Chesapeake Energy Corporation Reports Strong Results for the 2005 Firs

OKLAHOMA CITY, May 2 /PRNewswire-FirstCall/ -- Chesapeake Energy Corporation today reported financial and operating results for the first quarter of 2005. For the quarter, Chesapeake generated net income available to common shareholders of $119.5 million ($0.36 per fully diluted common share), operating cash flow of $505.5 million (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $431.0 million (defined as income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $783.5 million and production of 104.6 billion cubic feet of natural gas equivalent (bcfe).

The company's 2005 first 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 first quarter reported results are described as follows:

* an unrealized mark-to-market loss of $72.4 million resulting from the company's oil and natural gas and interest rate hedging programs; and * a $0.6 million loss resulting from the early extinguishment of certain Chesapeake debt securities.

Adjusted for the above-mentioned losses, Chesapeake's net income to common shareholders in the 2005 first quarter would have been $192.6 million ($0.56 per fully diluted common share) and ebitda would have been $549.1 million. The foregoing items do not affect the calculation of operating cash flow. A reconciliation of operating cash flow, ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 11-12 of this release.

Oil and Natural Gas Production Sets Record for 15th Consecutive Quarter; 2005 First Quarter Average Daily Production Increases 34% Over 2004 First Quarter and 4% Over Sequential 2004 Fourth Quarter

Daily production for the 2005 first quarter averaged 1,162 million cubic feet of natural gas equivalent (mmcfe), an increase of 295 mmcfe, or 34%, over the 867 mmcfe produced per day in the 2004 first quarter and an increase of 43 mmcfe, or 4%, over the 1,119 mmcfe produced per day in the 2004 fourth quarter. Of the 295 mmcfe daily increase in year-over-year production, 60% came from organic growth and 40% from acquisitions, making the company's trailing 12 month organic growth rate 20%. Of the 43 mmcfe daily increase in sequential quarterly production, 60% came from organic growth and 40% from acquisition growth, making the company's quarterly organic growth rate 2.3%. The company's 2005 first quarter production exceeded its February 22, 2005 forecasted mid-point production by 3.1 bcfe, or 3%, because of stronger than projected drilling and operational results.

Chesapeake's 2005 first quarter production of 104.6 bcfe was comprised of 94.1 billion cubic feet of natural gas (bcf) (90% on a natural gas equivalent basis) and 1.75 million barrels of oil and natural gas liquids (mmbo) (10% on a natural gas equivalent basis). Chesapeake's average daily production rate for the quarter of 1,162 mmcfe consisted of 1,046 mmcf of gas and 19,400 barrels of oil and natural gas liquids.

The 2005 first quarter was Chesapeake's 15th consecutive quarter of production growth. During these 15 quarters, Chesapeake's U.S. production has increased 190%, for an average compound quarterly growth rate of 7.4% and an average compound annual growth rate of 32.6%.

Oil and Natural Gas Proved Reserves Reach Record Level of 5.4 Tcfe; Drilling and Acquisition Costs are $1.20 per Mcfe as Company Adds 532 Bcfe and Replaces Production by 609%

Chesapeake began 2005 with estimated proved reserves of 4.902 trillion cubic feet of natural gas equivalent (tcfe) and ended the first quarter with 5.434 tcfe, an increase of 532 bcfe, or 11%. During the 2005 first quarter, the company replaced its 105 bcfe of production with an estimated 637 bcfe of new proved reserves, for a reserve replacement rate of 609% at a drilling and acquisition cost of $1.20 per thousand cubic feet of natural gas equivalent (mcfe). Reserve replacement through the drillbit was 333 bcfe, or 318% of production (including 45 bcfe from positive performance revisions and 30 bcfe from oil and natural gas price increases), or 52% of the total increase, at a cost of $1.13 per mcfe. Reserve replacement through acquisitions was 304 bcfe, or 291% of production, or 48% of the total increase, at a cost of $1.26 per mcfe.

Total costs incurred during the 2005 first quarter were $1.87 per mcfe, which includes drilling, completion, acquisition, seismic, leasehold, capitalized internal costs, non-cash tax basis step-up from the BRG corporate acquisition ($120 million, or $0.19 per mcfe), asset retirement obligations and all other capitalized miscellaneous costs. These costs exclude future development costs of proved undeveloped reserves. A complete reconciliation of finding and acquisition cost information and a roll forward of proved reserves is presented on page 9 of this release.

As of March 31, 2005, the company's estimated future net cash flows discounted at 10% before taxes (PV-10) from its proved reserves were $14.2 billion using field differential adjusted prices of $51.38 per bo (based on a NYMEX quarter-end price of $55.32 per bo) and $6.65 per mcf (based on a NYMEX quarter-end price of $7.17 per mcf). Chesapeake's PV-10 changes by approximately $236 million for every $0.10 per mcf change in gas prices and approximately $43 million for every $1.00 per bo change in oil prices.

These figures above do not include 206 bcfe of estimated proved reserves associated with $459 million of acquisitions that were announced on April 12, 2005, but not yet closed as of March 31, 2005.

Average Prices Realized, Hedging Results and Hedging Positions Detailed

Average prices realized during the 2005 first quarter (including realized gains or losses from oil and gas derivatives, but excluding unrealized gains or losses on such derivatives) were $41.74 per bo and $6.20 per mcf, for a realized gas equivalent price of $6.27 per mcfe. Chesapeake's average realized pricing differentials to NYMEX during the first quarter were a negative $4.07 per bo and a negative $0.75 per mcf. Realized gains or losses from oil and natural gas hedging activities during the quarter generated a $4.05 loss per bo and a $0.51 gain per mcf, for a 2005 first quarter realized hedging gain of $40.3 million, or $0.39 per mcfe.

Chesapeake has added to its 2005, 2006 and 2007 oil and natural gas hedge positions previously announced on April 12, 2005. The following tables compare Chesapeake's hedged production volumes as of May 2, 2005 to those as of April 12, 2005:

Hedged Positions as of May 2, 2005 Oil Natural Gas Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX 2005 1Q 50% $41.87 66% $6.82 2005 2Q 65% $43.98 65% $6.14 2005 3Q 35% $48.46 57% $6.28 2005 4Q 30% $48.46 38% $6.46 2005 Total 45% $45.01 56% $6.42 2006 16% $54.77 18% $6.85 2007 5% $50.79 --- --- Hedged Positions as of April 12, 2005 Oil Natural Gas Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX 2005 1Q 53% $41.87 68% $6.82 2005 2Q 63% $43.76 64% $6.12 2005 3Q 29% $47.59 54% $6.22 2005 4Q 24% $47.32 34% $6.36 2005 Total 42% $44.40 54% $6.39 2006 11% $55.68 17% $6.79 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.

The company's updated 2005 and 2006 forecasts are attached to this release in an Outlook dated May 2, 2005 labeled as Schedule "A". This Outlook has been changed from the Outlook dated April 12, 2005 (attached as Schedule "B" for investors' convenience) to reflect updated information.

Key Operational and Financial Statistics are Summarized Below for the 2005 First Quarter

The table below summarizes Chesapeake's key results during the 2005 first quarter and compares them to the 2004 fourth quarter and the 2004 first quarter:

Three Months Ended 3/31/05 12/31/04 3/31/04 Average daily production (in mmcfe) 1,162 1,119 867 Gas as % of total production 90 90 89 Natural gas production (in bcf) 94.1 92.2 70.1 Average realized gas price ($/mcf) (A) 6.20 5.50 5.62 Oil production (in mbbls) 1,746 1,792 1,465 Average realized oil price ($/bo) (A) 41.74 28.70 27.10 Natural gas equivalent production (in bcfe) 104.6 102.9 78.9 Gas equivalent realized price ($/mcfe) (A) 6.27 5.42 5.50 Net marketing income ($/mcfe) .07 .07 .05 General and administrative costs ($/mcfe) (B) (.09) (.08) (.10) Production taxes ($/mcfe) (.34) (.34) (.19) (E) Production expenses ($/mcfe) (.66) (.55) (.57) Interest expense ($/mcfe) (A) (.44) (.43) (.48) DD&A of oil and gas properties ($/mcfe) (1.73) (1.67) (1.52) D & A of other assets ($/mcfe) (.10) (.09) (.07) Operating cash flow ($ in millions) (C) 505.5 423.7 333.6 Operating cash flow ($/mcfe) 4.83 4.12 4.23 Ebitda ($ in millions) (D) 431.0 550.1 348.1 Ebitda ($/mcfe) 4.12 5.34 4.41 Net income to common shareholders ($ in millions) 119.5 163.2 104.4 (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 (E) includes pre-tax benefit of $6.8 million, or $0.09 per mcfe, related to prior period severance tax credits Company's Leasehold and 3-D Seismic Inventories Now Exceed 3.5 Million and 10 Million Net Acres; Identified Non-Proved Reserves in Company's Extensive Gas Resource Plays Exceed 4.0 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 first quarter, Chesapeake drilled 189 gross (143 net) operated wells and participated in another 209 gross (26 net) wells operated by other companies. The company's drilling success rate was 98% for company-operated wells and 97% for non-operated wells. During the quarter, Chesapeake invested $302 million in operated wells (using an average of 69 operated rigs), $75 million in non- operated wells (using an average of approximately 64 non-operated rigs) and $66 million in acquiring new 3-D seismic data and new leases (excluding leases acquired through acquisitions).

In addition to continuing to make significant additions to the company's existing core leasehold positions in the Anadarko and Arkoma Basins, South Texas, Texas Gulf Coast and Permian Basin projects, Chesapeake has also been aggressively building significant leasehold positions through acquisitions and leasing activities in the following gas resource plays: Sahara in the northwestern Anadarko Basin (approximately 600,000 prospective net acres acquired to date), the Mountain Front Deep Springer play in the western and southern Anadarko Basin (approximately 100,000 prospective net acres acquired to date), the Granite Wash and Cherokee/Atoka Wash plays in the western Anadarko Basin (approximately 200,000 prospective net acres acquired to date), the Hartshorne Coal and the Caney, Woodford and Fayetteville Shale plays of the Arkoma Basin (approximately 250,000 prospective acres acquired to date), the Barnett Shale play in North Texas (approximately 30,000 prospective net acres acquired to date, mainly in northern Johnson County), the Cotton Valley play in Northern Louisiana's Sligo Field (25,000 prospective net acres acquired to date) and, most recently, the Haley Deep play in West Texas (approximately 100,000 prospective net acres acquired to date).

Chesapeake believes it has built the largest onshore U.S. inventory of leasehold and 3-D seismic in the industry (more than 3.5 million and 10 million net acres, respectively) and believes it has identified a seven- year drilling backlog of approximately 7,000 locations on which the company expects to develop more than 4.0 tcfe of internally estimated non-proved reserves.

Management Comments

Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "Today's announcement of very strong operational and financial results for the 2005 first quarter provides ongoing confirmation that Chesapeake's business strategy continues to create significant shareholder value. This strategy has generated an approximate 60% increase in our common stock price during the past year and an approximate 1,500% increase since our IPO in February 1993 through:

* delivering growth through a balance of acquisitions and organic 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 on capital.

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, May 3, 2005 at 9:00 a.m. EDT to discuss this earnings release. The telephone number to access the conference call is 913.981.5582. For those unable to participate in the conference call, a replay will be available from 12:00 noon EDT, May 3, 2005 through midnight EDT on May 17, 2005. The number to access the conference call replay is 719.457.0820 and the passcode is 4449787. 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. 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-proved" 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.

Chesapeake Energy Corporation is the fourth 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 and Ark-La-Tex 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: March 31, 2005 March 31, 2004 $ $/mcfe $ $/mcfe REVENUES: Oil and gas sales 538,942 5.15 419,793 5.32 Oil and gas marketing sales 244,508 2.34 143,336 1.82 Total Revenues 783,450 7.49 563,129 7.14 OPERATING COSTS: Production expenses 69,562 0.66 44,803 0.57 Production taxes 35,958 0.34 14,936 0.19 General and administrative expenses: General and administrative (excluding stock- based compensation) 9,650 0.09 8,166 0.10 Stock-based compensation 2,417 0.02 1,869 0.02 Oil and gas marketing expenses 237,276 2.28 139,664 1.78 Oil and gas depreciation, depletion, and amortization 180,968 1.73 119,908 1.52 Depreciation and amortization of other assets 10,082 0.10 5,739 0.07 Total Operating Costs 545,913 5.22 335,085 4.25 INCOME FROM OPERATIONS 237,537 2.27 228,044 2.89 OTHER INCOME (EXPENSE): Interest and other income 3,357 0.03 1,343 0.02 Interest expense (43,128) (0.41) (46,545) (0.59) Loss on repurchases or exchanges of Chesapeake debt (900) (0.01) (6,925) (0.09) Total Other Income (Expense) (40,671) (0.39) (52,127) (0.66) Income Before Income Taxes 196,866 1.88 175,917 2.23 Income Tax Expense: Current --- --- --- --- Deferred 71,856 0.69 63,327 0.80 Total Income Tax Expense 71,856 0.69 63,327 0.80 NET INCOME 125,010 1.19 112,590 1.43 Preferred stock dividends (5,463) (0.05) (8,168) (0.11) NET INCOME AVAILABLE TO COMMON SHAREHOLDERS 119,547 1.14 104,422 1.32 EARNINGS PER COMMON SHARE: Basic $0.39 $0.44 Assuming dilution $0.36 $0.38 WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in 000's): Basic 309,857 236,884 Assuming dilution 351,357 299,604 CHESAPEAKE ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS (in 000's) (unaudited) March 31, December 31, 2005 2004 Cash $--- $6,896 Other current assets 592,941 560,644 Total Current Assets 592,941 567,540 Property and equipment (net) 8,506,657 7,444,384 Other assets 243,813 232,585 Total Assets $9,343,411 $8,244,509 Current liabilities $1,165,841 $963,953 Long term debt 3,718,679 3,075,109 Asset retirement obligation 78,845 73,718 Long term liabilities 62,473 34,973 Deferred tax liability 1,149,372 933,873 Total Liabilities 6,175,210 5,081,626 STOCKHOLDERS' EQUITY 3,168,201 3,162,883 TOTAL LIABILITIES & STOCKHOLDERS' EQUITY $9,343,411 $8,244,509 COMMON SHARES OUTSTANDING 315,103 311,869 CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF FIRST QUARTER 2005 COSTS INCURRED ($ in 000's, except per unit amounts) (unaudited) Reserves Cost (in mmcfe) $/mcfe Exploration and development costs (A) $376,794 332,577 $1.13 Acquisition of proved properties 384,953 304,328 1.26 Subtotal 761,747 636,905 1.20 Acquisition of unproved properties 224,532 --- --- Divestitures --- --- --- Leasehold acquisition costs 51,839 --- --- Geological and geophysical costs 14,247 --- --- Adjusted subtotal 1,052,365 636,905 1.65 Tax basis step-up 119,498 --- --- Asset retirement obligation and other 18,289 --- --- Total $1,190,152 636,905 $1.87 (A) Reserves include revisions to previous estimates CHESAPEAKE ENERGY CORPORATION ROLLFORWARD OF RESERVES (unaudited) Mmcfe Beginning balance, 12/31/04 4,901,751 Production (104,607) Acquisitions 304,328 Divestitures --- Revisions-performance 45,054 Revisions-price 29,915 Extensions and discoveries 257,608 Ending balance, 3/31/05 5,434,049 Reserve replacement 636,905 Reserve replacement rate 609% CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA - OIL & GAS SALES AND INTEREST EXPENSE (unaudited) THREE MONTHS ENDED: March 31, March 31, 2005 2004 Oil and Gas Sales ($ in thousands): Oil sales $79,944 $48,031 Oil derivatives - realized gains (losses) (7,067) (8,330) Oil derivatives - unrealized gains (losses) (12,842) (6,019) Total Oil Sales $60,035 $33,682 Gas sales $535,777 $360,101 Gas derivatives - realized gains (losses) 47,415 33,991 Gas derivatives - unrealized gains (losses) (104,285) (7,981) Total Gas Sales $478,907 $386,111 Total Oil and Gas Sales $538,942 $419,793 Average Sales Price (excluding gains (losses) on derivatives): Oil ($ per bbl) $45.79 $32.79 Gas ($ per mcf) $5.69 $5.14 Gas equivalent ($ per mcfe) $5.89 $5.17 Average Sales Price (excluding unrealized gains (losses) on derivatives): Oil ($ per bbl) $41.74 $27.10 Gas ($ per mcf) $6.20 $5.62 Gas equivalent ($ per mcfe) $6.27 $5.50 Interest Expense ($ in thousands): Interest $47,293 $38,564 Derivatives - realized (gains) losses (1,121) (758) Derivatives - unrealized (gains) losses (3,044) 8,739 Total Interest Expense $43,128 $46,545 CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED CASH FLOW DATA (in 000's) (unaudited) THREE MONTHS ENDED: March 31, March 31, 2005 2004 Cash provided by operating activities $513,526 $341,770 Cash (used in) investing activities (1,173,937) (735,434) Cash provided by financing activities 653,515 542,508 CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF CERTAIN FINANCIAL MEASURES (in 000's) (unaudited) THREE MONTHS ENDED: March 31, March 31, 2005 2004 CASH PROVIDED BY OPERATING ACTIVITIES $513,526 $341,770 Adjustments: Changes in assets and liabilities (8,063) (8,216) OPERATING CASH FLOW* $505,463 $333,554

*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: March 31, March 31, 2005 2004 Net income $125,010 $112,590 Income tax expense 71,856 63,327 Interest expense 43,128 46,545 Depreciation and amortization of other assets 10,082 5,739 Oil and gas depreciation, depletion and amortization 180,968 119,908 EBITDA** $431,044 $348,109

**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: March 31, March 31, 2005 2004 CASH PROVIDED BY OPERATING ACTIVITIES $513,526 $341,770 Changes in assets and liabilities (8,063) (8,216) Interest expense 43,128 46,545 Unrealized gains (losses) on oil and gas derivatives (117,127) (14,000) Other non-cash items (420) (17,990) EBITDA $431,044 $348,109 CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED EARNINGS & ADJUSTED EBITDA ($ in 000's, except per share amounts) (unaudited) THREE MONTHS ENDED: March 31, 2005 Net income available to common shareholders $119,547 Adjustments, net of tax: Unrealized (gains) losses on derivatives 72,443 Loss on repurchases or exchanges of debt 572 Adjusted earnings* $192,562 Adjusted earnings per share assuming dilution $0.56 EBITDA $431,044 Adjustments, before tax: Unrealized (gains) losses on oil and gas derivatives 117,127 Loss on repurchases or exchanges of debt 900 Adjusted EBITDA* $549,071

*Adjusted earnings 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 earnings and adjusted EBITDA to evaluate the Company's operational trends and performance relative to other oil and gas producing companies. b. Adjusted earnings 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. SCHEDULE "A" CHESAPEAKE'S OUTLOOK AS OF MAY 2, 2005

Quarter Ending June 30, 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 May 2, 2005, we are using the following key assumptions in our projections for the second quarter of 2005, the full-year 2005 and the full-year 2006.

The primary changes from our April 12, 2005 Outlook are in the table and are explained as follows:

1) We have updated the projected effects from changes in our hedging positions since our April 12, 2005 Outlook. 2) We have updated certain of our cost and oil and natural gas price differentials to reflect changing market conditions. 3) We have included our expectations for future NYMEX oil and gas prices to illustrate hedging effects only. 4) We have increased our capital expenditure projections to reflect anticipated higher levels of drilling activity and continuing service cost inflation. 5) We have increased our estimated diluted share count to reflect the common shares issuable upon conversion of our recently issued $460 million preferred stock issuance. Quarter Ending Year Ending Year Ending June 30, December 31, December 31, 2005 2005 2006 Estimated Production: Oil - Mbo 1,770 7,000 7,300 Gas - Bcf 98-100 403 - 411 457 - 467 Gas Equivalent - Bcfe 108.5 - 110.5 445 - 453 501 - 511 Daily gas equivalent midpoint - in Mmcfe 1,203 1,230 1,386 NYMEX Prices (for calculation of realized hedging effects only): Oil - $/Bo $45.00 $46.21 $45.00 Gas - $/Mcf $6.78 $6.51 $6.50 Estimated Differentials to NYMEX Prices: Oil - $/Bo -$4.00 -$4.00 -$4.00 Gas - $/Mcf -$0.80 -$0.80 -$0.80 Estimated Realized Hedging Effects (based on expected NYMEX prices above): Oil - $/Bo -$0.65 -$0.65 $1.52 Gas - $/Mcf -$0.25 $0.17 $0.11 Operating Costs per Mcfe of Projected Production: Production expense $0.68 - 0.72 $0.68 - 0.72 $0.72 - 0.77 Production taxes (generally 7% of O&G revenues) (A) $0.40 - 0.45 $0.40 - 0.45 $0.40 - 0.45 General and administrative $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 $0.04 - 0.06 DD&A - oil and gas $1.75 - 1.85 $1.75 - 1.85 $1.85 - 1.95 Depreciation of other assets $0.09 - 0.11 $0.09 - 0.11 $0.10 - 0.12 Interest expense (B) $0.43 - 0.47 $0.43 - 0.47 $0.43 - 0.47 Other Income and Expense per Mcfe: Marketing and other income $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% Equivalent Shares Outstanding: Basic 312 mm 315 mm 318 mm Diluted 370 mm 366 mm 373 mm Capital Expenditures: Drilling, leasehold and seismic $425 - $1,700 - $1,900 - $475 mm $1,900 mm $2,100 mm (A) Severance tax per mcfe is based on NYMEX prices of $45.00 per barrel of oil and natural gas prices ranging from $6.00-$7.20 during Q2 2005, $6.50-$7.50 during calendar 2005, and $6.35-$7.25 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 Avg. Avg. Open Swap NYMEX Gain NYMEX Price Positions Strike (Loss) Including as a % of Open Price from Open & Assuming Gas Estimated Swaps Of Open Locked Locked Production Total Gas in Bcf's Swaps Swaps Positions in Bcf's of: Production 2005: 1st Qtr 62.2 $7.00 -$0.18 $6.82 94.1 66% 2nd Qtr 64.0 $6.30 -$0.16 $6.14 99.0 65% 3rd Qtr 59.8 $6.46 -$0.18 $6.28 105.5 57% 4th Qtr 40.9 $6.73 -$0.27 $6.46 108.4 38% Total 2005 (A) 226.9 $6.61 -$0.19 $6.42 407.0 56% Total 2006 (A) 82.1 $7.14 -$0.29 $6.85 462.0 18% TOTALS 2005-2006 309.0 $6.75 -$0.22 $6.53 869.0 36% (A) Certain hedging arrangements include swaps with knockout prices ranging from $3.75 to $5.50 covering 79.5 bcf in 2005 and $3.75 to $5.50 covering 35.7 bcf in 2006.

Note: Not shown above are collars covering 4.4 bcf of production in 2005 at a weighted average floor and ceiling of $3.10 and $4.44 and call options covering 7.3 bcf of production in 2005 at a weighted average price of $6.00.

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 2005 188.6 $0.26 407.0 46% 2006 130.1 0.32 462.0 28% 2007 126.5 0.28 490.0 26% 2008 118.6 0.27 515.0 23% 2009 86.6 0.29 540.0 16% Totals 650.4 $0.28 2,414.0 27% * weighted average The company has entered into the following crude oil hedging arrangements: % Hedged Open Swap Positions Assuming Oil as % of Total Open Swaps Avg. NYMEX Production Estimated in mbo's Strike Price in mbo's of: Production Q1 - 2005 870.5 $41.87 1,746 50% Q2 - 2005 1,137.0 $43.98 1,750 65% Q3 - 2005 614.0 $48.46 1,750 35% Q4 - 2005 521.5 $48.467 1,754 30% Total 2005 (A) 3,143.0 $45.01 7,000 45% Total 2006 (A) 1,200.0 $54.77 7,300 16% Total 2007 365.0 $50.79 7,300 5% (A) Certain hedging arrangements include swaps with knockout prices ranging from $26.00 to $42.00 covering 2,317 mbo in 2005 and $40.00 to $42.00 covering 501.5 mbo in 2006. SCHEDULE "B" CHESAPEAKE'S PREVIOUS OUTLOOK AS OF APRIL 12, 2005 (PROVIDED FOR REFERENCE ONLY) NOW SUPERSEDED BY OUTLOOK AS OF MAY 2, 2005

Quarter Ending June 30, 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 April 12, 2005, we are using the following key assumptions in our projections for the second quarter of 2005, the full-year 2005 and the full-year 2006.

The primary changes from our February 22, 2005 Outlook are in the table and are explained as follows:

1) We have shown the operational and financial effects of the acquisitions and anticipated financing of them as described in our press release dated April 12, 2005. 2) We have shown our projections for the quarter ending June 30, 2005 for the first time. 3) We have updated the projected effects from changes in our hedging positions since our February 22, 2005 Outlook. 4) We have updated certain of our cost and oil and natural gas price differentials to reflect changing market conditions. 5) We have included our expectations for future NYMEX oil and gas prices to illustrate hedging effects only. Quarter Ending Year Ending Year Ending June 30, December 31, December 31, 2005 2005 2006 Estimated Production: Oil - Mbo 1,770 7,000 7,300 Gas - Bcf 98-100 403 - 411 457 - 467 Gas Equivalent - Bcfe 108.5 - 110.5 445 - 453 501 - 511 Daily gas equivalent midpoint-in Mmcfe 1,203 1,230 1,386 NYMEX Prices (for calculation of realized hedging effects only): Oil - $/Bo $45.00 $46.21 $45.00 Gas - $/Mcf $6.78 $6.51 $6.50 Estimated Differentials to NYMEX Prices: Oil - $/Bo -$4.00 -$4.00 -$4.00 Gas - $/Mcf -$0.80 -$0.80 -$0.80 Estimated Realized Hedging Effects (based on expected NYMEX prices above): Oil - $/Bo -$0.78 -$0.87 $1.12 Gas - $/Mcf -$0.26 $0.13 $0.10 Operating Costs per Mcfe of Projected Production: Production expense $0.68 - 0.72 $0.68 - 0.72 $0.72 - 0.77 Production taxes (generally 7% of O&G revenues) (A) $0.40 - 0.45 $0.40 - 0.45 $0.40 - 0.45 General and administrative $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 $0.04 - 0.06 DD&A - oil and gas $1.75 - 1.85 $1.75 - 1.85 $1.85 - 1.95 Depreciation of other assets $0.09 - 0.11 $0.09 - 0.11 $0.10 - 0.12 Interest expense (B) $0.43 - 0.47 $0.43 - 0.47 $0.43 - 0.47 Other Income and Expense per Mcfe: Marketing and other income $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% Equivalent Shares Outstanding: Basic 312 mm 315 mm 318 mm Diluted 367 mm 364 mm 370 mm Capital Expenditures: Drilling, leasehold and seismic $400 - $1,600 - $1,800 - $450 mm $1,800 mm $2,000 mm (A) Severance tax per mcfe is based on NYMEX prices of $45.00 per barrel of oil and natural gas prices ranging from $6.00-$7.20 during Q2 2005, $6.50-$7.50 during calendar 2005, and $6.35-$7.25 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 Avg. Avg. Open Swap NYMEX Gain NYMEX Price Positions Strike (Loss) Including as a % of Open Price from Open & Assuming Gas Estimated Swaps Of Open Locked Locked Production Total Gas in Bcf's Swaps Swaps Positions in Bcf's of: Production 2005: 1st Qtr 62.2 $7.00 -$0.18 $6.82 91.5 68% 2nd Qtr 63.1 $6.29 -$0.17 $6.12 99.0 64% 3rd Qtr 57.0 $6.41 -$0.19 $6.22 105.5 54% 4th Qtr 38.1 $6.64 -$0.28 $6.36 111.0 34% Total 2005 (A) 220.4 $6.58 -$0.19 $6.39 407.0 54% Total 2006 (A) 79.4 $7.10 -$0.31 $6.79 462.0 17% TOTALS 2005-2006 299.8 $6.72 -$0.22 $6.50 869.0 34% (A) Certain hedging arrangements include swaps with knockout prices ranging from $3.75 to $5.50 covering 79.5 bcf in 2005 and $3.75 to $5.50 covering 35.7 bcf in 2006.

Note: Not shown above are collars covering 4.4 bcf of production in 2005 at a weighted average floor and ceiling of $3.10 and $4.44 and call options covering 7.3 bcf of production in 2005 at a weighted average price of $6.00.

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 2005 188.6 $0.26 407.0 46% 2006 130.1 0.32 462.0 28% 2007 126.5 0.28 490.0 26% 2008 118.6 0.27 515.0 23% 2009 86.6 0.29 540.0 16% Totals 650.4 $0.28 2,414.0 27% * weighted average The company has entered into the following crude oil hedging arrangements: % Hedged Open Swap Positions Assuming Oil as % of Total Open Swaps Avg. NYMEX Production Estimated in mbo's Strike Price in mbo's of: Production Q1 - 2005 870.5 $41.87 1,650 53% Q2 - 2005 1,107.0 $43.76 1,770 63% Q3 - 2005 522.0 $47.59 1,790 29% Q4 - 2005 429.5 $47.32 1,790 24% Total 2005 (A) 2,929.0 $44.40 7,000 42% Total 2006 (A) 835.0 $55.68 7,300 11% (A) Certain hedging arrangements include swaps with knockout prices ranging from $26.00 to $42.00 covering 2,317 mbo in 2005 and $40.00 to $42.00 covering 501.5 mbo in 2006.