Press Releases

OKLAHOMA CITY--(BUSINESS WIRE)--Nov. 2, 2009-- Chesapeake Energy Corporation (NYSE:CHK) today announced financial and operating results for the 2009 third quarter. For the quarter, Chesapeake reported net income to common shareholders of $186 million ($0.30 per fully diluted common share), operating cash flow of $1.118 billion (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $707 million (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $1.811 billion and production of 228 billion cubic feet of natural gas equivalent (bcfe).

The company’s 2009 third quarter results include a realized natural gas and oil hedging gain of $687 million. The results also 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 for the 2009 third quarter of $440 million ($0.70 per fully diluted common share) and adjusted ebitda of $1.133 billion. The excluded items and their effects on 2009 third quarter reported results are detailed as follows:

• a net unrealized noncash after-tax mark-to-market loss of $166 million resulting from the company’s natural gas, oil and interest rate hedging programs; and
• a combined after-tax charge of $88 million related primarily to the impairment of certain midstream assets contributed to the newly formed joint venture with Global Infrastructure Partners, a loss on the sale of certain gathering systems and a loss on exchanges of certain of the company’s contingent convertible senior notes for shares of common stock.

The various items described above do not materially 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 15 - 19 of this release.

Key Operational and Financial Statistics Summarized

The table below summarizes Chesapeake’s key results during the 2009 third quarter and compares them to results during the 2009 second quarter and the 2008 third quarter.

2009 Third Quarter Average Daily Production Increases 1% over 2009 Second Quarter Production and 7% over 2008 Third Quarter Production

As announced on October 29, 2009, the company’s daily production for the 2009 third quarter averaged 2.483 bcfe, an increase of 30 million cubic feet of natural gas equivalent (mmcfe), or 1%, over the 2.453 bcfe produced per day in the 2009 second quarter and an increase of 162 mmcfe, or 7%, over the 2.321 bcfe produced per day in the 2008 third quarter. Adjusted for the company’s 2009 voluntary production curtailments due to low natural gas prices and involuntary production curtailments due to pipeline repairs in the Fayetteville Shale (which together averaged approximately 45 mmcfe per day during the 2009 third quarter), the company’s 2009 and third and fourth quarter 2008 volumetric production payment transactions (which combined averaged approximately 125 mmcfe per day during the 2009 third quarter) and the estimated impact from various divestitures (which would have averaged approximately 105 mmcfe per day during the 2009 third quarter), Chesapeake’s sequential and year-over-year production growth rates would have been 2% and 14%, respectively, after making similar adjustments to prior quarters.

Chesapeake’s average daily production for the 2009 third quarter of 2.483 bcfe consisted of 2.286 billion cubic feet of natural gas (bcf) and 32,902 barrels of oil and natural gas liquids (bbls). The company’s 2009 third quarter production of 228.5 bcfe was comprised of 210.3 bcf (92% on a natural gas equivalent basis) and 3.0 million barrels of oil and natural gas liquids (mmbbls) (8% on a natural gas equivalent basis).

The company anticipates delivering full-year production growth of approximately 5-6% in 2009, 8-10% in 2010 and 12-14% in 2011.

Average Realized Prices, Hedging Results and Hedging Positions Detailed

Average prices realized during the 2009 third quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $6.04 per thousand cubic feet (mcf) and $66.42 per bbl, for a realized natural gas equivalent price of $6.44 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains from natural gas and oil hedging activities during the 2009 third quarter generated a $3.20 gain per mcf and a $3.95 gain per bbl for a 2009 third quarter realized hedging gain of $687 million, or $3.00 per mcfe. Without realized hedging gains, the company’s average realized prices for the 2009 third quarter would have been $2.84 per mcf and $62.47 per bbl, for a natural gas equivalent price of $3.44 per mcfe. Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2009 third quarter were a negative $0.55 per mcf and a negative $5.83 per bbl.

By comparison, average prices realized during the 2008 third quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $8.02 per mcf and $75.74 per bbl, for a realized natural gas equivalent price of $8.38 per mcfe. Realized losses from natural gas and oil hedging activities during the 2008 third quarter generated a $0.71 loss per mcf and a $37.79 loss per bbl for a 2008 third quarter realized hedging loss of $246 million, or $1.15 per mcfe. Without realized hedging losses, the company’s average realized prices for the 2008 third quarter would have been $8.73 per mcf and $113.53 per bbl, for a natural gas equivalent price of $9.54 per mcfe. Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2008 third quarter were a negative $1.52 per mcf and a negative $4.46 per bbl.

The following tables summarize Chesapeake’s open hedge position through swaps and collars as of November 2, 2009. Depending on changes in natural gas and oil futures markets and management’s view of underlying natural gas and oil supply and demand trends, Chesapeake may either increase or decrease its hedging positions at any time in the future without notice.

Note: Certain open natural gas swap positions include knockout swaps with knockout provisions at $6.00 per mcf covering 1 bcf for the remainder of 2009, or less than 1% of the company’s natural gas swap positions remaining in 2009, $5.45 to $6.75 per mcf covering 70 bcf in 2010, or approximately 55% of the company’s natural gas swap positions in 2010; and $5.75 to $6.50 per mcf covering 24 bcf in 2011, or virtually all of the company’s natural gas swap positions in 2011. 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 per mcf covering 11 bcf for the remainder of 2009 and ranging from $4.25 to $5.50 per mcf covering 26 bcf in 2010, or approximately 20% and 40% of the company’s natural gas collar positions remaining in 2009 and 2010, respectively. Also, certain open oil swap positions include knockout swaps with knockout provisions at prices ranging from $50 to $60 per bbl covering 1 mmbbls for the remainder of 2009 and $60 per bbl covering 5 mmbbls and 1 mmbbls in 2010 and 2011, respectively, or virtually all of the company’s oil swap positions remaining in 2009, 2010 and 2011.

As of October 30, 2009, Chesapeake’s natural gas and oil hedging positions with 14 different counterparties had a positive mark-to-market value of approximately $290 million. The company’s realized cash hedging gains for 2009 have been $1.8 billion and since January 1, 2001 have been $3.9 billion.

The company’s updated forecasts for 2009, 2010 and 2011 are attached to this release in an Outlook dated November 2, 2009, labeled as Schedule “A,” which begins on page 20. This Outlook has been changed from the Outlook dated October 13, 2009, attached as Schedule “B,” which begins on page 25, to reflect various updated information.

Chesapeake’s Proved Natural Gas and Oil Reserves Decrease by 0.5 Tcfe in the 2009 Third Quarter to 12.0 Tcfe Due to Natural Gas Price Decline; Company Delivers Drilling and Net Acquisition Costs of $0.78 per Mcfe for the First Three Quarters of 2009; Company Record Set for Organic Proved Reserve Additions over a Nine Month Period

Chesapeake began the 2009 third quarter with estimated proved reserves of 12.525 trillion cubic feet of natural gas equivalent (tcfe) and ended the 2009 third quarter with 11.994 tcfe, a decrease of 531 bcfe, or 4%. The quarter’s reserve movement included 228 bcfe of production, 664 bcfe of extensions, 325 bcfe of positive performance revisions, 1.191 tcfe of negative revisions resulting from natural gas price decreases between June 30, 2009 and September 30, 2009 and 101 bcfe of net divestitures.

Chesapeake’s total drilling and net acquisition costs for the 2009 third quarter were $0.34 per mcfe. This calculation excludes costs of $516 million for the acquisition of unproved properties and leasehold, $1.124 billion for the divestiture of unproved properties and leasehold, $151 million for capitalized interest on unproved properties, $22 million for geological and geophysical expenditures and asset retirement obligations, and also excludes downward revisions of proved reserves from lower natural gas prices. Excluding these items and proved reserve acquisition and divestiture activity, Chesapeake’s exploration and development costs through the drillbit during the 2009 third quarter were $0.64 per mcfe, giving effect to the benefit of $379 million in drilling carries associated with the Haynesville ($146 million), Fayetteville ($186 million) and Marcellus ($47 million) joint ventures. A complete reconciliation of 2009 third quarter proved reserves and finding and acquisition costs is presented on page 11 of this release.

During the first three quarters of 2009, Chesapeake's estimated proved reserves decreased 57 bcfe, or 0.5%, from 12.051 tcfe at year-end 2008. Year to date, Chesapeake has replaced 665 bcfe of production with an estimated 608 bcfe of new proved reserves for a reserve replacement rate of 91%. The reserve movement for the nine months included 1.455 tcfe of extensions, 1.503 tcfe of positive performance revisions, 2.164 tcfe of downward revisions resulting from a decrease in natural gas prices between December 31, 2008 and September 30, 2009 and 186 bcfe of net divestitures. Chesapeake’s 2.958 tcfe of extensions and performance revisions in the first three quarters of 2009 set a company record for the highest level of organic proved reserve additions over a nine-month period. Based on current strip natural gas pricing, the company expects to recover at year-end 2009 approximately half of the 2.164 tcfe of its proved reserves that have been revised downward during the first three quarters of 2009 as a result of the decline in natural gas prices and to recover by year-end 2010 all or substantially all of these price-related revisions.

Chesapeake’s total drilling and net acquisition costs for the first three quarters of 2009 were $0.78 per mcfe. This calculation excludes costs of $1.262 billion for the acquisition of unproved properties and leasehold, $1.124 billion for the divestiture of unproved properties and leasehold, $464 million for capitalized interest on unproved properties, $117 million for geological and geophysical expenditures and asset retirement obligations, and also excludes downward revisions of proved reserves from lower natural gas prices. Excluding these items and proved reserve acquisition and divestiture activity, Chesapeake’s exploration and development costs through the drillbit during the first three quarters of 2009 were $0.86 per mcfe, giving effect to the benefit of $959 million in drilling carries associated with the Haynesville ($350 million), Fayetteville ($524 million) and Marcellus ($85 million) joint ventures. A complete reconciliation of the first three quarters of 2009 proved reserves and finding and acquisition costs is presented on page 12 of this release.

Chesapeake continued the industry’s most active drilling program during the first three quarters of 2009, drilling 853 gross operated wells (624 net wells with an average working interest of 73%) and participating in another 864 gross wells operated by other companies (76 net wells with an average working interest of 9%). The company’s drilling success rate was 99% for company-operated wells and 98% for non-operated wells. During the first three quarters of 2009, Chesapeake invested $2.211 billion in operated wells (using an average of 102 operated rigs) and $330 million in non-operated wells (using an average of 57 non-operated rigs) for total drilling, completing and equipping costs of $2.541 billion (net of carries).

As of September 30, 2009, the present value of future net cash flows, discounted at 10% per year, of Chesapeake’s estimated proved reserves (PV-10) was $7.596 billion based on NYMEX quarter-end prices of $3.30 per mcf and $70.21 per bbl. Chesapeake’s PV-10 changes by approximately $400 million for every $0.10 per mcf change in natural gas prices and approximately $60 million for every $1.00 per bbl change in oil prices.

By comparison, the December 31, 2008 PV-10 of the company’s proved reserves was $15.601 billion ($11.833 billion applying the ASC 932 standardized measure) based on NYMEX year-end prices of $5.71 per mcf and $44.61 per bbl. The September 30, 2008 PV-10 of the company’s proved reserves was $24.404 billion based on NYMEX quarter-end prices of $7.12 per mcf and $100.66 per bbl.

The company calculates the standardized measure of future net cash flows in accordance with ASC 932 only at year end because applicable income tax information on properties, including recently acquired natural gas and oil interests, is not readily available at other times during the year. As a result, the company is not able to reconcile the interim period-end PV-10 values to the standardized measure at such dates. The only difference between the two measures is that PV-10 is calculated before considering the impact of future income tax expenses, while the standardized measure includes such effects.

In addition to the PV-10 value of its proved reserves and the very significant value of its undeveloped leasehold, particularly in the Haynesville, Marcellus, Barnett and Fayetteville Shale plays and in the Colony and Texas Panhandle Granite Wash plays, the net book value of the company’s other assets (including gathering systems, compressors, land and buildings, investments and other noncurrent assets) was $6.5 billion as of September 30, 2009, $5.8 billion as of December 31, 2008 and $4.9 billion as of September 30, 2008.

Conference Call Information

A conference call to discuss this release has been scheduled for Tuesday morning, November 3, 2009, at 9:00 a.m. EST. The telephone number to access the conference call is 913-227-1352 or toll-free 866-293-8969. The passcode for the call is 4137448. We encourage those who would like to participate in the call to dial the access number between 8:50 and 9:00 a.m. EST. For those unable to participate in the conference call, a replay will be available for audio playback from 1:00 p.m. EST on November 3, 2009 through midnight EST on November 17, 2009. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 4137448. 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 in the “Events” subsection of the “Investors” section of our website. 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 natural gas and oil reserves, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, planned capital expenditures and anticipated asset acquisitions and sales, as well as 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 under “Risk Factors” in our 2008 Form 10-K and 2009 second quarter Form 10-Q filed with the U.S. Securities and Exchange Commission on March 2, 2009 and August 10, 2009, respectively. These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; impacts the current economic downturn may have on our business and financial condition; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; 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 natural gas and oil reserves and projecting future rates of production and the amount and timing of development expenditures; exploration and development drilling that does not result in commercially productive reserves; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas and oil sales and the need to secure hedging liabilities; uncertainties in evaluating natural gas and oil reserves of acquired properties and potential liabilities; the negative impact lower natural gas and oil prices could have on our ability to borrow; drilling and operating risks, including potential environmental liabilities; transportation capacity constraints and interruptions that could adversely affect our cash flow; potential increased operating costs resulting from proposed legislative and regulatory changes affecting our operations; and adverse results in 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.

Chesapeake Energy Corporation is one of the leading producers of natural gas in the U.S. Headquartered in Oklahoma City, the company's operations are focused on the development of onshore unconventional and conventional natural gas in the U.S. in the Barnett Shale, Haynesville Shale, Fayetteville Shale, Marcellus Shale, Anadarko Basin, Arkoma Basin, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and East Texas regions of the United States. Further information is available at www.chk.com.

SCHEDULE “A”

CHESAPEAKE’S OUTLOOK AS OF NOVEMBER 2, 2009

Years Ending December 31, 2009, 2010 and 2011

Our policy is to periodically provide guidance on certain factors that affect our future financial performance. As of November 2, 2009, we are using the following key assumptions in our projections for 2009, 2010 and 2011.

The primary changes from our October 13, 2009 Outlook are in italicized bold and are explained as follows:

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

2) Our NYMEX natural gas and oil price assumptions for realized hedging effects and estimating future operating cash flow have been updated; and

3) Our cash flow projections have been updated.

At September 30, 2009, the company had $3.1 billion of cash and cash equivalents and additional borrowing capacity under its three revolving bank credit facilities.

Commodity Hedging Activities

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

All of our derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty.

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 natural gas and oil derivative transactions in order to mitigate a portion of its exposure to adverse market changes in natural gas and oil prices. Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to natural gas and oil sales. All realized gains and losses from natural gas and oil derivatives are included in natural gas and oil sales in the month of related production. Pursuant to ASC 815, 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 natural gas and oil sales. Following provisions of ASC 815, 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 natural gas and oil 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 trades:

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

The company currently has the following natural gas written call options in place: