Chesapeake Energy Corporation Reports Financial and Operational Results for the 2007 Fourth Quarter and Full Year
Company Reports 2007 Fourth Quarter Net Income Available to Common Shareholders of $158 Million, or $0.33 per Fully Diluted Common Share, on Revenue of $2.1 Billion; Adjusted Net Income Available to Common Shareholders Reaches $466 Million, or $0.93 per Fully Diluted Common Share Full Year 2007 Net Income Available to Common Shareholders Reaches $1.2 Billion, or $2.62 per Fully Diluted Common Share, on Revenue of $7.8 Billion; Adjusted Net Income Available to Common Shareholders Reaches $1.6 Billion, or $3.21 per Fully Diluted Common Share Fourth Quarter 2007 Production of 2.2 Bcfe per Day Increases 10% Sequentially and 34% Year-Over-Year; Full Year Production of 2.0 Bcfe per Day Increases 23% Year-Over-Year Proved Reserves Reach Record Level of 10.9 Tcfe and Increase 21% Year-Over-Year; Company Delivers Full Year Reserve Replacement Rate of 369% from 1.9 Tcfe of Additions at a Drilling and Acquisition Cost of $2.08 per Mcfe

OKLAHOMA CITY--(BUSINESS WIRE)--Feb. 21, 2008--Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operating results for the 2007 fourth quarter and full year. For the 2007 fourth quarter, Chesapeake generated net income available to common shareholders of $158 million ($0.33 per fully diluted common share), operating cash flow of $1.3 billion (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $1.2 billion (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $2.1 billion and production of 204 billion cubic feet of natural gas equivalent (bcfe).

For the 2007 full year, Chesapeake generated net income available to common shareholders of $1.2 billion ($2.62 per fully diluted common share), operating cash flow of $4.6 billion and ebitda of $4.7 billion on revenue of $7.8 billion and production of 714 bcfe.

The company's 2007 fourth quarter and full year net income available to common shareholders and ebitda include various items that are typically not included in published estimates of the company's financial results by certain securities analysts. Excluding the items detailed below, Chesapeake generated adjusted net income to common shareholders in the 2007 fourth quarter of $466 million ($0.93 per fully diluted common share) and adjusted ebitda of $1.4 billion. For the 2007 full year, Chesapeake generated adjusted net income to common shareholders of $1.6 billion ($3.21 per fully diluted common share) and adjusted ebitda of $5.0 billion.

The excluded items and their effects on 2007 fourth quarter and full year reported results are detailed as follows:

    --  an unrealized after-tax mark-to-market loss of $180 million in
        the fourth quarter and $257 million for the full year
        resulting from the company's oil and natural gas and interest
        rate hedging programs;

    --  an after-tax gain of $51 million in the second quarter
        resulting from the sale of the company's investment in Eagle
        Energy Partners I, L.P.; and

    --  a reduction of net income available to common shareholders of
        $128 million for the fourth quarter and full year resulting
        from exchanges of the company's preferred stock for common
        stock that reduced future preferred stock dividend payment
        requirements.

The excluded items do not affect the calculation of operating cash flow. A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 18-21 of this release.

Key Operational and Financial Statistics Summarized Below for the 2007 Fourth Quarter, 2007 Third Quarter, 2006 Fourth Quarter and for the Full Years 2007 and 2006

The table below summarizes Chesapeake's key results during the 2007 fourth quarter and compares them to the 2007 third quarter and the 2006 fourth quarter and also compares the 2007 full year to the 2006 full year.

                          Three Months Ended:       Full Year Ended:
                      ---------------------------- -------------------
                      12/31/07  9/30/07  12/31/06  12/31/07  12/31/06
                      --------- -------- --------- --------- ---------
Average daily
 production (in
 mmcfe)                  2,219    2,026     1,653     1,957     1,585
Natural gas as % of
 total production           92       91        91        92        91
Natural gas
 production (in bcf)     187.8    170.3     138.8     655.0     526.5
Average realized
 natural gas price
 ($/mcf) (a)              8.11     7.41      9.03      8.14      8.76
Oil production (in
 mbbls)                  2,735    2,680     2,217     9,882     8,654
Average realized oil
 price ($/bbl) (a)       72.58    69.25     59.95     67.50     59.14
Natural gas
 equivalent
 production (in bcfe)    204.2    186.4     152.1     714.3     578.4
Natural gas
 equivalent realized
 price ($/mcfe) (a)       8.43     7.76      9.11      8.40      8.86
Oil and natural gas
 marketing income
 ($/mcfe)                  .09      .10       .11       .10       .09
Service operations
 income ($/mcfe)           .04      .06       .09       .06       .11
Production expenses
 ($/mcfe)                 (.88)    (.89)     (.82)     (.90)     (.85)
Production taxes
 ($/mcfe)                 (.32)    (.30)     (.31)     (.30)     (.31)
General and
 administrative costs
 ($/mcfe) (b)             (.29)    (.23)     (.22)     (.26)     (.19)
Stock-based
 compensation
 ($/mcfe)                 (.08)    (.10)     (.04)     (.08)     (.05)
DD&A of oil and
 natural gas
 properties ($/mcfe)     (2.55)   (2.57)    (2.51)    (2.57)    (2.35)
D&A of other assets
 ($/mcfe)                 (.16)    (.24)     (.20)     (.22)     (.18)
Interest expense
 ($/mcfe) (a)             (.49)    (.52)     (.54)     (.51)     (.52)
Operating cash flow
 ($ in millions) (c)     1,322    1,085     1,095     4,607     4,045
Operating cash flow
 ($/mcfe)                 6.48     5.82      7.20      6.45      6.99
Adjusted ebitda ($ in
 millions) (d)           1,432    1,195     1,210     5,028     4,449
Adjusted ebitda
 ($/mcfe)                 7.01     6.41      7.96      7.04      7.69
Net income to common
 shareholders ($ in
 millions)                 158      346       446     1,229     1,904
Earnings per share -
 assuming dilution
 ($)                       .33      .72       .96      2.62      4.35
Adjusted net income
 to common
 shareholders
($ in millions) (e)        466      330       418     1,563     1,575
Adjusted earnings per
 share - assuming
 dilution ($)              .93      .69       .90      3.21      3.61

(a) includes the effects of realized gains or (losses) from hedging, but does not include the effects of unrealized gains or (losses) from hedging

(b) excludes expenses associated with non-cash stock-based compensation

(c) defined as cash flow provided by operating activities before changes in assets and liabilities

(d) defined as net income before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on pages 20-21

(e) defined as net income available to common shareholders, as adjusted to remove the effects of certain items detailed on pages 20-21

Average Realized Prices, Hedging Results and Hedging Positions Detailed

Average prices realized during the 2007 fourth quarter (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $8.11 per thousand cubic feet of natural gas (mcf) and $72.58 per barrel of oil and natural gas liquids (bbl), for a realized natural gas equivalent price of $8.43 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains and losses from oil and natural gas hedging activities during the 2007 fourth quarter generated a $1.73 gain per mcf and a $13.66 loss per bbl for a 2007 fourth quarter realized hedging gain of $287 million, or $1.40 per mcfe. Excluding hedging activity, Chesapeake's average realized pricing differentials to NYMEX during the 2007 fourth quarter were a negative $0.59 per mcf and a negative $4.44 per bbl.

By comparison, average prices realized during the 2006 fourth quarter (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $9.03 per mcf and $59.95 per bbl, for a realized natural gas equivalent price of $9.11 per mcfe. Realized gains from oil and natural gas hedging activities during the 2006 fourth quarter generated a $3.14 gain per mcf and a $4.88 gain per bbl for a 2006 fourth quarter realized hedging gain of $447 million, or $2.94 per mcfe. Excluding hedging activity, Chesapeake's average realized pricing differentials to NYMEX during the 2006 fourth quarter were a negative $0.67 per mcf and a negative $5.14 per bbl.

For the 2007 full year, average prices realized (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $8.14 per mcf and $67.50 per bbl, for a realized natural gas equivalent price of $8.40 per mcfe. Realized gains and losses from oil and natural gas hedging activities during the 2007 full year generated a $1.85 gain per mcf and a $1.14 loss per bbl for a 2007 full year realized hedging gain of $1.2 billion, or $1.68 per mcfe. Excluding hedging activity, Chesapeake's average realized pricing differentials to NYMEX during the 2007 full year were a negative $0.57 per mcf and a negative $3.67 per bbl. During 2006 and 2007, Chesapeake's oil and natural gas hedging activities generated a total realized gain of $2.5 billion.

By comparison, for the 2006 full year, average prices realized (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $8.76 per mcf and $59.14 per bbl, for a realized natural gas equivalent price of $8.86 per mcfe. Realized gains and losses from oil and natural gas hedging activities during the 2006 full year generated a $2.41 gain per mcf and a $1.72 loss per bbl for a 2006 full year realized hedging gain of $1.3 billion, or $2.17 per mcfe. Excluding hedging activity, Chesapeake's average realized pricing differentials to NYMEX during the 2006 full year were a negative $0.89 per mcf and a negative $5.36 per bbl.

The following tables compare Chesapeake's open hedge position through swaps and collars as well as gains from lifted hedges as of February 21, 2008 to those previously announced as of November 6, 2007. Depending on changes in oil and natural gas futures markets and management's view of underlying oil and natural gas supply and demand trends, Chesapeake may either increase or decrease its hedging positions at any time in the future without notice.

             Open Swap Positions as of February 21, 2008

                                    Natural Gas             Oil
                                -------------------- -----------------
Quarter or Year                 % Hedged    $ NYMEX  % Hedged $ NYMEX
=============================== ========== ========= ======== ========
2008 Q1                               76%       8.64     68%     73.97
2008 Q2                               73%       8.44     72%     75.22
2008 Q3                               69%       8.60     72%     75.11
2008 Q4                               61%       9.13     65%     76.79
=============================== ========== ========= ======== ========
2008 Total                            70%       8.69     69%     75.24
=============================== ========== ========= ======== ========
2009 Total                            33%       8.94     73%     81.60
=============================== ========== ========= ======== ========
      Open Natural Gas Collar Positions as of February 21, 2008

                                               Average      Average
                                                Floor       Ceiling
Quarter or Year                  % Hedged      $ NYMEX      $ NYMEX
================================ ========== ============= ============
2008 Q1                                 10%          7.36         9.28
2008 Q2                                  1%          7.50         9.68
2008 Q3                                  1%          7.50         9.68
2008 Q4                                  1%          7.50         9.68
================================ ========== ============= ============
2008 Total                               3%          7.41         9.40
================================ ========== ============= ============
2009 Total                               5%          8.14        10.82
================================ ========== ============= ============
     Gains from Lifted Natural Gas Hedges as of February 21, 2008

                                   Assuming Natural Gas
                     Total Gain        Production of:         Gain
Quarter or Year     ($ millions)           (bcf)          ($ per mcf)
=================== ============= ======================= ============
2008 Q1                       156                     184         0.85
2008 Q2                        45                     194         0.23
2008 Q3                        41                     205         0.20
2008 Q4                        45                     210         0.22
=================== ============= ======================= ============
2008 Total                    287                     793         0.36
=================== ============= ======================= ============
2009 Total                     13                     897         0.01
=================== ============= ======================= ============
              Open Swap Positions as of November 6, 2007

                                   Natural Gas             Oil
                              --------------------- ------------------
Quarter or Year               % Hedged    $ NYMEX   % Hedged  $ NYMEX
============================= ========== ========== ======== =========
2008 Q1                              74%       8.78      80%     72.84
2008 Q2                              69%       8.49      78%     72.59
2008 Q3                              67%       8.64      75%     72.44
2008 Q4                              61%       9.16      66%     73.48
============================= ========== ========== ======== =========
2008 Total                           68%       8.76      75%     72.82
============================= ========== ========== ======== =========
2009 Total                           28%       8.87      73%     78.81
============================= ========== ========== ======== =========
Open Natural Gas Collar Positions as of November 6, 2007

                                             Average       Average
                                              Floor        Ceiling
Quarter or Year                % Hedged      $ NYMEX       $ NYMEX
============================== =========== ============ ==============
2008 Q1                                10%         7.36           9.28
2008 Q2                                 1%         7.50           9.68
2008 Q3                                 1%         7.50           9.68
2008 Q4                                 1%         7.50           9.68
============================== =========== ============ ==============
2008 Total                              3%         7.41           9.40
============================== =========== ============ ==============
2009 Total                              3%         7.97          11.18
============================== =========== ============ ==============
     Gains from Lifted Natural Gas Hedges as of November 6, 2007

                                    Assuming Natural Gas
                        Total Gain      Production of:        Gain
Quarter or Year        ($ millions)         (bcf)         ($ per mcf)
====================== ============ ===================== ============
2008 Q1                         133                   188         0.71
2008 Q2                          39                   194         0.20
2008 Q3                          36                   202         0.18
2008 Q4                          37                   209         0.18
====================== ============ ===================== ============
2008 Total                      245                   793         0.31
====================== ============ ===================== ============
2009 Total                       13                   897         0.01
====================== ============ ===================== ============

Certain open natural gas swap positions include knockout swaps with knockout provisions at prices ranging from $5.45 to $6.50 covering 191 billion cubic feet of natural gas (bcf) in 2008 and $5.45 to $6.50 covering 214 bcf in 2009. Certain open natural gas collar positions include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 11 bcf in 2008 and $5.50 to $6.00 covering 46 bcf in 2009. Also, certain open oil swap positions include cap-swaps and knockout swaps with provisions limiting the counterparty's exposure below prices ranging from $45.00 to $65.00 covering four million barrels of oil and natural gas liquids (mmbbls) in 2008 and from $52.50 to $60.00 covering seven mmbbls in 2009.

The company's updated forecasts for 2008 through 2009 are attached to this release in an Outlook dated February 21, 2008 labeled as Schedule "A", which begins on page 23. This Outlook has been changed from the Outlook dated November 6, 2007 (attached as Schedule "B", which begins on page 27) to reflect various updated information.

Company Provides Update on 2008-2009 Financial Plan

In September 2007, Chesapeake announced an enhanced financial plan designed to monetize latent balance sheet value and to fully fund its planned capital expenditures through at least 2009 without accessing public capital markets. Since then, the company has successfully implemented multiple aspects of the plan and anticipates further progress during 2008 and 2009. Chesapeake believes its planned future transactions in the asset and financial markets will allow it to monetize additional assets for approximately $3 billion by the end of 2009 that, in management's opinion, have not been adequately reflected in the company's market valuation historically.

Producing Property Monetizations and Asset Sales - On December 31, 2007, the company monetized certain Chesapeake-operated long-lived producing assets in Kentucky and West Virginia and retained drilling rights on the properties below currently producing intervals and outside of existing producing wellbores. Chesapeake received $1.1 billion for the sale of a volumetric production payment on the Appalachian assets covering proved reserves of approximately 208 bcfe and current production of approximately 55 million cubic feet of natural gas equivalent (mmcfe) per day. For accounting purposes, the transaction was treated as a sale and the company's proved reserves were reduced accordingly. The company also plans to pursue additional monetizations of similarly mature properties in 2008 and 2009 and anticipates further proceeds of approximately $2.0 billion.

In the 2008 first quarter, the company sold non-core oil and natural gas assets in the Rocky Mountains and in the southeastern Oklahoma Woodford Shale play for proceeds of approximately $250 million. The sales involved approximately six mmcfe of daily production and 32 bcfe of proved reserves.

Midstream Partnership - Chesapeake is currently in the process of forming a private partnership to own a non-operating interest in its midstream natural gas assets outside of Appalachia, which consist primarily of gas gathering systems and processing assets. These assets currently generate annualized cash flow from operating activities in excess of $150 million and are expected to grow substantially over at least the next three years as the company expands its gathering systems in multiple operating areas, particularly in the Fort Worth Barnett and Arkansas Fayetteville Shale plays. The company anticipates raising $1 billion in the first half of 2008 by selling a minority interest in the partnership.

Oil and Natural Gas Production Sets Record for 26th Consecutive Quarter and 18th Consecutive Year; 2007 Fourth Quarter Average Daily Production Increases 34% over the 2006 Fourth Quarter and Full Year 2007 Production Increases 23% over Full Year 2006

Daily production for the 2007 fourth quarter averaged 2.219 bcfe, an increase of 193 mmcfe, or 10%, over the 2.026 bcfe produced per day in the 2007 third quarter and an increase of 566 mmcfe, or 34%, over the 1.653 bcfe of daily production in the 2006 fourth quarter.

Chesapeake's 2007 fourth quarter production of 204.2 bcfe was comprised of 187.8 bcf (92% on a natural gas equivalent basis) and 2.74 mmbbls (8% on a natural gas equivalent basis). Chesapeake's average daily production for the quarter of 2.219 bcfe consisted of 2.041 bcf and 29,728 bbls.

The company's sequential and year-over-year growth rates for its 2007 fourth quarter natural gas production were 10% and 35%, respectively, while the company's sequential and year-over-year growth rates for its oil production were 2% and 23%, respectively. The 2007 fourth quarter was Chesapeake's 26th consecutive quarter of sequential U.S. production growth. Over these 26 quarters, Chesapeake's U.S. production has increased 467%, for an average compound quarterly growth rate of 7% and an average compound annual growth rate of 30%. Chesapeake's daily production for the 2007 full year averaged 1.957 bcfe, an increase of 372 mmcfe, or 23%, over the 1.585 bcfe of daily production for the 2006 full year.

Chesapeake's 2007 full year production of 714.3 bcfe was comprised of 655.0 bcf (92% on a natural gas equivalent basis) and 9.882 mmbbls (8% on a natural gas equivalent basis). Chesapeake's average daily production for the 2007 full year of 1.957 bcfe consisted of 1.794 bcf and 27,074 bbls. The company's growth rate for its 2007 full year natural gas production was 24% and its growth rate for 2007 full year oil production was 14%. The 2007 full year was Chesapeake's 18th consecutive year of sequential production growth.

Oil and Natural Gas Proved Reserves Reach Record Level of 10.9 Tcfe; 2007 Full Year Drilling and Acquisition Costs Average $2.08 per Mcfe; Company Adds 1.9 Tcfe for a Reserve Replacement Rate of 369%

Chesapeake began 2007 with estimated proved reserves of 8.956 trillion cubic feet of natural gas equivalent (tcfe) and ended the year with 10.879 tcfe, an increase of 1.923 tcfe, or 21%. During the year, Chesapeake replaced its 714 bcfe of production with an estimated 2.637 tcfe of new proved reserves for a reserve replacement rate of 369%. Reserve replacement through the drillbit was 2.468 tcfe, or 346% of production and 94% of the total increase (including 1.248 tcfe of positive performance revisions, of which 1.207 tcfe relate to infill drilling and increased density locations, and 97 bcfe of positive revisions resulting from oil and natural gas price increases between December 31, 2006 and December 31, 2007). Reserve replacement through the acquisition of proved reserves completed during the year was 377 bcfe, or 53% of production and 14% of the total increase. Divestments of proved reserves during the year totaled 208 bcfe for proceeds of $1.1 billion at a sales price of $5.49 per mcfe.

Chesapeake's total drilling and acquisition costs for the year were $2.08 per mcfe (excluding costs of $343 million for seismic, $1.1 billion for acquisition of unproved properties, $1.1 billion to acquire new leasehold, $254 million for capitalized interest on leasehold and unproved property and $159 million relating to tax basis step-up and asset retirement obligations, as well as positive revisions of proved reserves from higher oil and natural gas prices). Excluding these same items, Chesapeake's exploration and development costs through the drillbit were $2.13 per mcfe during the year while reserve replacement costs through acquisitions of proved reserves were $1.78 per mcfe. A complete reconciliation of finding and acquisition costs and a roll-forward of proved reserves are presented on page 16 of this release.

During 2007, Chesapeake continued the industry's most active drilling program and drilled 1,992 gross (1,695 net) operated wells and participated in another 1,679 gross (224 net) wells operated by other companies. The company's drilling success rate was 99% for company-operated wells and 97% for non-operated wells. Also during the year, Chesapeake invested $4.3 billion in operated wells (using an average of 140 operated rigs) and $0.7 billion in non-operated wells (using an average of 105 non-operated rigs).

As of December 31, 2007, Chesapeake's estimated future net cash flows from proved reserves, discounted at an annual rate of 10% before income taxes (PV-10), and after income taxes (standardized measure) were $20.6 billion and $15.0 billion, respectively, using field differential adjusted prices of $6.19 mcf (based on a NYMEX year-end price of $6.80 per mcf) and $90.58 per bbl (based on a NYMEX year-end price of $96.00 per bbl). Chesapeake's current PV-10 changes by approximately $390 million for every $0.10 per mcf change in natural gas prices and approximately $56 million for every $1.00 per bbl change in oil prices.

By comparison, the December 31, 2006 PV-10 and standardized measure of the company's proved reserves were $13.6 billion and $10.0 billion, respectively, using field differential adjusted prices of $5.41 per mcf (based on a NYMEX year-end price of $5.64 per mcf) and $56.25 per bbl (based on a NYMEX year-end price of $61.15 per bbl). A reconciliation of PV-10 and standardized measure is presented on page 22 of this release.

In addition to the PV-10 value of its proved reserves, the net book value of the company's other assets (including gathering systems, compressors, land and buildings, investments, long-term derivative instruments and other non-current assets) was $3.2 billion as of December 31, 2007 and $2.8 billion as of December 31, 2006.

Chesapeake's Leasehold and 3-D Seismic Inventories Increase to 13 Million Net Acres and 19 Million Acres; Risked Unproved Reserves in the Company's Inventory Reach 33 Tcfe While Unrisked Unproved Reserves Reach 100 Tcfe

Since 2000, Chesapeake has invested $9.4 billion in new leasehold and 3-D seismic acquisitions and now owns the largest combined inventories of onshore leasehold (13.2 million net acres) and 3-D seismic (19.2 million acres) in the U.S. On this leasehold, Chesapeake has an estimated 3.9 tcfe of proved undeveloped reserves and approximately 33 tcfe of risked unproved reserves (100 tcfe of unrisked unproved reserves). The company is currently using 145 operated drilling rigs to further develop its inventory of approximately 36,300 net drillsites, representing more than a 10-year inventory of drilling projects.

Chesapeake characterizes its drilling inventory by one of four play types: conventional gas resource, unconventional gas resource, emerging unconventional gas resource or Appalachian Basin gas resource. In these plays, Chesapeake uses a probability-weighted statistical approach to estimate the potential number of drillsites and unproved reserves associated with such drillsites. The following table summarizes Chesapeake's ownership and activity in each gas resource play type and highlights notable projects in each play.

                                   Est.    Risked     Est.    Est.
                                                               Avg.
                         CHK     Drilling    Net    Average  Reserves
                         Net     Density  Undrilled  Well    Per Well
                                                      Cost
Play Area              Acreage   (Acres)    Wells    ($000 )  (bcfe)
--------------------- ---------- -------- --------- -------- --------
Conventional
---------------------
Southern Oklahoma        345,000      120       600 $ 3,500      2.20
South Texas              145,000       80       400 $ 3,300      2.00
Mountain Front           140,000      320       100 $ 9,000      5.00
Other Conventional     2,970,000  Various     3,900  Various  Various
--------------------- ---------- -------- --------- -------- --------
Conventional Sub-
 total                 3,600,000              5,000

Unconventional
---------------------
Fort Worth Barnett
 Shale                   260,000       50     3,550 $ 2,600      2.50
Fayetteville Shale
 (Core)                  585,000       80     5,725 $ 3,000      2.00
Sahara                   850,000       70     9,000 $   880      0.55
Deep Haley               550,000      320       325 $12,000      6.00
Ark-La-Tex               220,000       55       950 $ 1,700      0.90
Granite, Atoka and
 Colony Washes           200,000       80     1,225 $ 4,000      2.30
Other Unconventional     935,000  Various       625  Various  Various
--------------------- ---------- -------- --------- -------- --------
Unconventional Sub-
 total                 3,600,000             21,400

Emerging
 Unconventional
---------------------
Delaware Basin Shales    815,000      160       500 $ 6,500      3.00
Deep Bossier             390,000      320       125 $10,000      5.00
Ardmore Basin
 Woodford Shale          170,000      160       200 $ 3,400      1.70
Alabama Shales           315,000       ND       100       ND       ND
Other Emerging
 Unconventional          310,000  Various       125  Various  Various
--------------------- ---------- -------- --------- -------- --------
Emerging
 Unconventional Sub-
 total                 2,000,000              1,050

Appalachia
---------------------
Marcellus Shale        1,030,000      160     1,400 $ 1,600      1.25
Lower Huron and Other  2,970,000  Various     7,450  Various  Various
--------------------- ---------- -------- --------- -------- --------
Appalachia Sub-total   4,000,000              8,850

--------------------- ---------- -------- --------- -------- --------
Total                 13,200,000             36,300
--------------------- ---------- -------- --------- -------- --------


                         Total    Risked  Unrisked  Current   Current
                         Proved  Unproved Unproved   Daily    Operated
                        Reserves Reserves Reserves Production   Rig
Play Area                (bcfe)   (bcfe)   (bcfe)   (mmcfe)    Count
----------------------- -------- -------- -------- ---------- --------
Conventional
-----------------------
Southern Oklahoma            849      800    3,200        200        7
South Texas                  428      500    1,900        130        5
Mountain Front               217      300    1,100         95        2
Other Conventional         2,449    3,000   16,500        560       16
----------------------- -------- -------- -------- ---------- --------
Conventional Sub-total     3,943    4,600   22,700        985       30

Unconventional
-----------------------
Fort Worth Barnett
 Shale                     2,062    5,900    7,300        410       39
Fayetteville Shale
 (Core)                      335    9,300   21,500        100       11
Sahara                     1,050    3,500    4,000        180       12
Deep Haley                   291    1,300    7,300        100        9
Ark-La-Tex                   615      400    1,900        120        6
Granite, Atoka and
 Colony Washes               881    1,800    2,500        160       11
Other Unconventional         196      600      700         30        8
----------------------- -------- -------- -------- ---------- --------
Unconventional Sub-
 total                     5,430   22,800   45,200      1,100       96

Emerging Unconventional
-----------------------
Delaware Basin Shales         15    1,200   11,700         ND        4
Deep Bossier                  22      400    4,500         ND        3
Ardmore Basin Woodford
 Shale                        32      300    1,300         ND        2
Alabama Shales                 0      100    2,000         ND        1
Other Emerging
 Unconventional                3      300    2,500         ND        1
----------------------- -------- -------- -------- ---------- --------
Emerging Unconventional
 Sub-total                    72    2,300   22,000         25       11

Appalachia
-----------------------
Marcellus Shale               ND    1,400    5,700         ND        2
Lower Huron and Other         ND    2,100    3,900         ND        6
----------------------- -------- -------- -------- ---------- --------
Appalachia Sub-total       1,402    3,500    9,600         85        8

----------------------- -------- -------- -------- ---------- --------
Total                     10,847   33,200   99,500      2,195      145
----------------------- -------- -------- -------- ---------- --------

Note: Data above is pro forma for divestitures of approximately 32 bcfe of proved reserves and 37,000 net acres of leasehold post year-end 2007. The table also reflects the effects of the company's VPP transaction that reduced Appalachian production and proved reserves by 55 mmcfe per day and 208 bcfe as of December 31, 2007.

    ND = Not disclosed

    Management Comments

Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We are pleased to report outstanding financial and operational results for the 2007 fourth quarter and full year. We are particularly proud of our success through the drillbit that enabled the company to deliver reserve and production growth well above our expectations at very attractive finding costs. In addition, our unrivalled inventory of leasehold, 3-D seismic and undrilled locations combined with our talented, motivated, hard-working and growing employee workforce should provide many more years of increases in reserves, production and net asset value per share. Finally, we are also pleased with our progress in implementing the various elements of our enhanced financial plan that should enable Chesapeake to deliver superior growth and financial returns without accessing the public capital markets for the foreseeable future."

Conference Call Information

A conference call to discuss this release has been scheduled for Friday morning, February 22, 2008, at 9:00 a.m. EST. The telephone number to access the conference call is 913-312-0822 or toll-free 888-230-5503. The passcode for the call is 4323736. We encourage those who would like to participate in the call to dial the access number between 8:50 and 8:55 a.m. EST. For those unable to participate in the conference call, a replay will be available for audio playback from noon EST on February 22, 2008, and will run through midnight EST on Friday, March 7, 2008. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 4323736. The conference call will also be webcast live on the Internet and can be accessed by going to Chesapeake's website at www.chk.com and selecting the "News & Events" section. The webcast of the conference call will be available on our website for one year.

This press release and the accompanying Outlooks include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of oil and natural gas reserves, expected oil and natural gas production and future expenses, projections of future oil and natural gas prices, planned capital expenditures for drilling, leasehold acquisitions and seismic data, and statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures concerning the fair value of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.

Factors that could cause actual results to differ materially from expected results are described in "Risks Related to our Business" under "Risk Factors" in the Offer to Exchange attached as an exhibit to each of the two Schedules TO we filed with the Securities and Exchange Commission on October 23, 2007. These risk factors include the volatility of oil and natural gas prices; the limitations our level of indebtedness may have on our financial flexibility; our ability to compete effectively against strong independent oil and natural gas companies and majors; the availability of capital on an economic basis, including planned asset monetization transactions, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and the amount and timing of development expenditures; uncertainties in evaluating oil and natural gas reserves of acquired properties and associated potential liabilities; our ability to effectively consolidate and integrate acquired properties and operations; unsuccessful exploration and development drilling; declines in the values of our oil and natural gas properties resulting in ceiling test write-downs; lower prices realized on oil and natural gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; the negative impact lower oil and natural gas prices could have on our ability to borrow; drilling and operating risks, including potential environmental liabilities; production interruptions that could adversely affect our cash flow; and pending or future litigation.

Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.

The SEC has generally permitted oil and natural gas companies, in filings made with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the term "unproved" to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third-party engineers or appraisers.

Chesapeake Energy Corporation is the largest independent and third-largest overall producer of natural gas in the U.S. Headquartered in Oklahoma City, the company's operations are focused on exploratory and developmental drilling and corporate and property acquisitions in the Mid-Continent, Fort Worth Barnett Shale, Fayetteville Shale, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast, Ark-La-Tex and Appalachian Basin regions of the United States. The company's Internet address is www.chk.com.

                    CHESAPEAKE ENERGY CORPORATION
                CONSOLIDATED STATEMENTS OF OPERATIONS
           ($ in millions, except per share and unit data)
                             (unaudited)

                                          December 31,   December 31,

THREE MONTHS ENDED:                          2007           2006
---------------------------------------- -------------- --------------
                                            $    $/mcfe    $    $/mcfe
                                         ------- ------ ------- ------

REVENUES:
  Oil and natural gas sales               1,460   7.15   1,429   9.39
  Oil and natural gas marketing sales       594   2.91     406   2.67
  Service operations revenue                 35   0.17      33   0.22
                                         ------- ------ ------- ------
     Total Revenues                       2,089  10.23   1,868  12.28
                                         ------- ------ ------- ------

OPERATING COSTS:
  Production expenses                       180   0.88     125   0.82
  Production taxes                           64   0.32      47   0.31
  General and administrative expenses        75   0.37      40   0.26
  Oil and natural gas marketing expenses    575   2.81     390   2.57
  Service operations expense                 27   0.13      19   0.12
  Oil and natural gas depreciation,
   depletion and amortization               521   2.55     382   2.51
  Depreciation and amortization of other
   assets                                    33   0.16      30   0.20
                                         ------- ------ ------- ------
     Total Operating Costs                1,475   7.22   1,033   6.79
                                         ------- ------ ------- ------

INCOME FROM OPERATIONS                      614   3.01     835   5.49
                                         ------- ------ ------- ------

OTHER INCOME (EXPENSE):
  Interest and other income                   3   0.01       6   0.04
  Interest expense                         (128) (0.63)    (81) (0.53)
                                         ------- ------ ------- ------
     Total Other Income (Expense)          (125) (0.62)    (75) (0.49)
                                         ------- ------ ------- ------

INCOME BEFORE INCOME TAXES                  489   2.39     760   5.00

  Income Tax Expense:
  Current                                     9   0.04       5   0.03
  Deferred                                  177   0.87     284   1.87
                                         ------- ------ ------- ------
     Total Income Tax Expense               186   0.91     289   1.90
                                         ------- ------ ------- ------

NET INCOME                                  303   1.48     471   3.10
                                         ------- ------ ------- ------

  Preferred stock dividends                 (17) (0.08)    (25) (0.17)
  Loss on exchange/conversion of
   preferred stock                         (128) (0.63)     --     --
                                         ------- ------ ------- ------

NET INCOME AVAILABLE TO COMMON
 SHAREHOLDERS                               158   0.77     446   2.93
                                         ======= ====== ======= ======

EARNINGS PER COMMON SHARE:

  Basic                                  $ 0.34         $ 1.05
                                         =======        =======
  Assuming dilution                      $ 0.33         $ 0.96
                                         =======        =======

WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in
 millions)

  Basic                                     468            426
                                         =======        =======
  Assuming dilution                         476            491
                                         =======        =======
                    CHESAPEAKE ENERGY CORPORATION
                CONSOLIDATED STATEMENTS OF OPERATIONS
           ($ in millions, except per share and unit data)
                             (unaudited)

                                          December 31,   December 31,

TWELVE MONTHS ENDED:                         2007           2006
---------------------------------------- -------------- --------------
                                            $    $/mcfe    $    $/mcfe
                                         ------- ------ ------- ------

REVENUES:
   Oil and natural gas sales              5,624   7.88   5,619   9.71
   Oil and natural gas marketing sales    2,040   2.86   1,577   2.73
   Service operations revenue               136   0.19     130   0.23
                                         ------- ------ ------- ------
      Total Revenues                      7,800  10.93   7,326  12.67
                                         ------- ------ ------- ------

OPERATING COSTS:
   Production expenses                      640   0.90     490   0.85
   Production taxes                         216   0.30     176   0.31
   General and administrative expenses      243   0.34     139   0.24
   Oil and natural gas marketing
    expenses                              1,969   2.76   1,522   2.63
   Service operations expense                94   0.13      68   0.12
   Oil and natural gas depreciation,
    depletion and amortization            1,835   2.57   1,359   2.35
   Depreciation and amortization of
    other assets                            154   0.22     104   0.18
   Employee retirement expense               --     --      55   0.09
                                         ------- ------ ------- ------
      Total Operating Costs               5,151   7.22   3,913   6.77
                                         ------- ------ ------- ------

INCOME FROM OPERATIONS                    2,649   3.71   3,413   5.90
                                         ------- ------ ------- ------

OTHER INCOME (EXPENSE):
   Interest and other income                 15   0.02      26   0.05
   Interest expense                        (406) (0.57)   (301) (0.52)
   Gain on sale of investment                83   0.12     117   0.20
                                         ------- ------ ------- ------
      Total Other Income (Expense)         (308) (0.43)   (158) (0.27)
                                         ------- ------ ------- ------

INCOME BEFORE INCOME TAXES                2,341   3.28   3,255   5.63

   Income Tax Expense:
     Current                                 29   0.04       5   0.01
     Deferred                               861   1.21   1,247   2.16
                                         ------- ------ ------- ------
       Total Income Tax Expense             890   1.25   1,252   2.17
                                         ------- ------ ------- ------

NET INCOME                                1,451   2.03   2,003   3.46
                                         ------- ------ ------- ------

   Preferred stock dividends                (94) (0.13)    (89) (0.15)
   Loss on exchange/conversion of
    preferred stock                        (128) (0.18)    (10) (0.02)
                                         ------- ------ ------- ------

NET INCOME AVAILABLE TO COMMON
 SHAREHOLDERS                             1,229   1.72   1,904   3.29
                                         ======= ====== ======= ======

EARNINGS PER COMMON SHARE:

   Basic                                 $ 2.69         $ 4.78
                                         =======        =======
   Assuming dilution                     $ 2.62         $ 4.35
                                         =======        =======

WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in
 millions)

   Basic                                    456            398
                                         =======        =======
   Assuming dilution                        487            459
                                         =======        =======
                    CHESAPEAKE ENERGY CORPORATION
                     CONSOLIDATED BALANCE SHEETS
                            (in millions)
                             (unaudited)

                                           December 31,  December 31,
                                                2007          2006
                                          -------------- -------------

Cash                                       $           1  $          3
Other current assets                               1,395         1,151
                                          -------------- -------------
   Total Current Assets                            1,396         1,154
                                          -------------- -------------

Property and equipment (net)                      28,337        21,904
Other assets                                       1,001         1,359
                                          -------------- -------------
   Total Assets                            $      30,734  $     24,417
                                          ============== =============

Current liabilities                        $       2,760  $      1,890
Long-term debt, net                               10,950         7,376
Asset retirement obligation                          236           193
Other long-term liabilities                          692           390
Deferred tax liability                             3,966         3,317
                                          -------------- -------------
   Total Liabilities                              18,604        13,166

Stockholders' Equity                              12,130        11,251
                                          -------------- -------------

Total Liabilities & Stockholders' Equity   $      30,734  $     24,417
                                          ============== =============

Common Shares Outstanding                            511           457
                                          ============== =============
                    CHESAPEAKE ENERGY CORPORATION
                            CAPITALIZATION
                            (in millions)
                             (unaudited)

                       December  % of Total    December  % of Total
                          31,        Book         31,        Book
                         2007   Capitalization   2006   Capitalization
                       -------- -------------- -------- --------------

Long-term debt, net    $ 10,950             47 $  7,376             40
Stockholders' equity     12,130             53   11,251             60
                       -------- -------------- -------- --------------
   Total               $ 23,080            100 $ 18,627            100
                       ======== ============== ======== ==============
                    CHESAPEAKE ENERGY CORPORATION
  RECONCILIATION OF 2007 ADDITIONS TO OIL AND NATURAL GAS PROPERTIES
                ($ in millions, except per unit data)
                             (unaudited)

                                                    Reserves
                                            Cost    (in mmcfe)  $/mcfe
                                          -------- ------------ ------

Exploration and development costs         $ 5,055  2,371,063(a)  2.13
Acquisition of proved properties              671    377,230     1.78
                                          -------- ------------
    Subtotal                                5,726  2,748,293     2.08
                                          -------- ------------

Divestitures                               (1,142)  (208,141)   (5.49)
Geological and geophysical costs              343         --
                                          -------- ------------
    Adjusted subtotal                       4,927  2,540,152     1.94
                                          -------- ------------

Revisions - price                              --     97,118

Leasehold acquisition costs                   886         --
Lease brokerage costs and recording fees      224         --
Acquisition of unproved properties and
 other                                      1,101         --
Capitalized interest on leasehold and
 unproved property                            254         --
                                          -------- ------------
    Adjusted subtotal                       7,392  2,637,270     2.80
                                          -------- ------------

Tax basis step-up                             131         --
Asset retirement obligation and other          29         --
                                          -------- ------------
    Total                                 $ 7,552  2,637,270     2.86
                                          ======== ============

(a) Includes 1,248 bcfe of positive performance revisions (1,207 bcfe relating to infill drilling and increased density locations and 41 bcfe of other performance related revisions) and excludes positive revisions of 97 bcfe resulting from oil and natural gas price increases between December 31, 2006 and 2007.

                    CHESAPEAKE ENERGY CORPORATION
                   ROLL-FORWARD OF PROVED RESERVES
                TWELVE MONTHS ENDED DECEMBER 31, 2007
                             (unaudited)

                                                              Mmcfe
                                                           -----------

Beginning balance, 01/01/07                                 8,955,614
Extensions and discoveries                                  1,122,986
Acquisitions                                                  377,230
Divestitures                                                 (208,141)
Revisions - performance                                     1,248,077
Revisions - price                                              97,118
Production                                                   (714,261)
                                                           -----------
Ending balance, 12/31/07                                   10,878,623
                                                           ===========

Reserve replacement                                         2,637,270
Reserve replacement ratio (a)                                     369%

(a) The company uses the reserve replacement ratio as an indicator of the company's ability to replenish annual production volumes and grow its reserves, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

                    CHESAPEAKE ENERGY CORPORATION
  SUPPLEMENTAL DATA - OIL AND NATURAL GAS SALES AND INTEREST EXPENSE
                             (unaudited)

                                        THREE MONTHS   TWELVE MONTHS
                                            ENDED           ENDED
                                        December 31,    December 31,
                                       --------------- ---------------
                                        2007    2006    2007    2006
                                       ------- ------- ------- -------
Oil and Natural Gas Sales ($ in
 millions):
   Oil sales                           $  236  $  122  $  678  $  527
   Oil derivatives - realized gains
    (losses)                              (38)     11     (11)    (15)
   Oil derivatives - unrealized gains
    (losses)                             (180)      4    (235)     28
                                       ------- ------- ------- -------

      Total Oil Sales                      18     137     432     540
                                       ------- ------- ------- -------

   Natural gas sales                    1,199     817   4,117   3,343
   Natural gas derivatives - realized
    gains (losses)                        324     436   1,214   1,269
   Natural gas derivatives - unrealized
    gains (losses)                        (81)     39    (139)    467
                                       ------- ------- ------- -------

      Total Natural Gas Sales           1,442   1,292   5,192   5,079
                                       ------- ------- ------- -------

      Total Oil and Natural Gas Sales  $1,460  $1,429  $5,624  $5,619
                                       ======= ======= ======= =======

Average Sales Price - excluding gains
 (losses) on derivatives:
   Oil ($ per bbl)                     $86.24  $55.07  $68.64  $60.86
   Natural gas ($ per mcf)             $ 6.38  $ 5.89  $ 6.29  $ 6.35
   Natural gas equivalent ($ per mcfe) $ 7.03  $ 6.17  $ 6.71  $ 6.69

Average Sales Price - excluding
 unrealized gains (losses)
on derivatives):
   Oil ($ per bbl)                     $72.58  $59.95  $67.50  $59.14
   Natural gas ($ per mcf)             $ 8.11  $ 9.03  $ 8.14  $ 8.76
   Natural gas equivalent ($ per mcfe) $ 8.43  $ 9.11  $ 8.40  $ 8.86

Interest Expense ($ in millions):
   Interest                            $   99  $   79  $  365  $  301
   Derivatives - realized (gains)
    losses                                  1       3       1       2
   Derivatives - unrealized (gains)
    losses                                 28      (1)     40      (2)
                                       ------- ------- ------- -------
      Total Interest Expense           $  128  $   81  $  406  $  301
                                       ======= ======= ======= =======
                      CHESAPEAKE ENERGY CORPORATION
                    CONDENSED CONSOLIDATED CASH FLOW DATA
                                (in millions)
                                 (unaudited)

                                             December 31, December 31,

THREE MONTHS ENDED:                              2007         2006
-------------------------------------------- ------------ ------------

Beginning cash                               $         2  $         1
Cash provided by operating activities              1,544        1,861
Cash (used in) investing activities               (1,434)      (2,274)
Cash provided by financing activities               (111)         415
Ending cash                                            1            3

============================================ ============ ============
                                             December 31, December 31,

TWELVE MONTHS ENDED:                             2007         2006
-------------------------------------------- ------------ ------------

Beginning cash                               $         3  $        60
Cash provided by operating activities              4,932        4,843
Cash (used in) investing activities               (7,922)      (8,942)
Cash provided by financing activities              2,988        4,042
Ending cash                                            1            3
                    CHESAPEAKE ENERGY CORPORATION
           RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
                            (in millions)
                             (unaudited)

                                           December September December
                                              31,      30,       31,

THREE MONTHS ENDED:                          2007      2007     2006
------------------------------------------ -------- --------- --------

CASH PROVIDED BY OPERATING ACTIVITIES       $1,544    $1,267   $1,861

Adjustments:
   Changes in assets and liabilities          (222)     (182)    (766)
                                           -------- --------- --------

OPERATING CASH FLOW(a)                      $1,322    $1,085   $1,095
                                           ======== ========= ========

(a) Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of an oil and natural gas company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity.

                                         December  September December
                                            31,       30,       31,

THREE MONTHS ENDED:                          2007       2007     2006
---------------------------------------- -------- ---------- --------

NET INCOME                                 $  303     $  372   $  471

Income tax expense                            186        228      289
Interest expense                              128        116       81
Depreciation and amortization of other
 assets                                        33         45       30
Oil and natural gas depreciation,
 depletion and amortization                   521        479      382
                                         -------- ---------- --------

EBITDA(b)                                  $1,171     $1,240   $1,253
                                         ======== ========== ========

(b) Ebitda represents net income before income tax expense, interest expense, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreement and is used in the financial covenants in our bank credit agreement and our senior note indentures. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP. Ebitda is reconciled to cash provided by operating activities as follows:

                                        December  September December
                                           31,        30,       31,

THREE MONTHS ENDED:                       2007       2007      2006
----------------------------------------------------------------------

CASH PROVIDED BY OPERATING ACTIVITIES  $    1,544 $   1,267 $   1,861

Changes in assets and liabilities            (222)     (182)     (766)
Interest expense                              128       116        81
Unrealized gains (losses) on oil and
 natural gas derivatives                     (261)       45        43
Other non-cash items                          (18)       (6)       34
                                       -------------------------------

EBITDA                                 $    1,171 $   1,240 $   1,253
                                       ===============================
                    CHESAPEAKE ENERGY CORPORATION
           RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
                            (in millions)
                             (unaudited)

                                      December  December    December
                                         31,        31,        31,

TWELVE MONTHS ENDED:                    2007       2006        2005
------------------------------------- --------- ---------- -----------

CASH PROVIDED BY OPERATING ACTIVITIES $  4,932  $   4,843  $     2,407

Adjustments:
  Changes in assets and liabilities       (325)      (798)          19
                                      --------- ---------- -----------

OPERATING CASH FLOW(a)                $  4,607  $   4,045  $     2,426
                                      ========= ========== ===========

(a) Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of an oil and natural gas company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity.

                                        December   December   December
                                           31,         31,       31,

TWELVE MONTHS ENDED:                       2007       2006      2005
-------------------------------------- ----------- ---------- --------

NET INCOME                             $     1,451 $    2,003 $    948

Income tax expense                             890      1,252      545
Interest expense                               406        301      220
Depreciation and amortization of other
 assets                                        154        104       51
Oil and natural gas depreciation,
 depletion and amortization                  1,835      1,359      894
                                       ----------- ---------- --------

EBITDA(b)                              $     4,736 $    5,019 $  2,658
                                       =========== ========== ========

(b) Ebitda represents net income before income tax expense, interest expense, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreement and is used in the financial covenants in our bank credit agreement and our senior note indentures. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP. Ebitda is reconciled to cash provided by operating activities as follows:

                                            December December December
                                               31,      31,      31,

TWELVE MONTHS ENDED:                           2007     2006     2005
---------------------------------------------------- -------- --------

CASH PROVIDED BY OPERATING ACTIVITIES        $4,932   $4,843   $2,407

Changes in assets and liabilities              (325)    (798)      19
Interest expense                                406      301      220
Unrealized gains (losses) on oil and natural
 gas derivatives                               (375)     496       41
Other noncash items                              98      177      (29)
                                            -------- -------- --------

EBITDA                                       $4,736   $5,019   $2,658
                                            ======== ======== ========
                    CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
                ($ in millions, except per share data)
                             (unaudited)

                                           December September December
                                              31,      30,       31,
 THREE MONTHS ENDED:                         2007     2007      2006
------------------------------------------ -------- --------- --------

Net income available to common
 shareholders                              $    158 $    346  $   446

Adjustments:
   Loss on conversion/exchange of
    preferred stock                             128       --       --
   Unrealized (gains) losses on
    derivatives, net of tax                     180      (16)     (27)
                                           -------- --------- --------

Adjusted net income available to common
 shareholders(1)                                466      330      419
   Preferred dividends                           17       26       25
                                           -------- --------- --------

Total adjusted net income                  $    483 $    356  $   444
                                           ======== ========= ========

Weighted average fully diluted shares
 outstanding(2)                                 520      517      491

Adjusted earnings per share assuming
 dilution                                  $   0.93 $   0.69  $  0.90
                                           ======== ========= ========

(1) Adjusted net income available to common and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:

a. Management uses adjusted net income available to common to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.

b. Adjusted net income available to common is more comparable to earnings estimates provided by securities analysts.

c. Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

(2) Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

                    CHESAPEAKE ENERGY CORPORATION
                  RECONCILIATION OF ADJUSTED EBITDA
                           ($ in millions)
                             (unaudited)

                                           December September December
                                              31,      30,       31,
 THREE MONTHS ENDED:                         2007     2007      2006
------------------------------------------ -------- --------- --------

 EBITDA                                    $  1,171 $  1,240  $ 1,253

 Adjustments, before tax:
Unrealized (gains) losses on oil and
 natural gas derivatives                        261      (45)     (43)
                                           -------- --------- --------

 Adjusted ebitda(1)                        $  1,432 $  1,195  $ 1,210
                                           ======== ========= ========

(1) Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to ebitda because:

a. Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.

b. Adjusted ebitda is more comparable to estimates provided by securities analysts.

c. Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

                    CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
                ($ in millions, except per share data)
                             (unaudited)

                                            December December December
                                               31,      31,      31,
TWELVE MONTHS ENDED:                          2007     2006      2005
------------------------------------------- -------- -------- --------

Net income available to common shareholders  $1,229   $1,904    $ 880

Adjustments:
   Loss on conversion/exchange of preferred
    stock                                       128       10       26
   Unrealized (gains) losses on
    derivatives, net of tax                     257     (308)     (27)
   Gain on sale of investment, net of tax       (51)     (73)      --
   Employee retirement expense, net of tax       --       34       --
   Cumulative impact of income tax rate
    change                                       --       15       --
   Loss on repurchases or exchanges of
    senior notes, net of tax                     --       --       45
   Reversal of severance tax accrual, net
    of tax                                       --       (7)      --
                                            -------- -------- --------

Adjusted net income available to common
 shareholders(1)                              1,563    1,575      924
   Preferred dividends                           94       89       42
                                            -------- -------- --------

Total adjusted net income                    $1,657   $1,664    $ 966
                                            ======== ======== ========

Weighted average fully diluted shares
 outstanding(2)                                 517      461      375

Adjusted earnings per share assuming
 dilution                                    $ 3.21   $ 3.61    $2.57
                                            ======== ======== ========

(1) Adjusted net income available to common and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:

a. Management uses adjusted net income available to common to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.

b. Adjusted net income available to common is more comparable to earnings estimates provided by securities analysts.

c. Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

(2) Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

                    CHESAPEAKE ENERGY CORPORATION
                  RECONCILIATION OF ADJUSTED EBITDA
                           ($ in millions)
                             (unaudited)

                                            December December December
                                               31,      31,      31,
 TWELVE MONTHS ENDED:                         2007     2006     2005
---------------------------------------------------- -------- --------

EBITDA                                       $4,736   $5,019   $2,658

Adjustments, before tax:
   Unrealized (gains) losses on oil and
    natural gas derivatives                     375     (496)     (41)
   Reversal of severance tax accrual             --      (12)      --
   Gain on sale of investment                   (83)    (117)      --
   Employee retirement expense                   --       55       --
   Loss on repurchase or exchange of senior
    notes                                        --       --       70
                                            -------- -------- --------

Adjusted EBITDA(1)                           $5,028   $4,449   $2,687
                                            ======== ======== ========

(1) Adjusted EBITDA excludes certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to EBITDA because:

a. Management uses adjusted EBITDA to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.

b. Adjusted EBITDA is more comparable to earnings estimates provided by securities analysts.

c. Items excluded generally are one-time items, or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

                    CHESAPEAKE ENERGY CORPORATION
                       RECONCILIATION OF PV-10
                           ($ in millions)
                             (unaudited)

                                             December 31, December 31,
                                                2007          2006
------------------------------------------ -------------- ------------

Standardized measure of discounted future
 net cash flows                                   $14,962      $10,007

Discounted future cash flows for income
 taxes                                              5,611        3,640
                                           -------------- ------------

Discounted future net cash flows before
 income taxes (PV-10)                             $20,573      $13,647

PV-10 is discounted (at 10%) future net cash flows before income taxes. The standardized measure of discounted future net cash flows includes the effects of estimated future income tax expenses and is calculated in accordance with SFAS 69. Management uses PV-10 as one measure of the value of the company's current proved reserves and to compare relative values among peer companies without regard to income taxes. We also understand that securities analysts and rating agencies use this measure in similar ways. While PV-10 is based on prices, costs and discount factors which are consistent from company to company, the standardized measure is dependent on the unique tax situation of each individual company.

The company's December 31, 2007 PV-10 and standardized measure were calculated using field differential adjusted prices of $6.19 mcf (based on a NYMEX year-end price of $6.80 per mcf) and $90.58 per bbl (based on a NYMEX year-end price of $96.00 per bbl). The company's December 31, 2006 PV-10 and standardized measure were calculated using field differential adjusted prices of $5.41 per mcf (based on a NYMEX year-end price of $5.64 per mcf) and $56.25 per bbl (based on a NYMEX year-end price of $61.15 per bbl).

    SCHEDULE "A"

    CHESAPEAKE'S OUTLOOK AS OF FEBRUARY 21, 2008

Quarter Ending March 31, 2008 and Years Ending December 31, 2008 and 2009.

We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance. As of February 21, 2008, we are using the following key assumptions in our projections for the first quarter of 2008 and the full years 2008 and 2009.

The primary changes from our November 6, 2007 Outlook are in italicized bold and are explained as follows:

1) We are providing our first guidance for the 2008 first quarter and increasing our prior production guidance for the full years 2008 and 2009. Guidance in this Outlook excludes production expected to be sold in conjunction with various anticipated monetization transactions in 2008 and 2009, whereas guidance issued on November 6, 2007 included such volumes;

2) Projected effects of changes in our hedging positions have been updated;

3) Certain cost assumptions, shares outstanding and budgeted capital expenditure assumptions have been updated; and

4) Our projected book tax rate has been updated.

                     Quarter Ending    Year Ending      Year Ending
                        3/31/2008       12/31/2008       12/31/2009
                     --------------- ---------------- ----------------
Estimated
 Production(a)
  Oil - mbbls                 2,675           10,500           11,000
  Natural gas - bcf       182 - 186        788 - 798        892 - 902
  Natural gas
   equivalent - bcfe      198 - 202        851 - 861        958 - 968

  Daily natural gas
   equivalent
   midpoint - mmcfe           2,200            2,340            2,640

NYMEX Prices (b)
 (for calculation of
 realized hedging
 effects only):
  Oil - $/bbl        $        80.98  $         76.49  $         75.00
  Natural gas -
   $/mcf             $         7.55  $          7.51  $          7.50

Estimated Realized
 Hedging Effects
 (based on assumed
 NYMEX prices
 above):
  Oil - $/bbl        $        (6.98) $         (2.11) $          6.00
  Natural gas -
   $/mcf             $         1.84  $          1.39  $          0.63

Estimated
 Differentials to
 NYMEX Prices:
  Oil - $/bbl                 7 - 9%           7 - 9%           7 - 9%
  Natural gas -
   $/mcf                    10 - 14%         10 - 14%         10 - 14%

Operating Costs per
 Mcfe of Projected
 Production:
  Production expense $  0.90 - 1.00  $   0.90 - 1.00  $   0.90 - 1.00
  Production taxes
   (generally 5% of
   O&G revenues) (c) $  0.32 - 0.37  $   0.32 - 0.37  $   0.32 - 0.37
  General and
   administrative(d) $  0.33 - 0.37  $   0.33 - 0.37  $   0.33 - 0.37
  Stock-based
   compensation
   (non-cash)        $  0.08 - 0.10  $   0.10 - 0.12  $   0.10 - 0.12
  DD&A of oil and
   natural gas
   assets            $  2.50 - 2.70  $   2.50 - 2.70  $   2.50 - 2.70
  Depreciation of
   other assets      $  0.20 - 0.24  $   0.20 - 0.24  $   0.20 - 0.24
  Interest
   expense(e)        $  0.50 - 0.55  $   0.50 - 0.55  $   0.50 - 0.55
Other Income per
 Mcfe:
  Oil and natural
   gas marketing
   income            $  0.09 - 0.11  $   0.09 - 0.11  $   0.09 - 0.11
  Service operations
   income            $  0.04 - 0.06  $   0.04 - 0.06  $   0.04 - 0.06

Book Tax Rate (About
 Equals 97%
 deferred)                     38.5%            38.5%            38.5%
Equivalent Shares
 Outstanding - in
 millions:
  Basic                         493              496              504
  Diluted                       525              526              534
Budgeted Capital
 Expenditures, net -
 in millions:
  Drilling           $1,100 - 1,200  $ 4,400 - 4,800  $ 4,400 - 4,800
  Leasehold and
   property
   acquisition costs $    400 - 450  $ 1,200 - 1,400  $ 1,200 - 1,400
  Monetization of
   oil and gas
   properties(a)                 --  $        (1,000) $        (1,000)
  Geological and
   geophysical costs $           75  $     250 - 300  $     250 - 300
                     --------------- ---------------- ----------------
      Total budgeted
       capital
       expenditures,
       net           $1,575 - 1,725  $4,850 - $5,500  $4,850 - $5,500

(a) The 2008 and 2009 forecasts assume that the company monetizes $2 billion of producing properties in multiple transactions in the second and fourth quarters of 2008 and 2009.

(b) NYMEX oil prices have been updated for actual contract prices through January 2008 and NYMEX natural gas prices have been updated for actual contract prices through February 2008.

(c) Severance tax per mcfe is based on NYMEX prices of: $80.98 per bbl of oil and $7.00 to $8.00 per mcf of natural gas during Q1 2008; $76.49 per bbl of oil and $7.40 to $8.40 per mcf of natural gas during calendar 2008; and $75.00 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during calendar 2009.

(d) Excludes expenses associated with non-cash stock compensation.

(e) Does not include gains or losses on interest rate derivatives (SFAS 133).

Commodity Hedging Activities

The company utilizes hedging strategies to hedge the price of a portion of its future oil and natural gas production. These strategies include:

(i) For swap instruments, Chesapeake receives a fixed price and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

(ii) For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a "cap" limiting the counterparty's exposure. In other words, there is no limit to Chesapeake's exposure but there is a limit to the downside exposure of the counterparty.

(iii) For knockout swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty's exposure to zero, in any given month, if the floating market price is lower than certain predetermined knockout prices.

(iv) For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake.

(v) Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

(vi) A three-way collar contract consists of a standard collar contract plus a written put option with a strike price below the floor price of the collar. In addition to the settlement of the collar, the put option requires Chesapeake to make a payment to the counterparty equal to the difference between the put option price and the settlement price if the settlement price for any settlement period is below the put option strike price.

(vii) Basis protection swaps are arrangements that guarantee a price differential for oil or natural gas from a specified delivery point. For Mid-Continent basis protection swaps, which have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian basis protection swaps, which have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

Commodity markets are volatile, and as a result, Chesapeake's hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction.

Chesapeake enters into oil and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and natural gas prices. Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to oil and natural gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and natural gas sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these nonqualifying derivatives that occur prior to their maturity (i.e., because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within oil and natural gas sales.

Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and natural gas sales.

Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas swaps:

                                                             Total
                                    Open Swap                Lifted
                                     Positions    Total     Gain per
                 Avg.    Assuming    as a % of    Gains      Mcf of
                 NYMEX    Natural    Estimated     from     Estimated
          Open   Strike     Gas        Total      Lifted     Total
          Swaps  Price   Production   Natural      Swaps     Natural
          in    of Open  in Bcf's       Gas        ($          Gas
          Bcf's  Swaps      of:      Production  millions)  Production
======== ====== ======= =========== =========== ========== ===========
Q1 2008   131.0 $  8.59         184         71% $    156.4 $      0.85
Q2 2008   133.0 $  8.51         194         69% $     44.5 $      0.23
Q3 2008   132.5 $  8.69         205         65% $     40.5 $      0.20
Q4 2008   119.5 $  9.23         210         57% $     45.3 $      0.22
======== ====== ======= =========== =========== ========== ===========
Total
 2008(1)  516.0 $  8.74         793         65% $    286.7 $      0.36
======== ====== ======= =========== =========== ========== ===========

======== ====== ======= =========== =========== ========== ===========
Total
 2009(1)  276.0 $  9.04         897         31% $     12.8 $      0.01
======== ====== ======= =========== =========== ========== ===========

(1) Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty's exposure below prices ranging from $5.45 to $6.50 covering 191 bcf in 2008 and $5.45 to $6.50 covering 214 bcf in 2009.

The company currently has the following open natural gas collars in place:

                                                             Open
                                                            Collars
                                               Assuming   as a % of
                                                Natural    Estimated
                              Avg.    Avg.        Gas        Total
                      Open     NYMEX  NYMEX    Production   Natural
                      Collars  Floor  Ceiling  in Bcf's       Gas
                     in Bcf's  Price   Price      of:      Production
==================== ======== ====== ======== =========== ===========
Q1 2008                  18.5  $7.36   $ 9.28         184         10%
Q2 2008                   2.7  $7.50   $ 9.68         194          1%
Q3 2008                   2.8  $7.50   $ 9.68         205          1%
Q4 2008                   2.8  $7.50   $ 9.68         210          1%
==================== ======== ====== ======== =========== ===========
Total 2008(1)            26.8  $7.41   $ 9.40         793          3%
==================== ======== ====== ======== =========== ===========

==================== ======== ====== ======== =========== ===========
Total 2009(1)            45.7  $8.14   $10.82         897          5%
==================== ======== ====== ======== =========== ===========

(1) Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 11 bcf in 2008 and $5.50 to $6.00 covering 46 bcf in 2009.

Note: Not shown above are written call options covering 110 bcf of production in 2008 at a weighed average price of $10.26 for a weighted average premium of $0.66 and 142 bcf of production in 2009 at a weighed average price of $11.18 for a weighted average premium of $0.48.

The company has the following natural gas basis protection swaps in place:

                       Mid-Continent                Appalachia
                  ----------------------- ---------------------------
                    Volume in   NYMEX       Volume in     NYMEX
                     Bcf's       less(1):    Bcf's         plus(1):
                  ----------- ----------- ------------- -------------
2008                    132.4        0.36          23.0          0.33
2009                     91.1        0.33          16.9          0.28
2010                       --          --          10.2          0.26
2011                       --          --          12.1          0.25
2012                     10.7        0.34            --            --
                  ----------- ----------- ------------- -------------
Totals                  234.2       $0.35          62.2         $0.29
                  =========== =========== ============= =============

(1) weighted average

We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition in November 2005. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($173 million as of December 31, 2007). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.

Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative Instruments and Hedging Activities," the assumed CNR derivative instruments are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows.

The following details the CNR derivatives (natural gas swaps) we have assumed:

                 Avg.                                      Open Swap
                 NYMEX                                      Positions
                 Strike  Avg. Fair              Assuming    as a % of
                 Price  Value Upon               Natural    Estimated
          Open  Of Open  Acquisition  Initial      Gas        Total
         Swaps   Swaps    of Open    Liability  Production   Natural
          in     (per       Swaps     Acquired  in Bcf's       Gas
          Bcf's   Mcf)   (per Mcf)   (per Mcf)     of:      Production
-------- ------ ------- ------------ --------- ----------- -----------
Q1 2008     9.5   $4.68        $9.42   ($4.74)         184          5%
Q2 2008     9.5   $4.68        $7.41   ($2.73)         194          5%
Q3 2008     9.7   $4.68        $7.41   ($2.74)         205          5%
Q4 2008     9.7   $4.66        $7.84   ($3.17)         210          5%
======== ====== ======= ============ ========= =========== ===========
Total
 2008      38.4   $4.68        $8.02   ($3.34)         793          5%
======== ====== ======= ============ ========= =========== ===========

======== ====== ======= ============ ========= =========== ===========
Total
 2009      18.3   $5.18        $7.28   ($2.10)         897          2%
======== ====== ======= ============ ========= =========== ===========

Note: Not shown above are collars covering 3.7 bcf of production in 2009 at an average floor and ceiling of $4.50 and $6.00.

The company also has the following crude oil swaps in place:

                                     Open Swap    Total      Total
                                    Positions     Losses     Lifted
                          Assuming     as a %      from     Losses per
           Open   Avg.      Oil         of        Lifted     bbl of
            Swaps  NYMEX Production  Estimated     Swaps    Estimated
            in    Strike in mbbls   Total Oil      ($      Total Oil
            mbbls  Price     of:     Production  millions)  Production
---------- ------ ------ ---------- ----------- ---------- -----------
Q1 2008     1,823  73.97      2,675         68%    $ (3.2)     $(1.21)
Q2 2008     1,866  75.22      2,605         72%    $ (4.7)     $(1.81)
Q3 2008     1,886  75.11      2,610         72%    $ (4.6)     $(1.76)
Q4 2008     1,702  76.79      2,610         65%    $ (4.7)     $(1.82)
========== ====== ====== ========== =========== ========== ===========
Total
 2008(1)    7,277 $75.24     10,500         69%    $(17.2)     $(1.65)
========== ====== ====== ========== =========== ========== ===========

========== ====== ====== ========== =========== ========== ===========
Total
 2009(1)    8,030 $81.60     11,000         73%        --          --
========== ====== ====== ========== =========== ========== ===========

(1) Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty's exposure below prices ranging from $45.00 to $60.00 covering 4,090 mbbls in 2008 and from $52.50 to $60.00 covering 7,483 mbbls in 2009.

Note: Not shown above are written call options covering 2,564 mbbls of production in 2008 at a weighted average price of $82.50 for a weighted average premium of $3.17 and 2,555 mbbls of production in 2009 at a weighed average price of $82.14 for a weighted average premium of $4.98.

    SCHEDULE "B"

    CHESAPEAKE'S PREVIOUS OUTLOOK AS OF NOVEMBER 6, 2007

    (PROVIDED FOR REFERENCE ONLY)

    NOW SUPERSEDED BY OUTLOOK AS OF FEBRUARY 21, 2008

Quarter Ending December 31, 2007 and Years Ending December 31, 2007, 2008 and 2009.

We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance. As of November 6, 2007, we are using the following key assumptions in our projections for the fourth quarter of 2007 and the full years 2007, 2008 and 2009.

The primary changes from our September 4, 2007 Outlook are in italicized bold and are explained as follows:

1) We are increasing our prior production guidance for the 2007 fourth quarter and for 2008 and 2009;

2) Production assumptions have been updated;

3) Projected effects of changes in our hedging positions have been updated; and

4) Certain cost assumptions, shares outstanding and budgeted capital expenditure assumptions have been updated.

                                     Quarter Ending    Year Ending
                                       12/31/2007       12/31/2007
                                    ---------------- -----------------
Estimated Production(a)
  Oil - mbbls                                 2,500            9,600
  Natural gas - bcf                   181.5 - 183.5        649 - 651
  Natural gas equivalent - bcfe       196.5 - 198.5        707 - 709
  Daily natural gas equivalent
   midpoint - in mmcfe                        2,150            1,940

NYMEX Prices (b) (for calculation of realized hedging effects only):
  Oil - $/bbl                       $         79.84  $         69.60
  Natural gas - $/mcf               $          7.07  $          6.89

Estimated Realized Hedging Effects (based on assumed NYMEX prices
 above):
  Oil - $/bbl                       $         (5.40) $          1.28
  Natural gas - $/mcf               $          1.68  $          1.84

Estimated Differentials to NYMEX
 Prices:
  Oil - $/bbl                                 7 - 9%           7 - 9%
  Natural gas - $/mcf                       10 - 14%         10 - 14%

Operating Costs per Mcfe of Projected Production:
  Production expense                $   0.90 - 1.00  $   0.90 - 1.00
  Production taxes (generally 5.5%
   of O&G revenues) (c)             $   0.35 - 0.40  $   0.35 - 0.40
  General and administrative        $   0.25 - 0.30  $   0.25 - 0.30
  Stock-based compensation (non-
   cash)                            $   0.08 - 0.10  $   0.08 - 0.10
  DD&A of oil and natural gas
   assets                           $   2.60 - 2.70  $   2.50 - 2.70
  Depreciation of other assets      $   0.18 - 0.20  $   0.20 - 0.24
  Interest expense(d)               $   0.55 - 0.60  $   0.55 - 0.60
Other Income per Mcfe:
  Oil and natural gas marketing
   income                           $   0.04 - 0.06  $   0.08 - 0.10
  Service operations income         $   0.04 - 0.06  $   0.05 - 0.07

Book Tax Rate (About Equals 97%
 deferred)                                       38%              38%
Equivalent Shares Outstanding - in
 millions:
  Basic                                         480              459
  Diluted                                       520              519
Budgeted Capital Expenditures, net - in millions:
  Drilling                          $ 1,000 - 1,100  $ 4,250 - 4,450
  Leasehold and property
   acquisition costs                $     300 - 350  $ 1,200 - 1,400
  Monetization of oil and gas
   properties(a)                    $(1,000 - 1,200) $(1,000 - 1,200)
  Geological and geophysical costs  $       50 - 75  $     250 - 300
                                    ---------------- -----------------
      Total budgeted capital
       expenditures, net            $     325 - 350  $ 4,700 - 4,950

                                       Year Ending      Year Ending
                                        12/31/2008       12/31/2009
                                     ---------------- ----------------
Estimated Production(a)
  Oil - mbbls                                 10,500           11,000
  Natural gas - bcf                        788 - 798        892 - 902
  Natural gas equivalent - bcfe            851 - 861        958 - 968
  Daily natural gas equivalent
   midpoint - in mmcfe                         2,340            2,640

NYMEX Prices (b) (for calculation of realized hedging effects only):
  Oil - $/bbl                        $         75.00  $         75.00
  Natural gas - $/mcf                $          7.50  $          7.50

Estimated Realized Hedging Effects (based on assumed NYMEX prices
 above):
  Oil - $/bbl                        $         (0.44) $          3.88
  Natural gas - $/mcf                $          1.36  $          0.53

Estimated Differentials to NYMEX
 Prices:
  Oil - $/bbl                                  7 - 9%           7 - 9%
  Natural gas - $/mcf                        10 - 14%         10 - 14%

Operating Costs per Mcfe of Projected Production:
  Production expense                 $   0.90 - 1.00  $   0.90 - 1.00
  Production taxes (generally 5.5%
   of O&G revenues) (c)              $   0.35 - 0.40  $   0.35 - 0.40
  General and administrative         $   0.25 - 0.30  $   0.25 - 0.30
  Stock-based compensation (non-
   cash)                             $   0.10 - 0.12  $   0.10 - 0.12
  DD&A of oil and natural gas
   assets                            $   2.50 - 2.70  $   2.50 - 2.70
  Depreciation of other assets       $   0.26 - 0.30  $   0.26 - 0.30
  Interest expense(d)                $   0.55 - 0.60  $   0.55 - 0.60
Other Income per Mcfe:
  Oil and natural gas marketing
   income                            $   0.07 - 0.09  $   0.07 - 0.09
  Service operations income          $   0.05 - 0.07  $   0.05 - 0.07

Book Tax Rate (About Equals 97%
 deferred)                                        38%              38%
Equivalent Shares Outstanding - in
 millions:
  Basic                                          496              504
  Diluted                                        525              532
Budgeted Capital Expenditures, net - in millions:
  Drilling                           $ 4,000 - 4,200  $ 4,000 - 4,200
  Leasehold and property
   acquisition costs                 $ 1,200 - 1,400  $ 1,200 - 1,400
  Monetization of oil and gas
   properties(a)                     $(1,000 - 1,200) $(1,000 - 1,200)
  Geological and geophysical costs   $     200 - 250  $     200 - 250
                                     ---------------- ----------------
      Total budgeted capital
       expenditures, net             $4,400 - $4,650  $4,400 - $4,650

(a) The 2008 and 2009 forecasts assume that the company monetizes producing properties in multiple transactions beginning late in the fourth quarter of 2007. For accounting purposes, the company anticipates that the proposed monetization transactions will be treated as prepaid sales rather than property sales. As a result, Chesapeake's forecast does not reflect a reduction of production volumes from the monetized properties.

(b) Oil NYMEX prices have been updated for actual contract prices through October 2007 and natural gas NYMEX prices have been updated for actual contract prices through November 2007.

(c) Severance tax per mcfe is based on NYMEX prices of: $79.84 per bbl of oil and $6.70 to $7.80 per mcf of natural gas during Q4 2007; $69.60 per bbl of oil and $6.80 to $7.90 per mcf of natural gas during calendar 2007; and $75.00 per bbl of oil and $6.80 to $7.90 per mcf of natural gas during calendar 2008 and 2009.

(d) Does not include gains or losses on interest rate derivatives (SFAS 133).

Commodity Hedging Activities

The company utilizes hedging strategies to hedge the price of a portion of its future oil and natural gas production. These strategies include:

(i) For swap instruments, Chesapeake receives a fixed price and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

(ii) For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a "cap" limiting the counterparty's exposure. In other words, there is no limit to Chesapeake's exposure but there is a limit to the downside exposure of the counterparty.

(iii) For knockout swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty's exposure to zero, in any given month, if the floating market price is lower than certain predetermined knockout prices.

(iv) For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake.

(v) Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

(vi) A three-way collar contract consists of a standard collar contract plus a written put option with a strike price below the floor price of the collar. In addition to the settlement of the collar, the put option requires Chesapeake to make a payment to the counterparty equal to the difference between the put option price and the settlement price if the settlement price for any settlement period is below the put option strike price.

(vii) Basis protection swaps are arrangements that guarantee a price differential for oil or natural gas from a specified delivery point. For Mid-Continent basis protection swaps, which have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian basis protection swaps, which have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

Commodity markets are volatile, and as a result, Chesapeake's hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction.

Chesapeake enters into oil and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and natural gas prices. Accordingly, associated gains or loses from the derivative transactions are reflected as adjustments to oil and natural gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and natural gas sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these nonqualifying derivatives that occur prior to their maturity (i.e., because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within oil and natural gas sales.

Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and natural gas sales.

Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas swaps:

                                                             Total
                                    Open Swap                Lifted
                                     Positions    Total     Gain per
                 Avg.    Assuming    as a % of    Gains      Mcf of
                 NYMEX    Natural    Estimated     from     Estimated
         Open    Strike     Gas        Total      Lifted     Total
          Swaps  Price   Production   Natural      Swaps     Natural
          in    of Open  in Bcf's       Gas        ($          Gas
          Bcf's  Swaps      of:      Production  millions)  Production
======== ====== ======= =========== =========== ========== ===========
Q4
 2007(1)  141.4 $  7.77       182.5 78%         $    158.1 $      0.87
======== ====== ======= =========== =========== ========== ===========
Q1 2008   130.5 $  8.74         188 69%         $    133.0 $      0.71
Q2 2008   125.4 $  8.57         194 65%         $     38.8 $      0.20
Q3 2008   124.9 $  8.74         202 62%         $     35.9 $      0.18
Q4 2008   117.6 $  9.27         209 56%         $     37.7 $      0.18
======== ====== ======= =========== =========== ========== ===========
Total
 2008(1)  498.4 $  8.82         793 63%         $    245.4 $      0.31
======== ====== ======= =========== =========== ========== ===========

======== ====== ======= =========== =========== ========== ===========
Total
 2009(1)  233.5 $  8.98         897 26%         $     12.5 $      0.01
======== ====== ======= =========== =========== ========== ===========

(1) Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty's exposure below prices ranging from $5.25 to $6.25 covering 17 bcf in Q4 2007, $5.45 to $6.50 covering 186 bcf in 2008 and $5.45 to $6.50 covering 152 bcf in 2009.

The company currently has the following open natural gas collars in place:

                                                              Open
                                                             Collars
                                                Assuming   as a % of
                                                 Natural    Estimated
                               Avg.    Avg.        Gas        Total
                       Open     NYMEX  NYMEX    Production   Natural
                       Collars  Floor  Ceiling  in Bcf's       Gas
                      in Bcf's  Price   Price      of:      Production
===================== ======== ====== ======== =========== ===========
Q4 2007(1)                19.6  $7.13   $ 8.88       182.5         11%
===================== ======== ====== ======== =========== ===========
Q1 2008                   18.5  $7.36   $ 9.28         188         10%
Q2 2008                    2.7  $7.50   $ 9.68         194          1%
Q3 2008                    2.8  $7.50   $ 9.68         202          1%
Q4 2008                    2.8  $7.50   $ 9.68         209          1%
===================== ======== ====== ======== =========== ===========
Total 2008(1)             26.8  $7.41   $ 9.40         793          3%
===================== ======== ====== ======== =========== ===========

===================== ======== ====== ======== =========== ===========
Total 2009(1)             27.4  $7.97   $11.18         897          3%
===================== ======== ====== ======== =========== ===========

(1) Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 14 bcf in Q4 2007, $5.00 to $6.00 covering 11 bcf in 2008 and $5.50 to $6.00 covering 27 bcf in 2009.

Note: Not shown above are written call options covering 7 bcf of production in Q4 2007 at a weighted average price of $7.85 for a weighted average premium of $1.13, 110 bcf of production in 2008 at a weighed average price of $10.26 for a weighted average premium of $0.66 and 119 bcf of production in 2009 at a weighed average price of $11.12 for a weighted average premium of $0.54.

The company has the following natural gas basis protection swaps in place:

                       Mid-Continent                 Appalachia
                 ------------------------- ---------------------------
                      Volume                      Volume
                       in        NYMEX             in        NYMEX
                       Bcf's      less(a):         Bcf's      plus(a):
                 ----------- ------------- ------------- -------------
Q4 2007                 33.3          0.26           9.2          0.35
2008                   118.6          0.27          43.9          0.35
2009                    86.6          0.29          36.5          0.31
2010                      --            --          29.2          0.31
2011                      --            --          29.2          0.32
2012                    10.7          0.34            --            --
                 ----------- ------------- ------------- -------------
Totals                 249.2         $0.28         148.0         $0.33
                 =========== ============= ============= =============

(a) weighted average

We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition in November 2005. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($216 million as of September 30, 2007). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.

Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative Instruments and Hedging Activities," the assumed CNR derivative instruments are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows.

The following details the CNR derivatives (natural gas swaps) we have assumed:

                 Avg.                                      Open Swap
                 NYMEX                                      Positions
                 Strike  Avg. Fair              Assuming    as a % of
                 Price  Value Upon               Natural    Estimated
          Open  Of Open  Acquisition  Initial      Gas        Total
         Swaps   Swaps    of Open    Liability  Production   Natural
          in     (per       Swaps     Acquired  in Bcf's       Gas
          Bcf's   Mcf)   (per Mcf)   (per Mcf)     of:      Production
-------- ------ ------- ------------ --------- ----------- -----------
Q4 2007    10.6   $4.82        $8.87   ($4.05)       182.5          6%
======== ====== ======= ============ ========= =========== ===========
Q1 2008     9.5   $4.68        $9.42   ($4.74)         188          5%
Q2 2008     9.5   $4.68        $7.41   ($2.73)         194          5%
Q3 2008     9.7   $4.68        $7.41   ($2.74)         202          5%
Q4 2008     9.7   $4.66        $7.84   ($3.17)         209          5%
======== ====== ======= ============ ========= =========== ===========
Total
 2008      38.4   $4.68        $8.02   ($3.34)         793          5%
======== ====== ======= ============ ========= =========== ===========

======== ====== ======= ============ ========= =========== ===========
Total
 2009      18.3   $5.18        $7.28   ($2.10)         897          2%
======== ====== ======= ============ ========= =========== ===========

Note: Not shown above are collars covering 3.7 bcf of production in 2009 at an average floor and ceiling of $4.50 and $6.00.

The company also has the following crude oil swaps in place:

                                     Open Swap    Total      Total
                                    Positions     Gains      Lifted
                          Assuming     as a %      from     Gain per
           Open   Avg.      Oil         of        Lifted     bbl of
            Swaps  NYMEX Production  Estimated     Swaps    Estimated
            in    Strike in mbbls   Total Oil      ($      Total Oil
            mbbls  Price     of:     Production  millions)  Production
---------- ------ ------ ---------- ----------- ---------- -----------
Q4 2007(1)  1,564 $72.84      2,500         63%     $(0.5)     $(0.21)
========== ====== ====== ========== =========== ========== ===========
Q1 2008     1,971  72.84      2,470         80%     $ 1.2      $ 0.49
Q2 2008     2,002  72.59      2,560         78%     $ 1.2      $ 0.47
Q3 2008     2,024  72.44      2,690         75%     $ 1.2      $ 0.45
Q4 2008     1,840  73.48      2,780         66%     $ 1.2      $ 0.43
========== ====== ====== ========== =========== ========== ===========
Total
 2008(1)    7,837 $72.82     10,500         75%     $ 4.8      $ 0.46
========== ====== ====== ========== =========== ========== ===========

========== ====== ====== ========== =========== ========== ===========
Total
 2009(1)    8,030 $78.81     11,000         73%        --          --
========== ====== ====== ========== =========== ========== ===========

(1) Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty's exposure below prices ranging from $45.00 to $60.00 covering 736 mbbls in Q4 2007 and 3,478 mbbls in 2008 and from $52.50 to $60.00 covering 7,483 mbbls in 2009.

Note: Not shown above are written call options covering 920 mbbls of production in Q4 2007 at a weighted average price of $79.85 for a weighted average premium of $1.00, 2,564 mbbls of production in 2008 at a weighted average price of $82.50 for a weighted average premium of $3.17 and 2,190 mbbls of production in 2009 at a weighed average price of $75.00 for a weighted average premium of $5.47.

CONTACT: Chesapeake Energy Corporation
Jeffrey L. Mobley, CFA, 405-767-4763
Senior Vice President - Investor Relations and Research
jeff.mobley@chk.com
or
Marc Rowland, 405-879-9232
Executive Vice President and Chief Financial Officer
marc.rowland@chk.com
SOURCE: Chesapeake Energy Corporation