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 months ended March 31, 2009 (the
"Current Quarter") and the three months ended March 31, 2008 (the "Prior
Quarter"):



                                                                   Three Months Ended
                                                                       March 31,
                                                                2009              2008
                                                                               (Adjusted)
Net Production:
Natural gas (mmcf)                                              195,749            187,772
Oil (mbbls)                                                       2,874              2,746
Natural gas equivalent (mmcfe)                                  212,993            204,248
Natural Gas and Oil Sales ($ in millions):
Natural gas sales                                             $     674       $      1,432
Natural gas derivatives - realized gains (losses)                   510                268
Natural gas derivatives - unrealized gains (losses)                  68             (1,002 )

Total natural gas sales                                           1,252                698

Oil sales                                                           104                258
Oil derivatives - realized gains (losses)                             9                (53 )
Oil derivatives - unrealized gains (losses)                          32               (130 )

Total oil sales                                                     145                 75

Total natural gas and oil sales                               $   1,397       $        773

Average Sales Price (excluding all gains (losses) on
derivatives):
Natural gas ($ per mcf)                                       $    3.44       $       7.63
Oil ($ per bbl)                                               $   35.99       $      94.14
Natural gas equivalent ($ per mcfe)                           $    3.65       $       8.28
Average Sales Price (excluding unrealized gains (losses)
on derivatives):
Natural gas ($ per mcf)                                       $    6.05       $       9.05
Oil ($ per bbl)                                               $   39.12       $      74.73
Natural gas equivalent ($ per mcfe)                           $    6.09       $       9.33
Other Operating Income(a) ($ in millions):
Natural gas and oil marketing                                 $      29       $         22
Service operations                                            $       6       $          7
Other Operating Income(a) ($ per mcfe):
Natural gas and oil marketing                                 $    0.14       $       0.11
Service operations                                            $    0.03       $       0.03
Expenses ($ per mcfe):
Production expenses                                           $    1.12       $       0.98
Production taxes                                              $    0.11       $       0.37
General and administrative expenses                           $    0.42       $       0.39
Natural gas and oil depreciation, depletion and
amortization                                                  $    2.10       $       2.52
Depreciation and amortization of other assets                 $    0.27       $       0.18
Interest expense(b)                                           $    0.14       $       0.42
Interest Expense ($ in millions):
Interest expense                                              $      38       $         86
Interest rate derivatives - realized (gains) losses                  (7 )                -
Interest rate derivatives - unrealized (gains) losses               (45 )               13

Total interest expense                                        $     (14 )     $         99

Net Wells Drilled                                                   264                448
Net Producing Wells as of the End of the Period                  22,691             21,471

(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 are the largest independent producer of natural gas in the United States. We own interests in approximately 43,200 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 the Current Quarter, Chesapeake continued the industry's most active drilling program drilling 307 gross (237 net) operated wells and participating in another 219 gross (27 net) wells operated by other companies. The company's drilling success rate was 98% for company-operated wells and 99% for non-operated wells. Also during the Current Quarter, we invested $1.020 billion in operated wells (using an average of 113 operated rigs) and $166 million in non-operated wells (using an average of 58 non-operated rigs) for total drilling, completing and equipping costs of $1.186 billion. At May 7, 2009, we were using 94 operated drilling rigs, reflecting the company's decreased drilling activity in response to low natural gas and oil prices.

On April 16, 2009, we announced that we had elected to curtail approximately 400 million cubic feet (mmcf) per day of our gross operated natural gas production due to continued low wellhead prices. The reduction included the approximate 200 mmcf per day curtailment of natural gas production previously announced on March 2, 2009. Prices remain very volatile, and we will restore production from time to time, or curtail production further, based on market conditions. Our strong financial condition, the availability of substantial drilling credits as a result of the 2008 joint ventures, and our extensive natural gas hedging positions provide us with the operational and financial flexibility to curtail production during periods of unusually low prices. The company will monitor market conditions to determine an appropriate time to resume full production.

Chesapeake began 2009 with estimated proved reserves of 12.051 tcfe and ended the Current Quarter with 11.851 tcfe, a decrease of 200 bcfe, or 2%. During the Current Quarter, we replaced 213 bcfe of production with an internally estimated 13 bcfe of new proved reserves, for a reserve replacement rate of 6%. The quarter's reserve movement includes 427 bcfe of extensions, 9 bcfe of acquisitions, 397 bcfe of positive performance revisions and 820 bcfe of downward revisions resulting from natural gas price decreases between December 31, 2008 and March 31, 2009. Based on our current drilling schedule and budget, we expect that virtually all of the proved undeveloped reserves added in 2009 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 proceeds from divestitures) and 3-D seismic acquisitions and now owns the largest combined inventories of onshore leasehold (15.2 million net acres) and 3-D seismic (22.3 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.

Our total debt as a percentage of total capitalization (total capitalization is the sum of total debt less cash on hand and stockholders' equity) was 52% as of March 31, 2009 and 40% as of December 31, 2008. The increase in this percentage is primarily the result of the reduction of equity as the result of the Current Quarter $5.7 billion net loss. The average maturity of our long-term debt is over seven years with an average coupon interest rate of approximately 6.1%. No scheduled principal payments are required under our senior notes until 2013 when $864 million is due.

Business Strategy

Our exploration, development and acquisition activities require us to make substantial 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 primarily in the Haynesville, Barnett and Marcellus Shale plays. During the second half of 2008 and again in 2009, in response to a significant decrease in natural gas prices, deteriorating global economic conditions and outlook and concerns about an oversupply of natural gas in the U.S. market, and in recognition of the substantial reduction in capital requirements resulting from our joint ventures with Plains Exploration & Production Company (PXP), BP America (BP) and StatoilHydro U.S.A. (StatoilHydro), we significantly reduced our planned capital expenditures through year-end 2010. We further believe our innovative joint ventures will create a significant cost advantage that will allow us to drive down finding costs in our joint venture plays. Our current budgeted capital expenditures are $4.350 billion to $4.975 billion in 2009 and $4.050 billion to $4.675 billion in 2010. We anticipate directing approximately 80% of our gross drilling capital expenditures during 2009 and 2010 to our Big 4 shale plays.

During each of 2009 and 2010, we anticipate our exploration and development costs will be up to 40% lower than 2008 costs as a result of lower service costs and the benefit of using approximately $2.4 billion of joint venture drilling credits in three of our Big 4 shale plays. The following table provides information about the joint venture drilling credits:

                                                                         Shale Play
                                                 Haynesville(a)             Fayetteville            Marcellus
                                                                       ($ in millions)
Joint venture with                                      PXP                       BP               StatoilHydro
Closing date                                       July 1, 2008           September 19, 2008     November 24, 2008
Cash proceeds at closing                   $                    1,650   $              1,100   $             1,250
Total drilling credit                      $                    1,650   $                800   $             2,125
Drilling credit billed as of March 31,
2009                                       $                      158   $                371   $                11
Remaining drilling credit as of March
31, 2009                                   $                    1,492   $                429   $             2,114

(a) Chesapeake and PXP amended their joint venture in February 2009 to provide PXP 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 PXP's interest in the Haynesville joint venture properties.

Cash flow from operations is our primary source of liquidity used to fund capital expenditures. Our $3.5 billion revolving bank credit facility and our $460 million midstream revolving bank credit facility provide us with additional liquidity. In February 2009, we issued $1.425 billion principal amount of our 9.5% senior notes due 2015. Net proceeds of $1.346 billion were used to repay outstanding indebtedness under our revolving bank credit facility, which we may reborrow from time to time to fund drilling and leasehold acquisition initiatives and for general corporate purposes. At March 31, 2009, we had borrowings of $2.225 billion and letters of credit of $7 million outstanding under our revolving bank credit facility and we had borrowings of $164 million under the midstream credit facility.

During 2009 and 2010, we plan to increase our liquidity, reduce our borrowings under our revolving bank credit facility and also strengthen our balance sheet through asset monetizations and the growth of our proved reserve base. Transactions we expect to complete in 2009 include the following:

• We are currently documenting our fifth volumetric production payment transaction (VPP) involving certain of our South Texas assets. We anticipate proceeds of approximately $475 million and expect to complete the transaction in the 2009 second quarter.

• We plan to sell certain non-Haynesville Shale producing assets in Louisiana in a sixth VPP in the second half of 2009 for approximately $250 million.

• We are in due diligence with a private equity investor to sell a 50% minority interest in our Barnett Shale and Mid-Continent natural gas gathering and processing assets in our midstream business, Chesapeake Midstream Partners. We anticipate proceeds of more than $550 million and expect to complete the transaction in the 2009 third quarter

• We anticipate selling approximately $300 million of mature producing assets late in the 2009 second quarter and another $200 million in the second half of 2009.

• We are currently in discussions with several companies about a possible Barnett Shale joint venture transaction and anticipate completing a transaction by year-end 2009 for proceeds of approximately $200 million to $300 million.

We believe that our anticipated internally generated cash flow, cash resources, expected asset monetization transactions and other sources of liquidity will allow us to fully fund our capital expenditure requirements in 2009. Further deterioration of the economy, continued low natural gas and oil prices and other factors, however, could require us to 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 capital expenditures. Our joint venture drilling credits also provide an additional source of liquidity that have reduced and will continue to reduce our capital expenditures. Cash provided by operating activities was $1.261 billion in the Current Quarter compared to $1.515 billion in the Prior Quarter. The $254 million decrease in the Current Quarter was primarily due to lower natural gas and oil prices. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding non-cash items such as ceiling test write-downs, 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 and oil prices and to provide more predictable future cash flow from operations, we currently have hedged through swaps and collars 82% of our expected remaining natural gas and oil production in 2009 and 24% of our expected natural gas and oil production in 2010 at average prices of $7.56 per mcfe and $9.45 per mcfe, respectively. Our natural gas and oil hedges as of March 31, 2009 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 March 31, 2009, we had a net natural gas and oil derivative asset of $1.481 billion.

Our $3.5 billion bank credit facility, our $460 million midstream credit facility and cash and cash equivalents are other sources of liquidity. At May 7, 2009, there was $1.268 billion of borrowing capacity available under the revolving bank credit facility and $220 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 $1.575 billion and repaid $3.120 billion in the Current Quarter, and we borrowed $2.591 billion and repaid $1.377 billion in the Prior Quarter.

On February 2, 2009, we completed a public offering of $1.0 billion aggregate principal amount of senior notes due 2015, which have a stated coupon rate of 9.5% per annum. The senior notes were priced at 95.071% of par to yield 10.625%. On February 17, 2009, we completed an offering of an additional $425 million aggregate principal amount of the 9.5% Senior Notes due 2015. The additional senior notes were priced at 97.75% of par plus accrued interest from February 2 to February 17, 2009 to yield 10.0% per annum. Net proceeds of $1.346 billion from these two offerings were used to repay outstanding indebtedness under our revolving bank credit facility, which we may reborrow from time to time to fund drilling and leasehold acquisition initiatives and for general corporate purposes.

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 our other investing activities for the Current Quarter and the Prior Quarter. 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, changes in 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 $44 million and $33 million in the Current Quarter and the Prior Quarter, 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 $6 million in the Current Quarter from $12 million in the Prior Quarter as a result of conversions and exchanges of preferred stock into common stock during 2008 and 2009. We received $1 million and $4 million from the exercise of employee and director stock options in the Current Quarter and the Prior Quarter.

In the Current Quarter and Prior Quarter, we received $1 million and paid $33 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 Quarter and the Prior Quarter, we reported a tax benefit from stock-based compensation of $0 and $11 million, respectively.

Outstanding payments from certain disbursement accounts in excess of funded cash balances where no legal right of set-off exists decreased $287 million in the Current Quarter and increased $44 million in the Prior Quarter. 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 derivative instruments that 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.

Our accounts receivable are primarily from purchasers of natural gas and oil ($475 million at March 31, 2009) and exploration and production companies which own interests in properties we operate ($476 million at March 31, 2009). 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. During the Current Quarter, we recognized an $8 million bad debt expense related to potentially uncollectible receivables.

Investing Activities

Cash used in investing activities decreased to $2.367 billion during the Current Quarter, compared to $2.692 billion during the Prior Quarter. We have been reducing our drilling program since the third quarter of 2008 and our leasehold and property acquisitions expenditures in the Current Quarter were 72% lower than in the Prior Quarter. The following table shows our cash used in (provided by) investing activities during these periods:

                                                                   Three Months Ended
                                                                       March 31,
                                                                   2009           2008
                                                                    ($ in millions)
Natural Gas and Oil Investing Activities:
Exploration and development of natural gas and oil
properties                                                      $    1,272       $ 1,322
Acquisition of leasehold and unproved properties                       257           860
Acquisitions of natural gas and oil companies and proved
properties, net of cash acquired                                         3            64
Geological and geophysical costs                                        74            84
Interest capitalized on unproved properties                            154            97
Divestitures of proved and unproved properties and leasehold             -          (243 )

Total natural gas and oil investing activities                       1,760         2,184

Other Investing Activities:
Additions to other property and equipment                              667           551
Proceeds from sale of compressors                                      (68 )         (17 )
Proceeds from sale of drilling rigs and equipment                        -           (34 )
Additions to investments                                                 8             9
Sale of other assets                                                     -            (1 )

Total other investing activities                                       607           508

Total cash used in investing activities                         $    2,367       $ 2,692

Due to current general economic conditions, decreases in natural gas prices and concerns about an oversupply of natural gas in the U.S. market, we and other exploration and production companies have significantly decreased budgets for natural gas and oil investing activities in 2009. In connection with our reduced budget for acquisitions, we are using our common stock for some or all of the consideration for certain transactions. In December 2008, we registered 25 million shares of common stock that we may offer and issue to acquire assets (including mineral interests), businesses or securities of other companies. As of May 8, 2009, we had issued approximately 17.5 million shares of common stock for leasehold acquisitions and anticipate we may issue the remaining shares over the course of 2009.

Bank Credit Facilities

We have a $3.5 billion syndicated revolving bank credit facility that matures in November 2012. As of March 31, 2009, we had $2.225 billion in outstanding borrowings under this facility and had utilized approximately $7 million of the facility for various letters of credit. The terms of the credit facility agreement summarized below reflect amendments effected on March 31, 2009.

Borrowings under the facility are secured by certain producing natural gas and oil properties and bear interest at our option at either (i) the greater of the reference rate of Union Bank of California, N.A., or the federal funds effective rate plus 0.50%, both of which are subject to a margin that varies from 0.00% to 0.75% (0.00% prior to the March 31, 2009 amendment) per annum according to our senior unsecured long-term debt ratings, or (ii) the London Interbank Offered Rate (LIBOR), plus a margin that varies from 1.50% to 2.25% (0.75% to 1.50% prior to the March 31, 2009 amendment) per annum according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are redetermined periodically. The unused portion of the facility is subject to a commitment fee of 0.50% (which varied according to our senior unsecured long-term debt ratings, from 0.125% to 0.30% per annum, prior to the March 31, 2009 amendment). Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit facility agreement requires us to maintain an indebtedness to total capitalization ratio (as defined) not to exceed 0.70 to 1 and an indebtedness to EBITDA ratio (as defined) not to exceed 3.75 to 1. Pursuant to the March 31, 2009 amendment of the credit facility, the effects of ceiling test write-downs are excluded from the calculation of total capitalization for purposes of the consolidated indebtedness to total capitalization ratio. As defined by the credit facility agreement, our indebtedness to total capitalization ratio was 0.42 to 1 and our indebtedness to EBITDA ratio was 2.91 to 1 at March 31, 2009. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million ($50 million in the case of our senior notes issued after 2004), would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of a significant portion of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness of the company and its restricted subsidiaries that we may have with an outstanding principal amount in excess of $75 million.

We also have a secured revolving bank credit facility for our midstream operations, organized under an unrestricted subsidiary, Chesapeake Midstream Partners, L.P. (CMP) and its operating subsidiary, Chesapeake Midstream Operating, L.L.C. (CMO). The facility matures in October 2013, has initial . . .