Chesapeake Energy Corporation Provides Operational Update
Company Reports 2009 Third Quarter Production of 2.483 Bcfe per Day, an Increase of 1% over 2009 Second Quarter Production and 7% over 2008 Third Quarter Production Company Anticipates Reporting 2009 Nine Month Drilling and Net Acquisition Costs of Less than $0.80 per Mcfe

OKLAHOMA CITY--(BUSINESS WIRE)--Oct. 29, 2009-- Chesapeake Energy Corporation (NYSE:CHK) today provided an update on its operational activities. For the 2009 third quarter, daily production averaged 2.483 billion cubic feet of natural gas equivalent (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 voluntary production curtailments due to low natural gas prices and involuntary production curtailments due to pipeline repairs (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, net of property divestitures.

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 Anticipates Reporting Drilling and Net Acquisition Costs of Less than $0.80 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 includes 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.

During the first three quarters of 2009, Chesapeake’s estimated proved reserves decreased by 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 year to date includes 1.455 tcfe of extensions, 1.503 tcfe of positive performance revisions, 2.164 tcfe of downward revisions resulting from natural gas price decreases 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 NYMEX natural gas strip pricing, the company expects to recover a significant portion 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.

Chesapeake anticipates reporting total drilling and net acquisition costs of less than $0.80 per thousand cubic feet of natural gas equivalent (mcfe) for the first three quarters of 2009. This estimate excludes costs for the acquisition of unproved properties and leasehold, proceeds from the sale of unproved properties and leasehold, capitalized interest on unproved properties, geologic and geophysical costs and costs relating to asset retirement obligations, and also excludes negative revisions of proved reserves from lower natural gas prices. The estimate includes 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 2009 proved reserve changes and year-to-date finding and net acquisition costs will be included in the company’s November 2, 2009 release of financial and operational results for the 2009 third quarter.

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. Also during the first three quarters of 2009, Chesapeake used an average of 102 operated rigs and an average of 57 non-operated rigs.

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, using field differential adjusted prices based on NYMEX quarter-end prices of $3.30 per thousand cubic feet (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 SFAS 69 standardized measure) using field differential adjusted prices 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 using field differential adjusted prices based on NYMEX quarter-end prices of $7.12 per mcf and $100.66 per bbl.

Chesapeake’s Leasehold and 3-D Seismic Inventories Total 14.1 Million Net Acres and 23.3 Million Acres; Risked Unproved Reserves in the Company’s Inventory Total 62 Tcfe and Unrisked Unproved Reserves Total 172 Tcfe

Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (14.1 million net acres) and 3-D seismic (23.3 million acres) in the U.S. and the largest inventory of U.S. Big 4 shale play leasehold (2.8 million net acres). On its leasehold at September 30, 2009, Chesapeake had identified an estimated 12 tcfe of proved reserves, 62 tcfe of risked unproved reserves and 172 tcfe of unrisked unproved reserves. The company is currently using 105 operated drilling rigs to further develop its inventory of approximately 35,500 net drillsites, which represents more than a 10-year inventory of drilling projects.

The following table summarizes Chesapeake’s ownership and activity in its Big 4 shale plays, its two primary Anadarko Basin Granite Wash plays and its other plays. Chesapeake uses a probability-weighted statistical approach to estimate the potential number of drillsites and unproved reserves associated with such drillsites.

Play Type/Area

 

CHK

Net

Acreage

 

Est.

Drilling

Density

(Acres)

  Risk

Factor

 

Risked

Net

Undrilled

Wells

 

Est. Avg.

Reserves

Per Well

(bcfe)

 

Proved

Reserves

(bcfe)

 

Risked

Unproved

Reserves

(bcfe)

 

Unrisked

Unproved

Reserves

(bcfe)

 

Est.

IRR at

$7 Gas/

$70 Oil

 

Current (1)

Daily

Production

(mmcfe)

 

Current (2)

Operated

Rig Count

Big 4 Shale Plays:

                                           
Haynesville Shale   510,000   80   40%   3,700   6.50   1,059   17,400   29,400   55%   330   35
Marcellus Shale   1,520,000   80   75%   4,750   4.20   201   16,900   67,700   66%   50   20
Barnett Shale   305,000   60   15%   2,600   2.65   2,806   4,900   6,300   36%   685   17
Fayetteville Shale   445,000   80   20%   4,100   2.40   1,167   7,800   9,800   31%   260   16
Subtotal   2,780,000           15,150       5,233   47,000   113,200       1,325   88
                                             
Colony Granite Wash   60,000   160   15%   250   5.70   337   1,000   1,200   141%   110   5
Texas Panhandle

Granite Wash

  40,000   80   25%   165   4.75   439   400   600   128%   75   2
Other   11,220,000   Various   Various   19,850   Various   5,985   13,400   57,200   Various   1,045   10
                                             
Total   14,100,000           35,500       11,994   61,800   172,200   Various   2,555   105

(1) Estimated October 2009 average

(2) As of October 30, 2009

Haynesville Shale (Northwest Louisiana, East Texas): Chesapeake is the largest leasehold owner and most active driller of new wells in the Haynesville Shale play in Northwest Louisiana and East Texas. Chesapeake now owns approximately 510,000 net acres of leasehold in the Haynesville Shale play. Chesapeake also has approximately 175,000 net acres of leasehold it believes is prospective for the Bossier Shale, which is not yet included in its unproved reserve estimates above. Chesapeake and its 20% joint venture partner, Plains Exploration & Production Company (NYSE:PXP) (which owns approximately 110,000 additional net acres), have drilled and completed 137 Chesapeake-operated horizontal wells in the Haynesville play and continue to experience outstanding drilling results. During the 2009 third quarter, Chesapeake’s average daily net production of 229 mmcfe in the Haynesville increased approximately 67% over the 2009 second quarter and approximately 573% over the 2008 third quarter. Chesapeake is currently producing a company record monthly average of approximately 330 mmcfe net per day (450 mmcfe gross operated) from the Haynesville and anticipates exceeding approximately 370 mmcfe net per day (500 mmcfe gross operated) by year-end 2009, approximately 500 mmcfe net per day (670 mmcfe gross operated) by year-end 2010 and approximately 690 mmcfe net per day (930 mmcfe gross operated) by year-end 2011. To further develop its 510,000 net acres of Haynesville leasehold, Chesapeake is currently drilling with 35 operated rigs and anticipates operating an average of approximately 40 rigs in 2010 to drill approximately 190 net wells. During the first three quarters of 2009, approximately $350 million of Chesapeake’s drilling costs in the Haynesville were paid for by its joint venture partner PXP. In August 2009, Chesapeake and PXP amended their joint venture agreement to accelerate the payment of PXP’s remaining joint venture drilling carries as of September 30, 2009 in exchange for an approximate 12% reduction in the total amount of drilling carry obligations due to Chesapeake. As a result, on September 29, 2009, Chesapeake received approximately $1.1 billion in cash from PXP and, beginning in the 2009 fourth quarter, Chesapeake and PXP will each pay their proportionate working interest costs on future drilling.

Assuming flat NYMEX natural gas prices of $7.00 per mcf over the life of the well (compared to a recent 10-year NYMEX strip price of approximately $7.25 per mcf), the company’s estimated pre-tax rate of return from a 6.5 bcfe horizontal Haynesville well drilled for $7.0 million is approximately 55%. In addition, Chesapeake’s leasehold investment in the Haynesville to date has been approximately $5.0 billion, of which approximately $2.8 billion, or 56%, has been recouped to date by selling a 20% interest in the company’s leasehold to PXP. The company’s net investment in its Haynesville leasehold is now about $4,300 per net acre on average.

Two notable recent wells completed by Chesapeake in the Haynesville are as follows:

  • The Caspiana 13-15-12 H-1 in Caddo Parish, LA achieved a peak rate of 20.2 mmcf per day; and
  • The Bradway 24-15-12 H-1 in Caddo Parish, LA achieved a peak rate of 18.6 mmcf per day.

Marcellus Shale (West Virginia, Pennsylvania and New York): With approximately 1.5 million net acres, Chesapeake is the largest leasehold owner in the Marcellus Shale play that spans from northern West Virginia across much of Pennsylvania into southern New York. The company’s joint venture partner, StatoilHydro (NYSE:STO, OSE:STL), owns approximately 570,000 additional net acres of Marcellus leasehold. Chesapeake remains the most active driller and expects to become the largest gross producer of natural gas from the play by year-end 2009. During the 2009 third quarter, Chesapeake’s average daily net production of 35 mmcfe in the Marcellus increased approximately 21% over the 2009 second quarter and approximately 338% over the 2008 third quarter. Chesapeake is currently producing a company record monthly average of approximately 50 mmcfe net per day (100 mmcfe gross operated) from the Marcellus and anticipates reaching approximately 90 mmcfe net per day (180 mmcfe gross operated) by year-end 2009, approximately 220 mmcfe net per day (440 mmcfe gross operated) by year-end 2010 and approximately 390 mmcfe net per day (780 mmcfe gross operated) by year-end 2011. To further develop its 1.5 million net acres of Marcellus leasehold, Chesapeake is currently drilling with 20 operated rigs and anticipates operating an average of approximately 28 rigs in 2010 to drill approximately 170 net wells. During the first three quarters of 2009, approximately $85 million of Chesapeake’s drilling costs in the Marcellus were paid for by STO. During the 2009 fourth quarter through 2012, 75% of Chesapeake’s drilling costs in the Marcellus will be paid for by STO, or approximately $2.0 billion over the next three years.

Since January 1, 2008, Chesapeake has drilled and completed 40 company-operated horizontal wells in the Marcellus. Assuming flat NYMEX natural gas prices of $7.00 per mcf (compared to a recent 10-year NYMEX strip price of approximately $7.25 per mcf), the company’s estimated pre-tax rate of return from a 4.2 bcfe horizontal Marcellus well drilled for $4.5 million is approximately 66% excluding the benefit of drilling carries and more than 1,000% including the benefit of drilling carries. The STO drilling carries should result in Chesapeake delivering lower finding costs, higher returns on invested capital and higher production growth levels than other companies can deliver from the Marcellus. In addition, Chesapeake’s leasehold investment in the Marcellus to date has been approximately $1.5 billion, of which $1.25 billion, or 83%, has been recouped to date by selling a 32.5% interest in the company’s leasehold to STO. The company’s net investment in its Marcellus leasehold is now about $165 per net acre on average.

Two notable recent wells completed by Chesapeake in the Marcellus are as follows:

  • The Clapper 2H in Susquehanna County, PA achieved a peak rate of 10.1 mmcf per day; and
  • The Otten 2H in Bradford County, PA achieved a peak rate of 8.9 mmcf per day.

Barnett Shale (North Texas): The Barnett Shale is currently the largest natural gas producing field in the U.S. and is producing approximately 50-60% of all shale gas in the U.S. In this play, Chesapeake is the second-largest producer, the most active driller and the largest leasehold owner in the Core and Tier 1 sweet spots of Tarrant and Johnson counties. During the 2009 third quarter, Chesapeake’s average daily net production of 639 mmcfe in the Barnett was approximately flat compared to the 2009 second quarter and increased approximately 22% over the 2008 third quarter. Chesapeake is currently producing a company record monthly average of approximately 685 mmcfe net per day (1,000 mmcfe gross operated) from the Barnett and anticipates reaching approximately 700 mmcfe net per day (1,020 mmcfe gross operated) by year-end 2009, approximately 725 mmcfe net per day (1,060 mmcfe gross operated) by year-end 2010 and approximately 760 mmcfe net per day (1,110 mmcfe gross operated) by year-end 2011. To further develop its 305,000 net acres of leasehold, of which 275,000 net acres are located in the Core and Tier 1 areas, Chesapeake anticipates operating an average of approximately 18 rigs in 2010 to drill approximately 300 net wells. If Chesapeake is successful in finding a joint venture partner for some or all of its Barnett Shale leasehold, the company plans to significantly increase Barnett drilling activity and production in 2010 and beyond. Assuming flat NYMEX natural gas prices of $7.00 per mcf (compared to a recent 10-year NYMEX strip price of approximately $7.25 per mcf), the company’s estimated pre-tax rate of return from a 2.65 bcfe horizontal Barnett well drilled for $2.6 million is approximately 36%.

Two notable recent wells completed by Chesapeake in the Barnett are as follows:

  • The Day Kimball Hill A1 in Tarrant County, TX achieved a peak rate of 16.4 mmcf per day and is expected to produce an average of more than 13.0 mmcf per day in its first full month and exceed the previous monthly industry Barnett production record established by two Chesapeake-operated wells this summer that averaged more than 9.0 mmcf per day; and
  • The Chaney 2H in Johnson County, TX achieved a peak rate of 10.0 mmcf per day.

Fayetteville Shale (Arkansas): The Fayetteville Shale is currently the second most productive shale play in the U.S. and one of the nation’s 10 largest natural gas fields of any type. In the Fayetteville, Chesapeake is the second-largest leasehold owner in the Core area of the play with 445,000 net acres. During the 2009 third quarter, Chesapeake’s average daily net production of 248 mmcfe in the Fayetteville increased approximately 13% over the 2009 second quarter and approximately 49% over the 2008 third quarter. Chesapeake is currently producing approximately 260 mmcfe net per day (400 mmcfe gross operated) from the Fayetteville and anticipates reaching approximately 290 mmcfe net per day (445 mmcfe gross operated) by year-end 2009, approximately 300 mmcfe net per day (460 mmcfe gross operated) by year-end 2010 and approximately 330 mmcfe net per day (510 mmcfe gross operated) by year-end 2011. To further develop its 445,000 net acres of Core Fayetteville leasehold, Chesapeake anticipates operating an average of approximately 12 rigs in 2010 to drill approximately 100 net wells. During the first the first three quarters of 2009, 100% of Chesapeake’s $524 million of drilling costs in the Fayetteville were paid for by its joint venture partner BP America (NYSE:BP). During the fourth quarter 2009, nearly all of Chesapeake’s drilling costs, or approximately $75 million, will be paid for by BP, bringing to an end BP’s drilling carry obligations to Chesapeake.

Assuming flat NYMEX natural gas prices of $7.00 per mcf (compared to a recent 10-year NYMEX strip price of approximately $7.25 per mcf), the company’s estimated pre-tax rate of return from a 2.4 bcfe horizontal Fayetteville well drilled for $3.0 million is approximately 31% excluding the benefit of drilling carries and is infinite including the benefit of drilling carries. During the last few months of 2008 and throughout 2009, Chesapeake’s 100% drilling carry from BP has resulted in lower finding costs, higher returns on invested capital and higher production growth levels than other companies have been able to deliver from the Fayetteville. In addition, Chesapeake’s leasehold investment in the Fayetteville to date has been approximately $530 million. By selling a 25% interest in the company’s leasehold to BP for $883 million, the company has more than recouped its entire leasehold investment in the Fayetteville.

Two notable recent wells completed by Chesapeake in the Fayetteville are as follows:

  • The Reva Deen 7-8 1-15H9 in White County, AR achieved a peak rate of 8.0 mmcf per day; and
  • The Collinsworth 7-16 2-10H in Conway County, AR achieved a peak rate of 6.2 mmcf per day.

Anadarko Basin Granite Wash (western Oklahoma and Texas Panhandle): In the various Wash plays of the Anadarko Basin, Chesapeake is the largest leasehold owner with approximately 350,000 net acres and is also the most active driller and largest producer. The Colony Granite Wash and the Texas Panhandle Granite Wash plays highlighted below are two particularly prolific areas within the Anadarko Basin Granite Wash and have become the two highest rate-of-return plays in the company.

Colony Granite Wash (western Oklahoma): Discovered by Chesapeake in February 2007, the Colony Granite Wash play is located in Custer and Washita counties, Oklahoma and is a subset of the greater Granite Wash plays of the Anadarko Basin. In the Colony Granite Wash, Chesapeake is the largest leasehold owner with 60,000 net acres and is also the most active driller and largest producer in the play. During the 2009 third quarter, Chesapeake’s average daily net production of 108 mmcfe in the Colony Granite Wash increased approximately 44% over the 2009 second quarter and approximately 108% over the 2008 third quarter. Chesapeake is currently producing approximately 110 mmcfe net per day (200 mmcfe gross operated) from the Colony Granite Wash and anticipates producing approximately 110 mmcfe net per day (200 mmcfe gross operated) at year-end 2009, approximately 145 mmcfe net per day (265 mmcfe gross operated) by year-end 2010 and approximately 175 mmcfe net per day (320 mmcfe gross operated) by year-end 2011. To further develop its 60,000 net acres of Colony Granite Wash leasehold, Chesapeake anticipates operating an average of approximately seven rigs in 2010 to drill approximately 40 net wells. Due in large part to the play’s high oil and natural gas liquids content, the Colony Granite Wash is Chesapeake’s highest rate-of-return play. Assuming flat NYMEX natural gas and oil prices of $7.00 per mcf and $70 per bbl, respectively (compared to recent 10-year NYMEX strip natural gas and oil prices of approximately $7.25 per mcf and $87.00 per bbl), the company’s estimated pre-tax rate of return from a 5.7 bcfe horizontal Colony Granite Wash well drilled for $6.25 million is approximately 141%.

Texas Panhandle Granite Wash: The Texas Panhandle Granite Wash play is located in Hemphill, Wheeler and Roberts counties, Texas and is a subset of the greater Granite Wash plays of the Anadarko Basin. In the Texas Panhandle Granite Wash, Chesapeake is one of the largest leasehold owners with 40,000 net acres and also one of the most active drillers and largest producers in the play. During the 2009 third quarter, Chesapeake’s average daily net production of 79 mmcfe in the Texas Panhandle Granite Wash increased approximately 3% over the 2009 second quarter and approximately 18% over the 2008 third quarter. Chesapeake is currently producing approximately 75 mmcfe net per day (100 mmcfe gross operated) from the Texas Panhandle Granite Wash and anticipates producing approximately 75 mmcfe net per day (100 mmcfe gross operated) at year-end 2009, approximately 80 mmcfe net per day (105 mmcfe gross operated) by year-end 2010 and approximately 85 mmcfe net per day (110 mmcfe gross operated) by year-end 2011. To further develop its 40,000 net acres of Texas Panhandle Granite Wash leasehold, Chesapeake anticipates operating an average of three rigs in 2010 to drill approximately 20 net wells. Assuming flat natural gas and oil prices of $7.00 per mcf and $70 per bbl, respectively (compared to recent 10-year NYMEX strip natural gas and oil prices of approximately $7.25 per mcf and $87.00 per bbl), the company’s estimated pre-tax rate of return from a 4.75 bcfe horizontal Texas Panhandle Granite Wash well drilled for $5.5 million is approximately 128%.

Management Comments

Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, “We are pleased to announce strong operational results for the 2009 third quarter including record organic proved reserve growth. While we expect natural gas prices to move higher in the months ahead, low natural gas prices at the end of the 2009 third quarter led to a 2.2 tcfe reduction of our proved reserves. Excluding these price-related revisions, Chesapeake would have reported 14.2 tcfe of proved reserves for the quarter – a level above that which we had previously targeted achieving by year-end 2009. Our attractive finding and net acquisition costs of less than $0.80 per mcfe benefitted from strong drilling results, reduced drilling costs and approximately $960 million of drilling carries from our joint venture partners. We have recently achieved company record production rates in our shale plays and anticipate delivering total company production growth of 8-10% in 2010 and 12-14% in 2011. We look forward to providing additional details on our 2009 third quarter results next week.”

2009 Third Quarter Financial and Operational Results and Conference Call Information

Chesapeake is scheduled to release its 2009 third quarter financial and operational results after the close of trading on the New York Stock Exchange on Monday, November 2, 2009. Also, a conference call to discuss this release and the November 2 release has been scheduled for Tuesday, 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 41337448. 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 includes “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, expectations regarding future natural gas and oil prices, planned drilling activity and costs, as well as statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. 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.

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

The company calculates the standardized measure of future net cash flows of proved reserves 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 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.

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.

 

 

Source: Chesapeake Energy Corporation

Chesapeake Energy Corporation
Investor Contact:
Jeffrey L. Mobley, CFA, 405-767-4763
Senior Vice President –
Investor Relations and Research
jeff.mobley@chk.com
or
Media Contact:
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Director – Media Relations
jim.gipson@chk.com