Overview

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 three and nine months ended September 30,
2008 (the "Current Quarter" and the "Current Period") and the three and nine
months ended September 30, 2007 (the "Prior Quarter" and the "Prior Period"):



                                                    Three Months Ended            Nine Months Ended
                                                      September 30,                 September 30,
                                                   2008           2007           2008           2007
Net Production:
Natural gas (mmcf)                                 196,657        170,325        579,423        467,197
Oil (mbbls)                                          2,810          2,680          8,372          7,147
Natural gas equivalent (mmcfe)                     213,517        186,405        629,655        510,079
Natural Gas and Oil Sales ($ in millions):
Natural gas sales                                $   1,717      $     971      $   5,046      $   2,918
Natural gas derivatives - realized gains
(losses)                                              (140 )          290           (174 )          890
Natural gas derivatives - unrealized gains
(losses)                                             3,854             73            325            (58 )

Total natural gas sales                              5,431          1,334          5,197          3,750

Oil sales                                              319            190            915            443
Oil derivatives - realized gains (losses)             (106 )           (4 )         (280 )           26
Oil derivatives - unrealized gains (losses)            764            (28 )         (245 )          (55 )

Total oil sales                                        977            158            390            414

Total natural gas and oil sales                  $   6,408      $   1,492      $   5,587      $   4,164

Average Sales Price (excluding all gains
(losses) on derivatives):
Natural gas ($ per mcf)                          $    8.73      $    5.71      $    8.71      $    6.25
Oil ($ per bbl)                                  $  113.53      $   70.76      $  109.28      $   61.91
Natural gas equivalent ($ per mcfe)              $    9.54      $    6.23      $    9.47      $    6.59
Average Sales Price (excluding unrealized
gains (losses) on derivatives):
Natural gas ($ per mcf)                          $    8.02      $    7.41      $    8.41      $    8.15
Oil ($ per bbl)                                  $   75.74      $   69.25      $   75.82      $   65.55
Natural gas equivalent ($ per mcfe)              $    8.38      $    7.76      $    8.75      $    8.39
Other Operating Income(a) ($ in millions):
Natural gas and oil marketing                    $      24      $      18      $      70      $      52
Service operations                               $       8      $      11      $      23      $      34
Other Operating Income ($per mcfe):
Natural gas and oil marketing                    $    0.11      $    0.10      $    0.11      $    0.10
Service operations                               $    0.04      $    0.06      $    0.04      $    0.07
Expenses ($ per mcfe):
Production expenses                              $    1.12      $    0.89      $    1.04      $    0.90
Production taxes                                 $    0.41      $    0.30      $    0.40      $    0.30
General and administrative expenses              $    0.50      $    0.33      $    0.46      $    0.33
Natural gas and oil depreciation, depletion
and amortization                                 $    2.25      $    2.57      $    2.41      $    2.58
Depreciation and amortization of other assets    $    0.23      $    0.24      $    0.20      $    0.24
Interest expense(b)                              $    0.26      $    0.52      $    0.35      $    0.52
Interest Expense ($ in millions):
Interest expense                                 $      51      $      98      $     220      $     266
Interest rate derivatives - realized (gains)
losses                                                   5             (1 )            1              -
Interest rate derivatives - unrealized
(gains) losses                                          (8 )           19             (9 )           13

Total interest expense                           $      48      $     116      $     212      $     279

Net Wells Drilled                                      455            529          1,388          1,480
Net Producing Wells as of the End of the
Period                                              22,475         20,932         22,475         20,932

(a) Includes revenue and operating costs.

(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 are the largest producer of natural gas in the United States. We own interests in approximately 40,500 producing natural gas and oil 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..

Our most important operating area has historically been the Mid-Continent region of Oklahoma, Arkansas, southwestern Kansas and the Texas Panhandle. At September 30, 2008, 46% of our estimated proved natural gas and oil reserves were located in the Mid-Continent region. However, during the past five years, we have established a top-two position in the four major unconventional plays onshore in the U.S., including the Barnett Shale in the Fort Worth Basin in north-central Texas; the Haynesville Shale in the Ark-La-Tex area of East Texas and northern Louisiana; the Fayetteville Shale in the Arkoma Basin of Arkansas; and the Marcellus and Lower Huron Shales in the Appalachian Basin of Kentucky, West Virginia, Pennsylvania and New York. In addition, we are pursuing other unconventional plays in the Anadarko Basin of western Oklahoma, the Ardmore Basin of southern Oklahoma, the Arkoma Basin of eastern Oklahoma and the Permian and Delaware Basins of West Texas and eastern New Mexico.

During the Current Period, Chesapeake continued the industry's most active drilling program and drilled 1,435 gross (1,193 net) operated wells and participated in another 1,439 gross (195 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 Current Period, we invested $3.852 billion in operated wells (using an average of 148 operated rigs) and $576 million in non-operated wells (using an average of 118 non-operated rigs) for total drilling, completing and equipping costs of $4.428 billion.

Chesapeake began 2008 with estimated proved reserves of 10.879 tcfe and ended the Current Period with 12.075 tcfe, an increase of 1.196 tcfe, or 11%. During the Current Period, we replaced 630 bcfe of production with an internally estimated 1.826 tcfe of new proved reserves, for a reserve replacement rate of 290%. Reserve replacement through the drillbit was 2.286 tcfe, or 363% of production, including 1.128 tcfe of positive performance revisions and 13 bcfe of positive revisions resulting from natural gas and oil price increases between December 31, 2007 and September 30, 2008. Reserve replacement through the acquisition of proved reserves was 165 bcfe. During the Current Period, we divested 638 bcfe of estimated proved reserves. 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 $13.3 billion in new leasehold (net of divestitures) and 3-D seismic acquisitions and now owns the largest combined inventories of onshore leasehold (15.6 million net acres) and 3-D seismic (21.1 million acres) in the U.S. On this leasehold, the company has approximately 37,000 net drillsites representing more than a 10-year inventory of drilling projects.

Our net debt as a percentage of total capitalization (total capitalization is the sum of net debt and stockholders' equity) was 43% as of September 30, 2008 and 47% as of December 31, 2007. The average maturity of our long-term debt is over eight years with an average interest rate of approximately 5.4%. No scheduled principal payments are required under our senior notes until 2013 when $864 million is due.

Business Strategy

In response to a decrease in natural gas prices since June 30, 2008, the current global economic outlook and concerns about a potential over supply of natural gas in the U.S. market, we have reduced our planned capital expenditures during the second half of 2008 through year-end 2010. 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 $2.4 billion to $2.8 billion in the fourth quarter of 2008 and $7.0 billion to $8.3 billion in 2009. We will continue to evaluate market conditions and natural gas prices and further reduce our capital expenditures if necessary.

We anticipate that our remaining 2008 and 2009 budgeted exploration and development capital expenditures, together with other capital expenditure requirements, will exceed our cash flow from operations and our borrowing capacity under our revolving credit facilities. To create additional value from our proved and unproved properties, to provide for our anticipated cash requirements and to generate excess cash to increase our financial flexibility, we expect to continue to engage in asset monetization transactions, including sales of producing properties, undeveloped acreage and non-strategic assets, additional joint venture arrangements and the sale of volumetric production payments, and we may consider alternative sources of public or private investment in the company or its subsidiaries. Our current budgeted cash inflows for these types of transactions are $2.5 billion to $3.0 billion in the fourth quarter of 2008 and $2.3 billion to $3.3 billion in 2009. While we believe that some or all of these sources of liquidity will be available to us, as they have been in 2008 to date, we will further curtail our capital spending if we are unable to access sufficient cash to fund our presently planned levels of capital spending and operations.

Since March 31, 2008, as detailed below, we have completed significant transactions that have provided approximately $10.4 billion of new capital. In each case, we used the proceeds to temporarily repay outstanding indebtedness under our revolving bank credit facility, which we have reborrowed to fund capital expenditures, and for other general corporate purposes, including the redemption of our 7.75% Senior Notes due 2015 ($300 million principal amount). In addition, up to $2.45 billion of our future drilling and completion costs in the Haynesville Shale and Fayetteville Shale will be funded by our joint venture partners.

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 our 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. We received aggregate net proceeds of approximately $4.734 billion from these four offerings. The availability of any additional capital from the public or private markets is uncertain at this time.

On May 1, 2008, we completed a volumetric production payment (VPP) transaction involving approximately 94 bcfe of estimated proved reserves and current net production (at the time of sale) of approximately 47 mmcfe per day from wells in Texas, Oklahoma and Kansas. This transaction resulted in net proceeds to us of $616 million. On August 1, 2008, we completed another VPP transaction with estimated proved reserves of approximately 93 bcfe and current net production (at the time of sale) of approximately 46 mmcfe per day from wells in the Anadarko Basin in Oklahoma. This transaction resulted in net proceeds to us of $594 million. This was our third VPP transaction and we expect to raise additional capital by this means in the fourth quarter of 2008 and in 2009.

On July 1, 2008, we entered into a joint venture with Plains Exploration & Production Company to develop our Haynesville Shale leasehold in Northwest Louisiana and East Texas. Under the terms of the joint venture, Plains acquired a 20% interest in our approximately 550,000 net acres of Haynesville Shale leasehold for $1.65 billion in cash, subject to customary post-closing adjustments. Plains has also 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. In addition, Plains will have the right to a 20% participation in any additional leasehold we acquire in the Haynesville Shale.

On September 5, 2008, we entered into a joint venture with BP America Inc. to develop our Fayetteville Shale leasehold in Arkansas. Under the terms of the joint venture, BP acquired a 25% interest in our approximately 540,000 net acres of Fayetteville Shale leasehold for $1.1 billion in cash paid at closing. BP will pay an additional $800 million by funding 100% of Chesapeake's 75% share of drilling and completion expenditures until the $800 million obligation has been funded. In addition, BP has the right to a 25% participation in any additional leasehold we acquire in the Fayetteville Shale.

We are presently in joint venture negotiations for our Marcellus Shale play on a promoted basis as well. These joint ventures allow us to generate profits from the sale of a portion of our leasehold in the joint venture areas, recover much or all of our initial leasehold investments in these plays, reduce our ongoing capital costs and minimize future risks.

On August 8, 2008, BP America Inc. acquired all of our interests in approximately 90,000 net acres of leasehold and producing natural gas properties in the Arkoma Basin Woodford Shale play for $1.7 billion in cash. The properties, which are located in Atoka, Coal, Hughes and Pittsburg counties, Oklahoma, were producing approximately 50 mmcfe per day at the time of sale.

We have resumed plans to sell either a minority interest in our non-Appalachian midstream natural gas business or specific midstream assets. Proceeds from any sale will be used to fund a portion of the costs associated with building the midstream infrastructure in various shale plays, primarily in the Haynesville Shale. On October 16, 2008, we closed a new secured revolving bank credit facility for the midstream operations. The facility matures in October 2013 and has initial availability of $460 million.

Management believes that our planned leasehold and development joint ventures and various asset monetization programs benefit the company in several ways. We will be able to improve our asset base, reduce our financial risk, decrease our DD&A rate and increase our profitability per unit of production, thereby increasing our returns on capital and advancing future value creation.

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 $4.305 billion in the Current Period compared to $3.389 billion in the Prior Period. The $916 million increase in the Current Period was primarily due to higher natural gas and oil prices and 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. While a decline in natural gas or oil prices would affect the amount of cash flow that would be generated from operations, we currently have hedged through swaps and collars 73% of our expected remaining natural gas and oil production in 2008 and 67% of our expected natural gas and oil production in 2009 at average prices of $9.09 and $8.65 per mcfe, respectively. Our natural gas and oil hedges as of September 30, 2008 are detailed in Item 3 of Part I 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 September 30, 2008, we had a net natural gas and oil derivative asset of $46 million. We satisfy commodity derivative liabilities from a portion of the proceeds of natural gas and oil production sold at market prices during the period of contract settlement (which will occur through 2022). 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 and cash and cash equivalents are other sources of liquidity. At November 6, 2008, there was no borrowing capacity available under the revolving bank credit facility; however, we had approximately $800 million of cash on hand and $378 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 $12.831 billion and repaid $11.307 billion in the Current Period, and we borrowed $5.949 billion and repaid $4.177 billion in the Prior Period.

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 $4.734 billion, which we used to fund the redemption of our 7.75% Senior Notes due 2015 and to temporarily repay indebtedness outstanding under our revolving bank credit facility. The following table reflects the proceeds from sales of securities we issued in the Current Period and the Prior Period ($ in millions):

                                                        For the Nine Months Ended September 30,
                                                      2008                                    2007
                                        Total Proceeds       Net Proceeds       Total Proceeds      Net Proceeds
Common stock                           $          2,698     $        2,598     $              -     $           -
Contingent convertible unsecured
senior notes                                      1,380              1,349                1,650             1,607
Unsecured senior notes guaranteed
by subsidiaries                                     800                787                    -                 -

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

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.

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 for the Current Period and the Prior Period. 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 $106 million and $85 million in the Current Period and the Prior Period, 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 $29 million in the Current Period from $78 million in the Prior Period as a result of conversions and exchanges of preferred stock into common stock during the Current Period and 2007. We received $8 million from the exercise of employee and director stock options in both the Current Period and the Prior Period.

In the Current Period and Prior Period, we paid $146 million and $65 million, respectively, to settle a portion of the derivative liabilities assumed in our November 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 the Current Period and the Prior Period, we reported a tax benefit from stock-based compensation of $42 million and $13 million, respectively.

Outstanding payments from certain disbursement accounts in excess of funded cash balances where no legal right of set-off exists increased $210 million in the Current Period and decreased $54 million in the Prior Period. 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 September 30, 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 the 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 credit worthiness 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 ($865 million at September 30, 2008) and exploration and production companies which own interests in properties we operate ($320 million at September 30, 2008). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parental guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.

Investing Activities

Cash used in investing activities increased to $8.201 billion during the Current Period, compared to $6.488 billion during the Prior Period. We have continued our active drilling program and our acquisitions are focused on leasehold and property acquisitions needed for planned natural gas and oil development. Our investing activities during the Current Period and the Prior Period reflect our increasing focus on converting our resource inventory into production, redeploying our capital by selling natural gas and oil properties with lower rates of return and increasing our investment in properties with higher return potential, and investing in drilling rigs, midstream systems, compressors and other property and equipment to support our natural gas and oil exploration, development and production activities. We have significantly decreased our budget for natural gas and oil investing activities in 2009. The following table shows our cash used in (provided by) investing activities during these periods:

                                                                    Nine Months Ended
                                                                      September 30,
                                                                    2008           2007
                                                                     ($ in millions)
Natural Gas and Oil Investing Activities:
Exploration and development of natural gas and oil
properties                                                       $    4,407       $ 3,525
Acquisition of leasehold and unproved properties                      6,932         1,703
Acquisitions of natural gas and oil companies and proved
properties, net of cash acquired                                        368           446
Geological and geophysical costs                                        234           245
Interest on leasehold and unproved properties                           289           182
Proceeds from sale of volumetric production payment                  (1,210 )           -
Divestitures of proved and unproved properties and leasehold         (4,666 )           -

Total natural gas and oil investing activities                        6,354         6,101

Other Investing Activities:
Additions to other property and equipment                             1,969         1,005
Proceeds from sale of drilling rigs and equipment                       (46 )        (322 )
Proceeds from sale of compressors                                      (114 )        (147 )
Additions to (proceeds from) investments                                 59          (117 )
Sale of other assets                                                    (21 )         (32 )
. . .