOTAL LIABILITIES & STOCKHOLDERS' EQUITY $12,365,629 $8,244,509 COMMON SHARES OUTSTANDING 344,059 311,869 CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF COSTS INCURRED FOR NINE MONTHS ENDED SEPTEMBER 30, 2005 ($ in 000's, except per unit amounts) (unaudited) Reserves Cost (in mmcfe) $/mcfe Exploration and development costs (A) $1,317,984 928,708 $1.42 Acquisition of proved properties 1,108,932 720,953 1.54 Subtotal 2,426,916 1,649,661 1.47 Acquisition of unproved properties 767,595 --- --- Divestitures (1,881) (491) --- Leasehold acquisition costs 164,568 --- --- Geological and geophysical costs 44,300 --- --- Adjusted subtotal 3,401,498 1,649,170 2.06 Tax basis step-up 253,194 --- --- Asset retirement obligation and other 20,130 --- --- Total $3,674,822 1,649,170 $2.23 (A) Reserves include revisions to previous estimates CHESAPEAKE ENERGY CORPORATION ROLL-FORWARD OF PROVED RESERVES (unaudited) Mmcfe Beginning balance, 12/31/04 4,901,751 Extensions and discoveries 853,297 Acquisitions 720,953 Divestitures (491) Revisions-performance (18,612) Revisions-price 94,023 Production (338,164) Ending balance, 9/30/05 6,212,757 Reserve replacement 1,649,170 Reserve replacement rate 488% CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA - OIL & GAS SALES AND INTEREST EXPENSE (in 000's) (unaudited) Three Months Ended Nine Months Ended September 30, September 30, 2005 2004 2005 2004 Oil and Gas Sales ($ in thousands): Oil sales $113,590 $73,921 $290,332 $181,882 Oil derivatives - realized gains (losses) (10,937) (20,464) (28,654) (41,672) Oil derivatives - unrealized gains (losses) (4,009) (14,436) (5,951) (21,925) Total Oil Sales $98,644 $39,021 $255,727 $118,285 Gas sales $833,992 $447,466 $2,005,670 $1,222,783 Gas derivatives - realized gains (losses) (111,668) (17,514) (97,955) (25,976) Gas derivatives - unrealized gains (losses) (100,040) (18,037) (131,171) (44,698) Total Gas Sales $622,284 $411,915 $1,776,544 $1,152,109 Total Oil and Gas Sales $720,928 $450,936 $2,032,271 $1,270,394 Average Sales Price (excluding gains (losses) on derivatives): Oil ($ per bbl) $58.98 $40.31 $51.08 $36.58 Gas ($ per mcf) $7.67 $5.38 $6.60 $5.32 Gas equivalent ($ per mcfe) $7.87 $5.53 $6.79 $5.41 Average Sales Price (excluding unrealized gains (losses) on derivatives): Oil ($ per bbl) $53.30 $29.15 $46.04 $28.20 Gas ($ per mcf) $6.64 $5.17 $6.27 $5.21 Gas equivalent ($ per mcfe) $6.85 $5.13 $6.42 $5.15 Interest Expense ($ in thousands): Interest $58,206 $42,258 $160,209 $118,335 Derivatives - realized (gains) losses (843) 221 (2,639) (184) Derivatives - unrealized (gains) losses 1,230 6,210 (1,947) 5,889 Total Interest Expense $58,593 $48,689 $155,623 $124,040 CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED CASH FLOW DATA (in 000's) (unaudited) THREE MONTHS ENDED: September 30, September 30, 2005 2004 Cash provided by operating activities $558,061 $367,649 Cash (used in) investing activities (1,115,166) (1,068,791) Cash provided by financing activities 684,207 673,978 NINE MONTHS ENDED: September 30, September 30, 2005 2004 Cash provided by operating activities $1,638,368 $1,038,206 Cash (used in) investing activities (3,655,044) (2,668,241) Cash provided by financing activities 2,136,882 1,638,527 CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF CERTAIN FINANCIAL MEASURES (in 000's) (unaudited) THREE MONTHS ENDED: September 30, September 30, 2005 2004 CASH PROVIDED BY OPERATING ACTIVITIES $558,061 $367,649 Adjustments: Changes in assets and liabilities 77,150 (14,252) OPERATING CASH FLOW* $635,211 $353,397

*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 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 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: September 30, September 30, 2005 2004 Net income $176,988 $96,872 Income tax expense 101,734 54,489 Interest expense 58,593 48,689 Depreciation and amortization of other assets 12,902 7,700 Oil and gas depreciation, depletion and amortization 231,145 153,586 EBITDA** $581,362 $361,336

**Ebitda represents net income (loss) before cumulative effect of accounting change, income tax expense (benefit), 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: September 30, September 30, 2005 2004 CASH PROVIDED BY OPERATING ACTIVITIES $558,061 $367,649 Changes in assets and liabilities 77,150 (14,252) Interest expense 58,593 48,689 Unrealized gains (losses) on oil and gas derivatives (104,049) (32,473) Other non-cash items (8,393) (8,277) EBITDA $581,362 $361,336 CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF CERTAIN FINANCIAL MEASURES (in 000's) (unaudited) NINE MONTHS ENDED: September 30, September 30, 2005 2004 CASH PROVIDED BY OPERATING ACTIVITIES $1,638,368 $1,038,206 Adjustments: Changes in assets and liabilities 15,589 (43,082) OPERATING CASH FLOW* $1,653,957 $995,124

*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 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 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.

NINE MONTHS ENDED: September 30, September 30, 2005 2004 Net income $495,777 $306,617 Income tax expense 284,977 172,470 Interest expense 155,623 124,040 Depreciation and amortization of other assets 34,791 20,155 Oil and gas depreciation, depletion and amortization 621,484 410,237 EBITDA** $1,592,652 $1,033,519

**Ebitda represents net income (loss) before cumulative effect of accounting change, income tax expense (benefit), 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:

NINE MONTHS ENDED: September 30, September 30, 2005 2004 CASH PROVIDED BY OPERATING ACTIVITIES $1,638,368 $1,038,206 Changes in assets and liabilities 15,589 (43,082) Interest expense 155,623 124,040 Unrealized gains (losses) on oil and gas derivatives (137,122) (66,623) Other non-cash items (79,806) (19,022) EBITDA $1,592,652 $1,033,519 CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON & ADJUSTED EBITDA

($ in 000's, except per share amounts) (unaudited) Three Months Nine Months Ended Ended September 30, September 30, 2005 2005 Net income available to common shareholders $149,059 $447,783 Adjustments: Loss on conversion/exchange of preferred stock 17,725 22,468 Net Income $166,784 $470,251 Adjustments, net of tax: Unrealized (gains) losses on derivatives 66,851 85,836 Loss on repurchases or exchanges of debt 474 44,480 Adjusted net income available to common* $234,109 $600,567 Adjusted earnings per share assuming dilution** $0.65 $1.71 EBITDA $581,362 $1,592,652 Adjustments, before tax: Unrealized (gains) losses on oil and gas derivatives 104,049 137,122 Loss on repurchases or exchanges of debt 747 70,047 Adjusted EBITDA* $686,158 $1,799,821

*Adjusted net income available to common and adjusted earnings per share assuming dilution and adjusted EBITDA 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 and EBITDA because:

a. Management uses adjusted net income available to common and adjusted EBITDA to evaluate the company's operational trends and performance relative to other oil and gas producing companies. b. Adjusted net income available to common and adjusted EBITDA are more comparable to earnings and EBITDA 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.

**For purposes of calculating fully diluted shares and earnings per share assuming dilution for the three and nine months ended September 30, 2005, accounting rules prohibit the company from assuming the conversion of the 4.125% preferred stock, 4.50% preferred stock and 5.00% (Series 2003) preferred stock for common shares prior to conversion or exchange for either period since the effect would have been anti-dilutive. In determining adjusted earnings per share, we have reflected these shares as though they were converted at the beginning of the period which increases the fully diluted share count to 376.6 million and 365.1 million for the three and nine months ended September 30, 2005, respectively.

SCHEDULE "A" CHESAPEAKE'S OUTLOOK AS OF OCTOBER 31, 2005

Quarter Ending December 31, 2005; Year Ending December 31, 2005; Year Ending December 31, 2006; Year Ending December 31, 2007.

We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of October 31, 2005, we are using the following key assumptions in our projections for the fourth quarter of 2005, the full-year 2005, the full-year 2006 and the full-year 2007.

The primary changes from our October 3, 2005 Outlook are in italicized bold in the table and are explained as follows:

1) We have updated the projected effect of changes in our hedging positions since our October 3, 2005 Outlook. 2) We have updated our expectations for future NYMEX oil and gas prices based on current market conditions in order to illustrate hedging effects only. 3) We have updated certain of our costs to reflect changing market conditions. 4) We have provided our initial guidance for the full-year 2007. 5) We have not reflected any of CNR's derivative positions. We will record such positions at fair value in the purchase price allocation as a liability on the date of acquisition. Changes in fair value subsequent to the acquisition date for the derivative positions assumed will result in adjustments to our oil and gas revenues only upon cash settlement. Quarter Ending Year Ending Year Ending Year Ending 12/31/2005 12/31/2005 12/31/2006 12/31/2007 Estimated Production: Oil - Mbo 1,950 7,650 7,700 7,750 Gas - Bcf 112 - 114 416 - 419 512 - 522 553 - 563 Gas Equivalent - Bcfe 124 - 126 462 - 465 558 - 568 599 - 609 Daily gas equivalent midpoint -in Mmcfe 1,359 1,270 1,543 1,655 NYMEX Prices (for calculation of realized hedging effects only): Oil - $/Bo $60.00 $56.59 $50.00 $50.00 Gas - $/Mcf $10.64 $8.05 $7.00 $7.00 Estimated Differentials to NYMEX Prices: Oil - $/Bo 6-8% 6-8% 6-8% 6-8% Gas - $/Mcf 10-15% 8-12% 8-12% 8-12% Estimated Realized Hedging Effects (based on expected NYMEX prices above): Oil - $/Bo -$2.78 -$4.30 $4.94 $0.35 Gas - $/Mcf -$1.58 -$0.41 $0.80 $0.26 Operating Costs per Mcfe of Projected Production: Production expense $0.70 - 0.74 $0.68 - 0.72 $0.77 - 0.82 $0.80 - 0.85 Production taxes (generally 6.5% of O&G revenues) (A) $0.60 - 0.64 $0.45 - 0.50 $0.40 - 0.45 $0.40 - 0.45 General and administrative $0.10 - 0.12 $0.10 - 0.12 $0.11 - 0.13 $0.11 - 0.13 Stock-based compensation (non-cash) $0.03 - 0.05 $0.03 - 0.05 $0.08 - 0.10 $0.10 - 0.12 DD&A - oil and gas $2.05 - 2.10 $1.85 - 1.95 $2.15 - 2.20 $2.25 - 2.30 Depreciation of other assets $0.10 - 0.12 $0.09 - 0.11 $0.10 - 0.12 $0.11 - 0.13 Interest expense (B) $0.48 - 0.52 $0.45 - 0.49 $0.48 - 0.53 $0.50 - 0.55 Other Income and Expense per Mcfe: Marketing and other income $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04 Book Tax Rate (approximately equal to 95% deferred) 36.5% 36.5% 36.5% 36.5% Equivalent Shares Outstanding: Basic 345 mm 322 mm 360 mm 364 mm Diluted 406 mm 375 mm 424 mm 429 mm Capital Expenditures: Drilling, leasehold and seismic $575 - $2,000 - $2,700 - $3,100 - 625 mm 2,200 mm 2,900 mm 3,300 mm (A) Severance tax per mcfe is based on NYMEX prices of $60.00 per bo and natural gas prices ranging from $9.00 to $11.30 per mcf during Q4 2005, $60.00 per bo and natural gas prices ranging from $7.25 to $12.50 per mcf during calendar 2005, $50.00 per bo and $6.75 to $7.60 per mcf during calendar 2006 and 2007. (B) 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 gas production. These strategies include:

(i) For swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price, as defined in each instrument, 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) Basis protection swaps are arrangements that guarantee a price differential of oil or gas from a specified delivery point. 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.

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 gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and 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 non-qualifying 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 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.

The company currently has in place the following natural gas swaps: % Hedged Open Swap Avg. Avg. NYMEX Positions NYMEX Gain Price as a % of Strike (Loss) Including Assuming Estimated Open Price from Open Gas Total Swaps Of Open Locked & Locked Production Gas in Bcf's Swaps Swaps Positions in Bcf's of: Production 2005: Q4 2005(A) 82.2 $8.27 -$0.13 $8.14 113.0 73% 2006: Q1 67.5 $10.01 -$0.12 $9.89 122.0 55% Q2 51.9 $8.11 -$0.10 $8.01 127.0 41% Q3 52.4 $8.10 -$0.10 $8.00 132.0 40% Q4 45.7 $8.31 -$0.10 $8.21 136.0 34% Total 2006(A) 217.5 $8.74 -$0.11 $8.63 517.0 42% Total 2007 38.1 $9.47 -$0.31 $9.16 558.0 7% Total 2008 11.0 $8.37 --- $8.37 585.0 2% (A) Certain hedging arrangements include swaps with knockout prices ranging from $3.75 to $5.50 covering 20.1 bcf in 2005 and $3.75 to $5.50 covering 43.0 bcf in 2006.

Note: Not shown above are collars covering 1.4 bcf of production in 2005 at a weighted average floor and ceiling of $3.49 and $5.27 and 0.2 bcf of production in 2006 at a weighted average floor and ceiling of $6.00 and $9.70 and call options covering 1.8 bcf of production in 2005 at a weighted average price of $5.86, 7.3 bcf of production in 2006 at a weighted average price of $12.50, 7.3 bcf of production in 2007 at a weighted average price of $12.50 and 7.3 bcf of production in 2008 at a weighed average price of $12.50.

The company has also entered into the following natural gas basis protection swaps:

Assuming Gas Volume Production in Bcf's NYMEX less*: in Bcf's of: % Hedged 4th Quarter 2005 49.4 $0.27 113 44% 2006 130.1 0.32 517 25% 2007 126.5 0.28 558 23% 2008 118.6 0.27 585 20% 2009 86.6 0.29 615 14% Totals 511.2 $0.29 2,388 21% * weighted average The company has entered into the following crude oil hedging arrangements: % Hedged Open Swap Positions as % of Assuming Total Open Swaps Avg. NYMEX Oil Production Estimated in mbo's Strike Price in mbo's of: Production 2005: Q4 2005(A) 1,073.5 $54.97 1,950.0 55% 2006: Q1 1,035.0 $59.71 1,900.0 54% Q2 1,016.5 $59.60 1,920.0 53% Q3 966.0 $59.83 1,940.0 50% Q4 920.0 $59.45 1,940.0 47% Total 2006(A) 3,937.5 $59.65 7,700.0 51% Total 2007 635.0 $54.29 7,750.0 8% (A) Certain hedging arrangements include swaps with knockout prices ranging from $26.00 to $42.00 covering 276 mbo in 2005 and $40.00 to $42.00 covering 501.5 mbo in 2006. SCHEDULE "B" CHESAPEAKE'S PREVIOUS OUTLOOK AS OF OCTOBER 3, 2005 (PROVIDED FOR REFERENCE ONLY) NOW SUPERSEDED BY OUTLOOK AS OF OCTOBER 31, 2005

Quarter Ending September 30, 2005; Quarter Ending December 31, 2005; Year Ending December 31, 2005; Year Ending December 31, 2006.

We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of October 3, 2005, we are using the following key assumptions in our projections for the third quarter of 2005, the fourth quarter of 2005, the full-year 2005 and the full-year 2006.

The primary changes from our September 7, 2005 Outlook are in italicized bold in the table and are explained as follows:

1) We have shown the operational and financial effects of the pending acquisition and anticipated financing as described in our press release dated October 3, 2005. We have assumed that the CNR acquisition will close no later than December 15, 2005. 2) We have updated the projected effect of changes in our hedging positions since our September 7, 2005 Outlook. 3) We have updated our expectations for future NYMEX oil and gas prices based on current market conditions in order to illustrate hedging effects only. 4) We have updated certain of our costs to reflect changing market conditions and the impact of the CNR acquisition. 5) We have increased our estimated basic common share count to reflect the common stock issued in connection with the exchanges of a portion of our preferred stock during September 2005. 6) We have provided guidance for the fourth quarter of 2005. Quarter Quarter Ending Ending Year Ending Year Ending 9/30/2005 12/31/2005 12/31/2005 12/31/2006 Estimated Production: Oil - Mbo 1,950 1,950 7,650 7,700 Gas - Bcf 107 - 109 112 - 114 416 - 419 512 - 522 Gas Equivalent - Bcfe 118.5 - 120.5 124 - 126 462 - 465 558 - 568 Daily gas equivalent midpoint - in Mmcfe 1,300 1,359 1,270 1,543 NYMEX Prices (for calculation of realized hedging effects only): Oil - $/Bo $61.34 $60.00 $56.09 $50.00 Gas - $/Mcf $8.53 $9.00 $7.64 $7.00 Estimated Differentials to NYMEX Prices: Oil - $/Bo -$4.50 -$4.50 -$4.50 -$4.50 Gas - $/Mcf -$0.80 -$1.50 -$1.00 -$1.00 Estimated Realized Hedging Effects (based on expected NYMEX prices above): Oil - $/Bo -$4.48 -$2.78 -$4.09 $4.94 Gas - $/Mcf -$1.21 -$0.33 -$0.21 $0.66 Operating Costs per Mcfe of Projected Production: Production expense $0.68 - 0.72 $0.70 - 0.74 $0.68 - 0.72 $0.77 - 0.82 Production taxes (generally 7% of O&G revenues) (A) $0.51 - 0.56 $0.56 - 0.60 $0.45 - 0.50 $0.45 - 0.50 General and administrative $0.10 - 0.12 $0.10 - 0.12 $0.10 - 0.12 $0.11 - 0.13 Stock-based compensation (non-cash) $0.03 - 0.05 $0.03 - 0.05 $0.03 - 0.05 $0.04 - 0.06 DD&A - oil and gas $1.85 - 1.95 $2.05 - 2.10 $1.85 - 1.95 $2.15 - 2.20 Depreciation of other assets $0.09 - 0.11 $0.10 - 0.12 $0.09 - 0.11 $0.10 - 0.12 Interest expense (B) $0.48 - 0.52 $0.48 - 0.52 $0.45 - 0.49 $0.48 - 0.53 Other Income and Expense per Mcfe: Marketing and other income $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04 Book Tax Rate (approximately equal to 95% deferred) 36.5% 36.5% 36.5% 36.5% Equivalent Shares Outstanding: Basic 322 mm 342 mm 321 mm 355 mm Diluted 376 mm 399 mm 373 mm 418 mm Capital Expenditures: Drilling, leasehold and seismic $485 - $575 - $2,000 - $2,500 - $535 mm $625 mm $2,200 mm $2,700 mm (A) Severance tax per mcfe is based on NYMEX prices of $60.00 per bo and natural gas prices ranging from $8.70 to $10.00 per mcf during Q3 2005, $60.00 per bo and natural gas prices ranging from $9.25 to $10.00 per mcf during Q4 2005, $60.00 per bo and natural gas prices ranging from $8.25 to $10.00 per mcf during calendar 2005 and $50.00 per bo and $7.15 to $7.90 per mcf during calendar 2006. (B) 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 gas production. These strategies include:

(i) For swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price, as defined in each instrument, 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) Basis protection swaps are arrangements that guarantee a price differential of oil or gas from a specified delivery point. 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.

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 gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and 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 non-qualifying 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 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.

The company currently has in place the following natural gas swaps: % Hedged Open Swap Avg. Avg. NYMEX Positions NYMEX Gain Price as a % of Strike (Loss) Including Assuming Estimated Open Price from Open Gas Total Swaps Of Open Locked & Locked Production Gas in Bcf's Swaps Swaps Positions in Bcf's of: Production 2005: Q3 72.9 $6.64 -$0.15 $6.49 108.0 68% Q4 79.5 $8.06 -$0.14 $7.92 113.0 70% Remaining 2005(A) 152.4 $7.38 -$0.14 $7.24 221.0 69% 2006: Q1 58.5 $9.38 -$0.15 $9.23 122.0 48% Q2 44.6 $7.73 -$0.13 $7.60 127.0 35% Q3 45.1 $7.73 -$0.12 $7.61 132.0 34% Q4 38.4 $7.82 -$0.12 $7.70 136.0 28% Total 2006 (A) 186.6 $8.27 -$0.13 $8.14 517.0 36% Total 2007 14.4 $9.09 -$0.81 $8.28 555.0 3% (A) Certain hedging arrangements include swaps with knockout prices ranging from $3.75 to $5.50 covering 42.6 bcf in 2005 and $3.75 to $5.50 covering 43.0 bcf in 2006.

Note: Not shown above are collars covering 3.0 bcf of production in 2005 at a weighted average floor and ceiling of $3.59 and $5.37 and 0.2 bcf of production in 2006 at a weighted average floor and ceiling of $6.00 and $9.70 and call options covering 3.7 bcf of production in 2005 at a weighted average price of $5.79, 7.3 bcf of production in 2006 at a weighted average price of $12.50 and 7.3 bcf of production in 2007 at a weighted average price of $12.50.

The company has also entered into the following natural gas basis protection swaps:

Assuming Gas Production Volume in Bcf's NYMEX less*: in Bcf's of: % Hedged 3rd & 4th Quarter 2005 96.3 $0.27 221 44% 2006 130.1 0.32 517 25% 2007 126.5 0.28 555 23% 2008 118.6 0.27 580 20% 2009 86.6 0.29 605 14% Totals 558.1 $0.29 2,478 23% * weighted average The company has entered into the following crude oil hedging arrangements: % Hedged Open Swap Positions as % of Assuming Total Open Swaps Avg. NYMEX Oil Production Estimated in mbo's Strike Price in mbo's of: Production 2005: Q3 903.5 $51.66 1,950 46% Q4 1,073.5 $54.97 1,950 55% Remaining 2005 (A) 1,977.0 $53.46 3,900 51% 2006: Q1 1,035.0 $59.64 1,900.0 54% Q2 1,016.5 $59.57 1,920.0 53% Q3 966.0 $59.85 1,940.0 50% Q4 920.0 $59.55 1,940.0 47% Total 2006 (A) 3,937.5 $59.65 7,700.0 51% Total 2007 635.0 $54.29 7,750.0 8% (A) Certain hedging arrangements include swaps with knockout prices ranging from $26.00 to $42.00 covering 552 mbo in 2005 and $40.00 to $42.00 covering 501.5 mbo in 2006.