Financial Data

The following table sets forth certain information regarding the production
volumes, natural gas and oil sales, average sales prices received, other
operating income and expenses for the periods indicated:



                                                             Years Ended December 31,
                                                       2008            2007            2006
Net Production:
Natural gas (mmcf)                                     775,424         654,969         526,459
Oil (mbbls)                                             11,220           9,882           8,654
Natural gas equivalent (mmcfe)                         842,744         714,261         578,383
Natural Gas and Oil Sales ($ in millions):
Natural gas sales                                    $   6,003       $   4,117       $   3,343
Natural gas derivatives - realized gains
(losses)                                                   267           1,214           1,269
Natural gas derivatives - unrealized gains
(losses)                                                   521            (139 )           467

Total natural gas sales                                  6,791           5,192           5,079

Oil sales                                                1,066             678             527
Oil derivatives - realized gains (losses)                 (275 )           (11 )           (15 )
Oil derivatives - unrealized gains (losses)                276            (235 )            28

Total oil sales                                          1,067             432             540

Total natural gas and oil sales                      $   7,858       $   5,624       $   5,619

Average Sales Price (excluding gains (losses) on
derivatives):
Natural gas ($ per mcf)                              $    7.74       $    6.29       $    6.35
Oil ($ per bbl)                                      $   95.04       $   68.64       $   60.86
Natural gas equivalent ($ per mcfe)                  $    8.39       $    6.71       $    6.69
Average Sales Price (excluding unrealized gains
(losses) on derivatives):
Natural gas ($ per mcf)                              $    8.09       $    8.14       $    8.76
Oil ($ per bbl)                                      $   70.48       $   67.50       $   59.14
Natural gas equivalent ($ per mcfe)                  $    8.38       $    8.40       $    8.86
Other Operating Income (a) ($ in millions):
Natural gas and oil marketing                        $      93       $      71       $      55
Service operations                                   $      30       $      42       $      62
Other Operating Income (a) ($ per mcfe):
Natural gas and oil marketing                        $    0.11       $    0.10       $    0.09
Service operations                                   $    0.04       $    0.06       $    0.11
Expenses ($ per mcfe):
Production expenses                                  $    1.05       $    0.90       $    0.85
Production taxes                                     $    0.34       $    0.30       $    0.31
General and administrative expenses                  $    0.45       $    0.34       $    0.24
Natural gas and oil depreciation, depletion and
amortization                                         $    2.34       $    2.57       $    2.35
Depreciation and amortization of other assets        $    0.21       $    0.22       $    0.18
Interest expense (b)                                 $    0.27       $    0.51       $    0.52
Interest Expense ($ in millions):
Interest expense                                     $     235       $     365       $     301
Interest rate derivatives - realized (gains)
losses                                                      (6 )             1               2
Interest rate derivatives - unrealized (gains)
losses                                                      85              40              (2 )

Total interest expense                               $     314       $     406       $     301

Net Wells Drilled                                        1,733           1,919           1,449
Net Producing Wells as of the End of Period             22,813          21,404          19,079

(a) Includes revenue and operating costs and excludes depreciation and amortization of other assets.

(b) Includes the effects of realized gains (losses) from interest rate derivatives, but excludes the effects of unrealized gains (losses) and is net of amounts capitalized.

We manage our business as three separate operational segments: exploration and production; marketing; and service operations, which is comprised of our wholly-owned drilling and trucking operations. We refer you to Note 14 of the notes to our consolidated financial statements appearing in Item 8 of this report, which summarizes by segment our net income and capital expenditures for 2008, 2007 and 2006 and our assets as of December 31, 2008, 2007 and 2006.

Executive Summary

We are the largest independent producer of natural gas in the United States. We own interests in approximately 41,200 producing oil and natural gas wells that are currently producing approximately 2.3 bcfe per day, 92% of which is natural gas. Our strategy is focused on discovering, acquiring and developing conventional and unconventional natural gas reserves onshore in the U.S., primarily in the "Big 4" natural gas shale plays: the Barnett Shale in the Fort Worth Basin of north-central Texas, the Haynesville Shale in the Ark-La-Tex area of northwestern Louisiana and East Texas, the Fayetteville Shale in the Arkoma Basin of central Arkansas and the Marcellus Shale in the northern Appalachian Basin of West Virginia, Pennsylvania and New York. We also have substantial operations in various other plays, both conventional and unconventional, in the Mid-Continent, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and Ark-La-Tex regions of the United States.

During 2008, Chesapeake continued the industry's most active drilling program drilling 1,819 gross (1,491 net) operated wells and participating in another 1,857 gross (242 net) wells operated by other companies. The company's drilling success rate was 99% for company-operated wells and 98% for non-operated wells. Also during 2008, we invested $5.043 billion in operated wells (using an average of 145 operated rigs) and $754 million in non-operated wells (using an average of 110 non-operated rigs) for total drilling, completing and equipping costs of $5.797 billion.

Chesapeake began 2008 with estimated proved reserves of 10.879 tcfe and ended the year with 12.051 tcfe, an increase of 1.172 tcfe, or 11%. During 2008, we replaced 843 bcfe of production with an internally estimated 2.015 tcfe of new proved reserves, for a reserve replacement rate of 239%. Reserve replacement through the drillbit was 2.545 tcfe, or 302% of production, including 1.248 tcfe of positive performance revisions and 298 bcfe of negative revisions resulting from natural gas and oil price decreases between December 31, 2007 and December 31, 2008. Reserve replacement through the acquisition of proved reserves was 172 bcfe. During 2008, we divested 702 bcfe of estimated proved reserves. Our annual decline rate on producing properties is projected to be 29% from 2009 to 2010, 18% from 2010 to 2011, 14% from 2011 to 2012, 11% from 2012 to 2013 and 9% from 2013 to 2014. Our percentage of proved undeveloped reserve additions to total proved reserve additions was approximately 2% in 2008, 29% in 2007 and 38% in 2006. Based on our current drilling schedule and budget, we expect that virtually all of the proved undeveloped reserves added in 2008 will begin producing within the next three to five years. Generally, proved developed reserves are producing at the time they are added or will begin producing within one year.

Since 2000, Chesapeake has invested $12.6 billion in new leasehold (net of divestitures) and 3-D seismic acquisitions and now owns the largest combined inventories of onshore leasehold (15 million net acres) and 3-D seismic (22 million acres) in the U.S. On this leasehold, the company has approximately 36,000 net drillsites representing more than a 10-year inventory of drilling projects.

Business Strategy

Our exploration, development and acquisition activities require us to make substantial operating and capital expenditures. Through the middle of 2008, we increased our capital expenditure budget for 2008 and 2009 several times in response to higher leasehold acquisition costs and in order to accelerate leasehold acquisition and drilling in the Haynesville Shale and other plays. During the second half of 2008, in response to a significant decrease in natural gas prices, deteriorating global economic conditions and outlook and concerns about a

potential oversupply of natural gas in the U.S. market, we significantly reduced our planned capital expenditures through year-end 2010 in order to bring our planned operating and capital expenditures within our anticipated internally generated cash flow. Our current budgeted capital expenditures for drilling, leasehold and producing property acquisitions, geophysical costs, and additions to midstream, compression and other property and equipment are $4.150 billion to $4.675 billion in 2009 and $4.550 billion to $5.175 billion in 2010.

Cash flow from operations is our primary source of liquidity used to fund operating expenses and capital expenditures. Our $3.5 billion revolving bank credit facility and our $460 million midstream revolving bank credit facility, discussed more fully below, provide us with additional liquidity. In response to the difficulties faced by several financial institutions and to ensure we had ample liquidity available, we borrowed the remaining capacity under our revolving bank credit facility at the end of the third quarter of 2008. As a result, we had borrowings of $3.474 billion and letters of credit of $15 million outstanding under that facility as of December 31, 2008. As of December 31, 2008, we had borrowings of $460 million under the midstream credit facility.

During 2008, we relied on capital markets financings and asset monetization transactions, such as sales of producing properties, undeveloped acreage and non-strategic assets, joint venture arrangements and volumetric production payment, or VPP, transactions to provide us with additional capital. Since March 31, 2008, these types of transactions have provided approximately $12.1 billion of new capital, and up to $4.6 billion of our future drilling and completion costs in the Haynesville, Fayetteville and Marcellus Shales will be funded by our joint venture partners. These transactions are summarized below:

• From April through July of 2008, we issued 51.75 million shares of our common stock, $800 million of our 7.25% Senior Notes due 2018 and $1.380 billion of our 2.25% Contingent Convertible Senior Notes due 2038, resulting in aggregate net proceeds to us of $4.734 billion. The availability of any additional capital from the public or private markets is uncertain at this time.

• In May, August and December of 2008, we completed three separate VPP transactions involving approximately 285 bcfe of proved reserves and net production (at the time of sale) of 153 mmcfe per day from wells in Texas, Oklahoma and Kansas, resulting in aggregate net proceeds to us of $1.6 billion.

• In July of 2008, we entered into a joint venture with Plains Exploration & Production Company to develop our Haynesville Shale leasehold, under the terms of which (1) Plains acquired a 20% interest in our approximately 550,000 net acres of Haynesville Shale leasehold for $1.65 billion in cash, (2) Plains agreed to fund 50% of our 80% share of the costs associated with drilling and completing future Haynesville Shale joint venture wells over a multi-year period, up to an additional $1.65 billion and (3) Plains will have the right to a 20% participation in any additional leasehold we acquire in the Haynesville Shale. Subsequently, in February 2009, we amended the joint venture to provide Plains a one-time option in June 2010 to reduce its obligation to fund our drilling and completion costs by $800 million in exchange for assigning us 50% of its interest in the Haynesville joint venture properties.

• In August of 2008, we sold 90,000 net acres of leasehold and producing natural gas properties with net production (at the time of sale) of 50 mmcfe per day in the Arkoma Basin Woodford Shale play in Oklahoma to BP America Inc. for $1.7 billion in cash.

• In September of 2008, we entered into a joint venture with BP America Inc. to develop our Fayetteville Shale leasehold, under the terms of which
(1) BP acquired a 25% interest in our approximately 540,000 net acres of Fayetteville Shale leasehold for $1.1 billion in cash, (2) BP agreed to fund 100% of our 75% share of the costs associated with drilling and completing future Fayetteville Shale joint venture wells over a multi-year period, up to an additional $800 million and (3) BP will have the right to a 25% participation in any additional leasehold we acquire in the Fayetteville Shale.

• In November of 2008, we entered into a joint venture with a U.S. subsidiary of StatoilHydro ASA, under the terms of which StatoilHydro acquired a 32.5% interest in our approximately 1.8 million net acres of Marcellus Shale leasehold for $1.25 billion in cash, (2) StatoilHydro agreed to fund 75% of

During the fourth quarter of 2008, we privately exchanged $765 million in aggregate principal amount of our 2.75% Contingent Convertible Senior Notes due 2035, our 2.50% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 for an aggregate of 23,913,203 shares of our common stock. Our net debt as a percentage of total capitalization (total capitalization is the sum of net debt less cash on hand and stockholders' equity) was 43% as of December 31, 2008 and 47% as of December 31, 2007. The average maturity of our long-term debt as of December 31, 2008 was over eight years with an average interest rate of approximately 5.6%. No scheduled principal payments are required under our senior notes until 2013 when $864 million is due.

We plan to continue to evaluate asset monetization transactions in order to create additional value from our proved and unproved properties and to increase our financial flexibility. Management believes that our leasehold and development joint ventures and various asset monetization programs benefit the company by improving our asset base, reducing our financial risk, decreasing our DD&A rate and increasing our profitability per unit of production, thereby increasing our returns on capital and advancing future value creation. We may also consider alternative sources of public or private investment in the company or its subsidiaries. While we believe that our anticipated internally generated cash flow, cash resources and other sources of liquidity will allow us to fully fund our 2009 and 2010 operating and capital expenditure requirements, further deterioration of the economy and other factors could require us to fund these expenditures from monetization transactions or further curtail our spending.

Liquidity and Capital Resources

Sources and Uses of Funds

Cash flow from operations is a significant source of liquidity used to fund operating expenses and capital expenditures. Cash provided by operating activities was $5.236 billion in 2008, compared to $4.932 billion in 2007 and $4.843 billion in 2006. The $304 million increase from 2007 to 2008 was primarily due to higher volumes of natural gas and oil production. The $89 million increase from 2006 to 2007 was primarily due to higher volumes of natural gas and oil production. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding non-cash items, such as depreciation, depletion and amortization, deferred income taxes and unrealized gains and (losses) on derivatives. See the discussion below under Results of Operations.

Changes in market prices for natural gas and oil directly impact the level of our cash flow from operations. To mitigate the risk of declines in natural gas or oil prices and to provide more predictable future cash flow from operations, we currently have hedged through swaps and collars 78% of our expected remaining natural gas and oil production in 2009 and 48% of our expected natural gas and oil production in 2010 at average prices of $7.71 and $9.02 per mcfe, respectively. Our natural gas and oil hedges as of December 31, 2008 are detailed in Item 7A of this report. Depending on changes in natural gas and oil futures markets and management's view of underlying natural gas and oil supply and demand trends, we may increase or decrease our current hedging positions.

As of December 31, 2008, we had a net natural gas and oil derivative asset of $1.305 billion. We have arrangements with our hedging counterparties that allow us to minimize the potential liquidity impact of significant mark-to-market fluctuations in the value of our natural gas and oil hedges by making collateral allocations from our bank credit facility or directly pledging natural gas and oil properties, rather than posting cash or letters of credit with the counterparties.

Our $3.5 billion bank credit facility, our $460 million midstream bank credit facility and cash and cash equivalents are other sources of liquidity. Following the February 2009 issuance of $1.425 billion of 9.5% Senior Notes due 2015, there was as of February 26, 2009 $1.864 billion of borrowing capacity available under the revolving bank credit facility and $36 million of borrowing capacity under the midstream credit facility. We use the facilities and cash on hand to fund daily operating activities and acquisitions as needed. We borrowed $13.3 billion and repaid $11.3 billion in 2008, we borrowed $7.9 billion and repaid $6.2 billion in 2007, and we borrowed $8.4 billion and repaid $8.3 billion in 2006 under our bank credit facilities. A substantial portion of our natural gas and oil properties are not currently pledged under debt or hedging arrangements and therefore are available to be pledged as additional collateral under our revolving bank credit facility if needed based on our periodic borrowing base and collateral redeterminations. Accordingly, we believe our borrowing capacity will not be reduced associated with such periodic redeterminations.

On April 2, 2008, we issued 23 million shares of our common stock in a public offering at a price of $45.75 per share, and on July 15, 2008, we issued 28.75 million shares of common stock in a public offering at a price of $57.25 per share. On May 20, 2008 we completed public offerings of $800 million of our 7.25% Senior Notes due 2018 and $1.380 billion of our 2.25% Contingent Convertible Senior Notes due 2038. These four offerings resulted in aggregate net proceeds to us of approximately $4.734 billion, which we used to fund the redemption of our 7.75% Senior Notes due 2015 and to temporarily repay indebtedness outstanding under our revolving bank credit facility. The following table reflects the proceeds from sales of securities we issued in 2008, 2007 and 2006 (in millions):

                                               2008                      2007                      2006
                                        Total         Net         Total         Net         Total         Net
                                       Proceeds     Proceeds     Proceeds     Proceeds     Proceeds     Proceeds
Common stock                          $    2,698   $    2,598   $        -   $        -   $    1,800   $    1,759
Contingent convertible senior notes        1,380        1,349        1,650        1,607            -            -
Senior notes                                 800          787            -            -        1,799        1,755
Convertible preferred stock                    -            -            -            -          575          558

Total                                 $    4,878   $    4,734   $    1,650   $    1,607   $    4,174   $    4,072

In May 2008, we sold a portion of our proved reserves in certain producing assets in Texas, Oklahoma and Kansas in a VPP transaction for proceeds of approximately $616 million, net of transaction costs. We completed another VPP transaction in August 2008, when we sold a portion of our proved reserves in certain producing assets in the Anadarko Basin of Oklahoma for proceeds of approximately $594 million, net of transaction costs. Also, in December 2008, we sold certain long-lived producing assets in the Anadarko and Arkoma Basins in a VPP transaction for proceeds of approximately $412 million, net of transaction costs. Approximately, $43 million of the proceeds are being held in escrow until post-closing adjustments have been finalized. In August 2008, we sold leasehold and producing natural gas properties in the Arkoma Basin Woodford Shale play in Oklahoma for $1.7 billion in cash.

In the second half of 2008, the company entered into three joint venture arrangements covering three of the company's Big 4 shale plays. In the joint ventures, the company has collaborated with other leading energy companies to accelerate the development of the company's properties in the Haynesville Shale, the Fayetteville Shale and the Marcellus Shale. In total, we sold leasehold and producing property assets in which we had a cost basis of approximately $1.2 billion to these three joint venture partners for total cash consideration of $4.0 billion and up to $4.6 billion of future drilling cost carries while we retained a majority interest in each joint venture. The drilling cost carries of up to approximately $4.2 billion that remain unused as of December 31, 2008 will be extremely valuable in the years ahead by enabling the company to develop reserves in these joint venture shale plays at greatly reduced costs. We are also considering opportunities for other joint venture transactions to develop our properties.

Our primary use of funds is for capital expenditures related to exploration, development and acquisition of natural gas and oil properties. We refer you to the table under Investing Activities below, which sets forth the components of our natural gas and oil investing activities and other investing activities for 2008, 2007 and 2006.

We retain a significant degree of control over the timing of our capital expenditures which permits us to defer or accelerate certain capital expenditures if necessary to address any potential liquidity issues. In addition, higher drilling and field operating costs, drilling results that alter planned development schedules, acquisitions or other factors could cause us to revise our drilling program, which is largely discretionary.

We paid dividends on our common stock of $148 million, $115 million and $87 million in 2008, 2007 and 2006, respectively. The Board of Directors increased the quarterly dividend on common stock from $0.0675 to $0.075 per share beginning with the dividend paid in July 2008. Dividends paid on our preferred stock decreased to $35 million in 2008 from $95 million in 2007 and $88 million in 2006 as a result of conversions and exchanges of preferred stock into common stock during 2008 and 2007.

In 2008, holders of our 4.5% cumulative convertible preferred stock and our 5.0% (Series 2005B) cumulative preferred stock exchanged 891,100 shares and 3,654,385 shares for 2,227,750 shares and 10,443,642 shares of common stock, respectively, in privately negotiated exchanges. The exchanges resulted in a loss of $67 million. In 2007, holders of our 5.0% (Series 2005) cumulative convertible preferred stock and 6.25% mandatory convertible preferred stock exchanged 4,535,880 shares and 2,156,184 shares for 19,038,891 and 17,367,823 shares of common stock, respectively, in public exchange offers. The exchanges resulted in a loss $128 million.

We received $9 million, $15 million and $73 million from the exercise of employee and director stock options in 2008, 2007 and 2006, respectively. We paid $5 million, $0 and $86 million to purchase treasury stock in 2008, 2007 and 2006, respectively. Of these amounts, $5 million and $11 million were used to fund our matching contribution to our 401(k) and deferred compensation plans in 2008 and 2006, respectively. The remaining $75 million in 2006 was used to purchase shares of common stock to be used upon the exercise of stock options under certain stock option plans.

In 2008, 2007 and 2006, we paid $167 million, $91 million and $87 million, respectively, to settle a portion of the derivative liabilities assumed in our 2005 acquisition of Columbia Natural Resources, LLC.

SFAS 123(R) requires tax benefits resulting from stock-based compensation deductions in excess of amounts reported for financial reporting purposes to be reported as cash flows from financing activities. In 2008, 2007 and 2006, we reported a tax benefit from stock-based compensation of $43 million, $20 million and $88 million, respectively.

Outstanding payments from certain disbursement accounts in excess of funded cash balances where no legal right of set-off exists increased by $330 million, decreased by $98 million and increased by $70 million in 2008, 2007 and 2006, respectively. All disbursements are funded on the day they are presented to our bank using available cash on hand or draws on our revolving bank credit facility.

Credit Risk

A significant portion of our liquidity is concentrated in both cash and cash equivalents and derivative instruments. On December 31, 2008, our cash and cash equivalents were invested in money market funds with investment grade ratings. A significant portion of these funds was invested at the close of business on September 19, 2008, and is protected under the U.S. Treasury Department's Temporary Guarantee Program. The remaining funds were spread among several counterparties to mitigate risk.

Derivative instruments enable us to hedge a portion of our exposure to natural gas and oil prices and interest rate volatility. These arrangements expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers and spread our instruments among multiple counterparties such that no single counterparty represents a material credit risk to the company. Recently there have been concerns about the ability of certain counterparties to continue to meet their financial obligations. We monitor the creditworthiness of all our counterparties and do not believe a failure by a counterparty would have a material negative impact on our liquidity.

Our accounts receivable are primarily from purchasers of natural gas and oil ($738 million at December 31, 2008) and exploration and production companies which own interests in properties we operate ($424 million at December 31, . . .