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Chesapeake Energy Corporation Provides Quarterly Operational Update

8/2/2010 11:03 AM

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Company Reports 2010 Second Quarter Production of 2.789 Bcfe per Day, an Increase of 14% over 2009 Second Quarter Production and 8% over 2010 First Quarter Production;
2010 Second Quarter Production of Liquids Increases 41% Year-Over-Year to 10%
of Total Production and 17% of Realized Natural Gas and Liquids Revenue

Company Expects Production Growth of Approximately 13% in 2010 and 18% in 2011, Including Liquids Production Growth of Approximately 60% in 2010 and 80% in 2011

Proved Reserves Reach 15.5 Tcfe; Company Reports 2010 First Half
Drilling and Completion Costs of $0.87 per Mcfe

2011 Drilling and Completion Capital Expenditures Projected to Remain Flat Compared
to 2010 Drilling and Completion Capital Expenditures; 2011 Drilling and Completion
Capital Expenditures Reduced by $400 Million on Natural Gas Plays and
Increased by $400 Million on Liquids-Rich Plays Compared to 2010

Company Expects to Increase Liquids Production to Approximately 200,000 Bbls per Day, or Approximately 25% of Total Production and Approximately 40% of Production
Revenue, by Year-End 2015 through Organic Growth

Eagle Ford Shale Joint Venture Discussions Continue; Transaction
Announcement Anticipated in the 2010 Third Quarter

OKLAHOMA CITY, OKLAHOMA, AUGUST 2, 2010 – Chesapeake Energy Corporation (NYSE:CHK) today provided an update on its operational activities.  For the 2010 second quarter, daily production averaged 2.789 billion cubic feet of natural gas equivalent (bcfe), an increase of 203 million cubic feet of natural gas equivalent (mmcfe), or 8%, above the 2.586 bcfe produced per day in the 2010 first quarter and an increase of 336 mmcfe, or 14%, over the 2.453 bcfe produced per day in the 2009 second quarter.

Chesapeake’s average daily production of 2.789 bcfe for the 2010 second quarter consisted of 2.497 billion cubic feet of natural gas (bcf) and 48,670 barrels of oil and natural gas liquids (NGLs) (bbls). The company’s 2010 second quarter production of 253.8 bcfe was comprised of 227.2 bcf (90% on a natural gas equivalent basis) and 4.4 million barrels of oil and NGLs (mmbbls) (10% on a natural gas equivalent basis).  The company’s year-over-year growth rate of natural gas production was 11% and its year-over-year growth rate of oil and NGLs (liquids) production was 41%.  The company’s percentage of revenue from liquids in the 2010 second quarter was 17% of realized production revenue compared to 14% in the 2009 second quarter.

Chesapeake is projecting full-year production growth of approximately 13% in 2010 and 18% in 2011, including production growth from liquids of approximately 60% in 2010 and 80% in 2011. Of Chesapeake’s projected 13% and 18% growth rates in 2010 and 2011, approximately 37% and 50%, respectively, of the growth is projected to come from increased liquids production.

Chesapeake’s Proved Natural Gas and Oil Reserves Increase by 8% in the
2010 First Half to 15.5 Tcfe; Company Reports 2010 First Half
Drilling and Completion Costs of $0.87 per Mcfe

The following table compares Chesapeake’s June 30, 2010 proved reserves, the increase over its year-end 2009 proved reserves, reserve replacement ratio, estimated future net cash flows from proved reserves (discounted at an annual rate of 10% before income taxes (PV-10)), and proved developed percentage based on the trailing 12-month average price required under SEC rules and the 10-year average NYMEX strip prices at June 30, 2010.

Pricing Method Natural Gas Price ($/mcf) Oil Price ($/bbl) Proved Reserves (tcfe)(a)(b) First Half Proved Reserves Growth (tcfe)(c) First Half Proved Reserves Growth %(c) Reserve Replacement Ratio PV-10 (billions) Proved Developed Percentage
Trailing 12-month average (SEC) $4.10 $75.78 15.5 1.2 8.5% 348% $12.9 54%
6/30/10 10-year average NYMEX strip $6.30 $84.38 16.1 0.6 3.9% 225% $26.8 55%

(a) Reserve volumes estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of June 2010 of $4.10 per mcf of natural gas and $75.78 per bbl of oil, before field differential adjustments.  This pricing yields estimated "proved reserves" for SEC reporting purposes.  Natural gas and oil volumes estimated under any alternative pricing scenario reflect the sensitivity of proved reserves to a different pricing assumption.

(b) After sales of proved reserves of approximately 1.1 tcfe during the 2010 first half.

(c) Compares proved reserve growth for the 2010 first half under comparable pricing methods.  At year-end 2009, Chesapeake’s proved reserves were 14.3 tcfe using trailing 12-month average prices, which are required by SEC reporting rules, and 15.5 tcfe using the 10-year average NYMEX strip prices at December 31, 2009.  Futures prices represent an unbiased consensus estimate by market participants about the likely prices to be received for future production.  Management believes that 10-year average NYMEX strip prices provide a better indicator of the likely economic producibility of the company’s proved reserves than the historical 12-month average price.

The following table summarizes Chesapeake’s development costs for the 2010 first half using the two pricing methods described above.

Development Cost Category Trailing 12-Month Average (SEC) Pricing ($/mcfe) 6/30/10 10-year Average NYMEX Strip Pricing ($/mcfe)
Drilling and completion costs (1) $0.87 $0.97
Drilling, completion and net acquisition costs (1) $0.42 $0.55

(1)Includes performance-related revisions and drilling and completion carries and excludes price-related revisions

A complete reconciliation of proved reserves and reserve replacement ratios based on these two alternative pricing methods, along with total costs, is presented on pages 11 and 12 of this release.

In addition to the PV-10 value of its proved reserves and the significant value of its undeveloped leasehold, particularly in the Haynesville, Marcellus, Barnett and Fayetteville unconventional natural gas shale plays and the company’s unconventional liquids-rich plays, particularly the Granite Wash and Eagle Ford Shale, the net book value of the company’s other assets (including gathering systems, compressors, land and buildings, investments and other non-current assets) was $5.8 billion as of June 30, 2010 compared to $6.7 billion as of December 31, 2009.  The decline in other assets is primarily due to the deconsolidation of the company’s midstream joint venture reflecting the implementation of new accounting guidance for certain investments.

During the 2010 first half, Chesapeake continued the industry’s most active drilling program, drilling 687 gross operated wells (440 net wells with an average working interest of 64%) and participating in another 562 gross wells operated by other companies (73 net wells with an average working interest of 13%).  The company’s drilling success rate was 99% for both company-operated wells and non-operated wells.

2011 Drilling and Completion Capital Expenditures Projected to Remain Flat Compared to 2010 Drilling and Completion Capital Expenditures; 2011 Drilling and Completion Capital Expenditures Reduced by $400 Million on Natural Gas Plays and
Increased by $400 Million on Liquids-Rich Plays Compared to 2010

In recognition of the significant and persistent value gap that has developed between natural gas and oil prices, Chesapeake has accelerated its transition to a more liquids-rich asset base.  The company has redirected a significant portion of its technological, geoscientific, leasehold acquisition and drilling expertise to identifying, securing and commercializing unconventional liquids-rich plays.  To date, Chesapeake has built leasehold positions and established production in 12 disclosed and several undisclosed liquids-rich plays.  The company now owns approximately 2.4 million net acres of leasehold in liquids-rich plays with approximately 3.0 billion barrels of oil equivalent (bboe) (18 tcfe) of risked unproved resources and approximately 8.2 bboe (49 tcfe) of unrisked unproved resources.

Additionally, compared to 2010, Chesapeake is reducing its projected 2011 drilling and completion capital expenditures on natural gas plays by approximately $400 million and increasing its drilling and completion capital expenditures on liquids-rich plays by approximately $400 million.  On a net basis, after joint venture carries, Chesapeake is projecting 2011 drilling and completion capital expenditures will remain flat compared to 2010 drilling and completion capital expenditures of approximately $4.5 - $4.6 billion. The following table provides an analysis and projection of how Chesapeake's operated net drilling and completion capital expenditures on liquids plays are expected to increase from 13% in 2008 to approximately 55% in 2012.

CHK Operated Drilling and
Completion Capital Expenditures
Year Natural Gas Plays Liquids Plays
2008 (actual) 87% 13%
2009 (actual) 90% 10%
2010 (1H actual, 2H projected) 68% 32%
2011 (projected) 59% 41%
2012 (projected) 45% 55%

This planned transition will result in a more balanced portfolio between natural gas and liquids and by year-end 2015, Chesapeake expects to increase its liquids production to approximately 200,000 bbls per day, or approximately 25% of total production (using a 6:1 natural gas to liquids ratio), through organic growth and expects revenue from liquids to be approximately 40% of total production revenue. 

Chesapeake’s Leasehold and 3-D Seismic Inventories Total 13.9 Million Net Acres and 25.5 Million Acres; Risked Unproved Resources in the Company’s Inventory Total 95 Tcfe

Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (13.9 million net acres) and 3-D seismic (25.5 million acres) in the U.S. and the largest inventory of U.S. natural gas shale play leasehold (2.8 million net acres) and now owns the largest inventory of leasehold in two of the Top 3 new unconventional liquids-rich plays – the Eagle Ford Shale and the Niobrara Shale. 

On its total leasehold inventory, Chesapeake has identified an estimated 16.1 tcfe of proved reserves (using volume estimates based on the 10-year average NYMEX strip prices at June 30, 2010), 95 tcfe of risked unproved resources and 225 tcfe of unrisked unproved resources.  The company is currently using 133 operated drilling rigs to further develop its inventory of approximately 40,000 net drillsites.  Of Chesapeake’s 133 operated rigs, 91 are drilling wells primarily focused on unconventional natural gas plays and 42 are drilling wells primarily focused on liquids-rich plays.  In addition, 126 of the company’s 133 operated rigs are drilling horizontal wells. 

Marcellus Shale (West Virginia, Pennsylvania and New York): With approximately 1.55 million net acres, an increase of approximately 50,000 net acres from the 2010 first quarter, Chesapeake is the largest leasehold owner, second-largest producer and most active driller in the Marcellus Shale play that spans from northern West Virginia across much of Pennsylvania into southern New York.  On its Marcellus leasehold, Chesapeake estimates it has approximately 460 bcfe of proved reserves (based on the 10-year average NYMEX strip prices at June 30, 2010) and 34.1 tcfe of risked unproved resources.  As a result of continued strong production results, the company has recently raised its average estimated ultimate recovery (EUR) on its Marcellus Shale acreage by approximately 24% from 4.2 bcfe per well to 5.2 bcfe per well.

During the 2010 second quarter, Chesapeake’s average daily net production of 105 mmcfe in the Marcellus increased approximately 65% over the 2010 first quarter and approximately 250% over the 2009 second quarter.  The company’s average daily net production rate in the Marcellus in July 2010 was approximately 130 mmcfe and the company anticipates adding more than 60 mmcfe of net production in the West Virginia portion of the play in the second half of 2010 once new natural gas processing facilities become operational.  Chesapeake is currently drilling with 26 operated rigs in the Marcellus and anticipates operating an average of approximately 28 rigs in 2010 to drill approximately 150 net wells.  During the 2010 second quarter, Chesapeake received approximately $144 million of drilling and completion carries from its Marcellus joint venture partner Statoil (NYSE:STO, OSE:STL).  From July 2010 through 2012, Chesapeake should receive approximately $1.7 billion in additional drilling carries from STO.

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

  • The Mowry 1H in Bradford County, PA achieved a peak 24-hour rate of 9.9 million cubic feet of natural gas (mmcf) per day;
  • The Przybyszewski 4H in Susquehanna County, PA achieved a peak 24-hour rate of 9.7 mmcf per day; and
  • The White 2H in Susquehanna County, PA achieved a peak 24-hour rate of 9.0 mmcf per day.

Haynesville and Bossier Shales (Northwest Louisiana and East Texas): Chesapeake is the largest leasehold owner, largest producer and most active driller of new wells in the Haynesville Shale play in Northwest Louisiana and East Texas.  Chesapeake owns approximately 530,000 net acres of leasehold in the Haynesville Shale play, under which approximately 195,000 net acres is prospective for the Bossier Shale.  On its Haynesville and Bossier leasehold, Chesapeake estimates it has approximately 2.9 tcfe of proved reserves (based on the 10-year average NYMEX strip prices at June 30, 2010) and 23.7 tcfe of risked unproved resources.

The company has drilled and completed 252 gross Chesapeake-operated horizontal wells in the Haynesville and Bossier since discovering the play in 2007.  During the 2010 second quarter, Chesapeake’s average daily net production of 560 mmcfe in the Haynesville increased approximately 30% over the 2010 first quarter and approximately 315% over the 2009 second quarter.  The company’s average daily net production rate in the Haynesville in July 2010 was approximately 615 mmcfe.  The company is currently drilling with 35 operated rigs in the Haynesville and anticipates operating an average of approximately 36 rigs in 2010 to drill approximately 175 net wells.  The company anticipates having the vast majority of its Haynesville Shale leasehold held by production (HBP) by year-end 2011 and as such will have greater drilling flexibility in the years ahead.

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

  • The Sloan H-1 in DeSoto Parish, LA achieved a peak 24-hour rate of 22.2 mmcf per day;
  • The Brasch Family H-1 in DeSoto Parish, LA achieved a peak 24-hour rate of 22.0 mmcf per day; and
  • The Wren H-1 in DeSoto Parish, LA achieved a peak 24-hour rate of 21.6 mmcf per day.

Barnett Shale (North Texas): The Barnett Shale is currently the largest natural gas-producing field 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.  Following the sale of 25% of its interests in the Barnett Shale to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE:TOT, FP:FP), in January 2010, the company owns approximately 220,000 net acres of leasehold.  Chesapeake estimates it has approximately 2.9 tcfe of proved reserves (based on the 10-year average NYMEX strip prices at June 30, 2010) and 3.4 tcfe of risked unproved resources in the Barnett play.  As a result of continued strong production results, the company has recently raised its average EUR on its Barnett Shale acreage by approximately 13% from 2.65 bcfe per well to 3.0 bcfe per well.

During the 2010 second quarter, Chesapeake’s average daily net production of 535 mmcfe in the Barnett decreased approximately 5% over the 2010 first quarter and decreased approximately 20% over the 2009 second quarter.  Adjusted for the company’s sale of a 25% joint venture interest to Total in the 2010 first quarter, the company’s sequential and year-over-year production growth rate in the Barnett Shale was 5% and 10%, respectively.  The company’s average daily net production rate in the Barnett in July 2010 was approximately 535 mmcfe.  Chesapeake is currently drilling with 22 operated rigs in the Barnett and anticipates operating an average of approximately 22 rigs in the Barnett in 2010 to drill approximately 245 net wells.  During the 2010 second quarter, Chesapeake received approximately $110 million of drilling and completion carries from Total.  From July 2010 through 2012, Chesapeake should receive approximately $1.2 billion in additional drilling carries from Total.

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

  • The Brown 7H in Johnson County, TX achieved a peak 24-hour rate of 8.0 mmcf per day;
  • The Fellowship 5H in Dallas County, TX achieved a peak 24-hour rate of 7.9 mmcf per day; and
  • The Greenbriar 2H in Tarrant County, TX achieved a peak 24-hour rate of 7.0 mmcf per day.

Fayetteville Shale (Arkansas): In the Fayetteville, Chesapeake is the second-largest leasehold owner and producer and the most active driller in the play with 465,000 net acres.  On its Fayetteville leasehold, the company estimates it has approximately 2.4 tcfe of proved reserves (based on the 10-year average NYMEX strip prices at June 30, 2010) and 7.7 tcfe of risked unproved resources.  As a result of continued strong production results, the company has recently raised its average EUR on its Fayetteville Shale acreage by approximately 8% from 2.4 bcfe per well to 2.6 bcfe per well.

During the 2010 second quarter, Chesapeake’s average daily net production of 370 mmcfe in the Fayetteville increased approximately 5% over the 2010 first quarter and approximately 65% over the 2009 second quarter. The company’s average daily net production rate in the Fayetteville in July 2010 was approximately 370 mmcfe. The company is currently drilling with eight operated rigs in the Fayetteville and anticipates operating an average of approximately 10 rigs in 2010 to drill approximately 85 net wells. The Fayetteville provides an excellent example of how the company is able to reduce its drilling activity once a play is substantially HBP. Chesapeake lowered its drilling activity from an average of 18 operated rigs in 2009 to eight operated rigs currently and an average of eight operated rigs projected for 2011 and beyond.

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

  • The Merideth 7-16 2-2H in Conway County, AR achieved a peak 24-hour rate of 7.3 mmcf per day;
  • The Ransom 7-8 1-21H16 in White County, AR achieved a peak 24-hour rate of 6.0 mmcf per day; and
  • The Heggie 7-9 5-12H1 in White County, AR achieved a peak 24-hour rate of 4.9 mmcf per day.

Granite Wash (western Oklahoma and Texas Panhandle): Chesapeake is the largest leasehold owner and producer and the most active driller with approximately 200,000 net acres, an increase of 5,000 net acres from the 2010 first quarter, in the unconventional liquids-rich Granite Wash plays in the Anadarko Basin, which include the Oklahoma Colony and the Texas Panhandle Granite Wash plays.  On its Granite Wash leasehold, Chesapeake estimates it has approximately 200 million barrels of oil equivalent (mmboe) (1.2 tcfe) of proved reserves (based on the 10-year average NYMEX strip prices at June 30, 2010) and 900 mmboe (5.4 tcfe) of risked unproved resources.

During the 2010 second quarter, Chesapeake’s average daily net production of 260 mmcfe (43 thousand barrels of oil equivalent (mboe)) in the Greater Granite Wash play increased approximately 5% over the 2010 first quarter and 80% over the 2009 second quarter.  Chesapeake anticipates operating an average of approximately 12 rigs in the Granite Wash in 2010 to drill approximately 75 net wells.  Due in large part to the play’s high oil and natural gas liquids content, the Granite Wash is currently Chesapeake’s highest rate-of-return play and serves as an example of how the company is implementing a transition to increased drilling activity and production to liquids-rich plays.  Chesapeake increased its drilling activity in the Granite Wash from an average of eight operated rigs in 2009 to 14 operated rigs currently and an average of 16 operated rigs projected for 2011. 

Three notable recent wells completed by Chesapeake in the Colony Granite Wash are as follows:

  • The James 1-33H in Washita County, OK achieved a peak 24-hour rate of 10.0 mmcf and 2,490 bbls per day, or 24.9 mmcfe per day;
  • The Huls USA 1-13H in Washita County, OK achieved a peak 24-hour rate of 13.3 mmcf and 1,780 bbls per day, or 24.0 mmcfe per day; and
  • The Gwendolyn 2-22H in Washita County, OK achieved a peak 24-hour rate of 8.0 mmcf and 1,980 bbls per day, or 19.9 mmcfe per day.

Three notable recent wells completed by Chesapeake in the Texas Panhandle Granite Wash are as follows:

  • The Ruby Lee 104H in Wheeler County, TX achieved a peak 24-hour rate of 25.3 mmcf and 2,920 bbls per day, or 42.8 mmcfe per day;
  • The Dowell 1-31H in Roger Mills County, OK achieved a peak 24-hour rate of 16.2 mmcf and 2,440 bbls per day, or 30.6 mmcfe per day; and
  • The Zybach 2010H in Wheeler County, TX achieved a peak 24-hour rate of 8.0 mmcf and 1,270 bbls per day, or 15.6 mmcfe per day.

Eagle Ford Shale (South Texas): Chesapeake has built a leading position in the liquids-rich portion of the Eagle Ford Shale in South Texas with approximately 550,000 net acres of Eagle Ford Shale leasehold, an increase of approximately 150,000 net acres from the 2010 first quarter. Chesapeake has drilled and completed seven gross wells to date and anticipates operating an average of approximately five rigs in the Eagle Ford in 2010.  In 2011 and 2012, the company expects to increase its drilling activity to an average of 16 and 27 rigs, respectively.  Chesapeake expects to conclude ongoing Eagle Ford Shale joint venture discussions and announce a joint venture transaction by the end of the 2010 third quarter.

Three notable recent wells completed by Chesapeake in the Eagle Ford Shale are as follows:

  • The PGE Browne 1-H in Webb County, TX achieved a peak 24-hour rate of 4.0 mmcf and 1,200 bbls per day, or 11.2 mmcfe per day;
  • The Lazy A Cotulla 1H in Dimmit County, TX achieved a peak 24-hour rate of 0.3 mmcf and 930 bbls per day, or 5.9 mmcfe per day; and
  • The Traylor North 1H in Zavala County, TX achieved a peak 24-hour rate of 0.3 mmcf and 930 bbls per day, or 5.9 mmcfe per day.

Anadarko Basin Unconventional Liquids Plays (western Oklahoma and Texas Panhandle): Chesapeake is the largest leasehold owner in the Anadarko Basin unconventional liquids plays, which include horizontal drilling in the Cleveland, Tonkawa and Mississippian formations, with approximately 730,000 net acres, an increase of 65,000 net acres from the 2010 first quarter.  The company has drilled and completed 55 gross wells to date in these three plays.  Chesapeake anticipates operating an average of approximately six rigs in its Anadarko Basin unconventional liquids plays in 2010 to drill approximately 55 net wells and expects to increase its average operated rig count to 11 in 2011 and 13 in 2012.

Permian Basin Unconventional Liquids Plays (West Texas and southern New Mexico): Chesapeake has built a strong position of approximately 290,000 net acres of leasehold in four Permian Basin unconventional liquids plays: the Avalon Shale, Bone Spring, Wolfcamp and Spraberry in West Texas and in southern New Mexico.  The company has drilled and completed 100 gross wells to date in these four plays.  Chesapeake anticipates operating an average of approximately five rigs in its Permian Basin unconventional liquids plays in 2010 to drill approximately 60 net wells.  In 2011 and 2012, the company plans to increase its operated rig count as it continues its transition away from natural gas drilling to more liquids-rich drilling.

Rocky Mountain Unconventional Liquids Plays (southern Wyoming and northern Colorado): Chesapeake has developed a leading position in the horizontal Niobrara and Frontier plays in the Powder River Basin in Wyoming with approximately 470,000 net acres acquired during the past two years.  The company has also recently entered the Niobrara play in the DJ Basin of northern Colorado and southern Wyoming with 205,000 net acres.  The company has drilled and completed two gross wells to date in these plays.  Chesapeake expects to initiate joint venture discussions in the Niobrara play in the 2010 second half.  In 2011 and 2012, the company plans to increase its Niobrara and Frontier operated rig count to an average of approximately six operated rigs as it continues its transition away from natural gas drilling to more liquids-rich drilling.

Management Comments

Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, “We are pleased to deliver strong operational performance in the 2010 second quarter highlighted by 8% production growth over the 2010 first quarter and drilling and completion costs of $0.87 per mcfe for the 2010 first half.  We also have reduced our projected 2011 natural gas drilling and completion capital expenditures by approximately $400 million and increased our projected liquids-rich drilling and completion capital expenditures by approximately $400 million compared to 2010.  Additionally, after a very aggressive effort to capture leasehold in the first half of 2010 in a large number of highly competitive liquids-rich unconventional plays, the company expects to become a significant seller of leasehold in the second half of 2010 and in 2011 through planned joint venture transactions. 

“Chesapeake’s goal is to reach a balanced mix of natural gas and liquids revenue as quickly as possible.  We plan to shift our capital spending mix between natural gas plays and liquids-rich plays to approximately 45/55 by year-end 2012.  By year-end 2015, we expect to increase our liquids production to approximately 200,000 bbls per day, or approximately 25% of total production and 40% of production revenue.  This will be a remarkable achievement for a company of our size, one that we expect to deliver to our investors from organic drilling, rather than through acquisitions, at very low per net acre leasehold acquisition costs and low drilling and completion costs.  Chesapeake’s transition will be transformative for our company and its shareholders.

“Our strategy to accomplish this goal is set forth below:

  • Reduce drilling of natural gas wells except for those required to HBP leasehold or to use a drilling carry provided by a joint venture partner until such time as natural gas prices rise above $6.00 per mcf;
  • Lease and develop substantial new liquids-rich plays in which the company can acquire very large leasehold positions of 250,000-750,000 net acres;
  • Within one year of acquisition, sell a minority interest in a new play, recovering all or virtually all of the cost to acquire the leasehold in the play, and to fund a significant portion of Chesapeake’s future drilling costs in the play;
  • Accelerate drilling of liquids-rich plays until year-end 2012 when the company’s drilling capital expenditures are balanced approximately 50/50 between natural gas plays and liquids-rich plays;
  • Continue adding proved reserves, net of monetizations and divestitures, of approximately 2.5 - 3.0 tcfe (415 - 500 mmboe) annually; and
  • Accomplish these goals without the issuance of additional equity and with a reduction of debt levels such that the company becomes investment grade within the next few years.”

Conference Call Information

Chesapeake is scheduled to release its 2010 second quarter financial results after the close of trading on the New York Stock Exchange on Tuesday, August 3, 2010.  Also, a conference call to discuss this release and the August 3 release has been scheduled for Wednesday, August 4, 2010, at 9:00 a.m. EDT.  The telephone number to access the conference call is 913-312-4373 or toll-free 866-454-4205. The passcode for the call is 9144645.  We encourage those who would like to participate in the call to dial the access number between 8:50 and 9:00 a.m. EDT.  For those unable to participate in the conference call, a replay will be available for audio playback from 1:00 p.m. EDT on August 4, 2010 through midnight EDT on August 18, 2010.  The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112.   The passcode for the replay is 9144645.  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 the website.  The webcast of the conference call will be available on Chesapeake’s 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 proved reserves and unproved resources, projections of future natural gas and oil production, 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 2009 Form 10-K filed with the U.S. Securities and Exchange Commission on March 1, 2010.  These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; 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; potential differences in our interpretations of new reserve disclosure rules and future SEC guidance; inability to generate profits or achieve targeted results in drilling and well operations; 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; a reduced ability to borrow or raise additional capital as a result of  lower natural gas and oil prices; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business; general economic conditions negatively impacting us and our business counterparties; transportation capacity constraints and interruptions that could adversely affect our cash flow; 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 requires natural gas and oil companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of natural gas and oil that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.  In this press release, we use the terms "risked and unrisked unproved resources" and "estimated average resources per well" to describe Chesapeake’s internal estimates of volumes of natural gas and oil that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques.  These are broader descriptions of potentially recoverable volumes than probable and possible reserves, as defined by SEC regulations.  Estimates of risked and unrisked unproved resources 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.  We believe our estimates of unproved resources are reasonable, but such estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.

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.  Year-end standardized measure calculations are provided in the financial statement notes in our annual reports on Form 10-K. 

Chesapeake Energy Corporation is one of the largest producers of natural gas and the most active driller of new wells in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S. Chesapeake owns leading positions in the Barnett, Fayetteville, Haynesville, Marcellus and Bossier natural gas shale plays and in the Eagle Ford, Granite Wash and various other unconventional oil plays. The company has also vertically integrated its operations and owns substantial midstream, compression, drilling and oilfield service assets. Further information is available at www.chk.com.

 

CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF 2010 FIRST HALF ADDITIONS TO NATURAL GAS AND OIL PROPERTIES
BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES
($ in millions, except per-unit data)
(unaudited)
  Proved
Reserves
  Cost   Bcfe(a)   $/mcfe
Drilling and completion costs(b) $
2,306
2,654
(c) 
0.87
Acquisition of proved properties
76
35
2.18
Sale of proved properties
(1,716)
(1,118)
1.53
Drilling, completion and net acquisition costs
666
1,571
0.42
Revisions – price
121
Acquisition of unproved properties and leasehold
2,356
Sale of unproved properties and leasehold
(200)
Net unproved properties and leasehold acquisition
2,156
Capitalized interest on leasehold and unproved property
339
Geological and geophysical costs
84
Capitalized interest and geological and geophysical costs
423
Subtotal
3,245
1,692
1.92
Asset retirement obligation and other
(3)
Total costs $
3,242
1,692
1.92
CHESAPEAKE ENERGY CORPORATION
ROLL-FORWARD OF PROVED RESERVES
SIX MONTHS ENDED JUNE 30, 2010
BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES
(unaudited)
  Bcfe (a) 
Beginning balance, 1/01/10
14,254
Production
(487
)
Acquisitions
35
Divestitures
(1,118
)
Revisions – changes to previous estimates
428
Revisions – price
121
Extensions and discoveries
2,226
Ending balance, 6/30/10
15,459
Proved reserves growth rate
8.5
%
Proved developed reserves
8,388
Proved developed reserves percentage 54 %
Reserve replacement
1,692
Reserve replacement ratio(d)
348
%

(a)Reserve volumes estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of June 2010 of $4.10 per mcf of natural gas and $75.78 per bbl of oil, before field differential adjustments.

(b)Includes drilling and completion carries associated with the Statoil and Total joint ventures.

(c)Includes 428 bcfe of positive revisions resulting from changes to previous estimates and excludes positive revisions of 121 bcfe resulting from higher natural gas and oil prices using the average first-day-of-the-month price for the twelve months ended June 2010 compared to the twelve months ended December 2009.

(d)The company uses the reserve replacement ratio as an indicator of the company’s ability to replenish annual production volumes and grow its reserves.  It should be noted that the reserve replacement ratio is a statistical indicator that has limitations.  The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions.  Its predictive and comparative value is also limited for the same reasons.  In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

 

CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF 2010 FIRST HALF ADDITIONS TO NATURAL GAS AND OIL PROPERTIES
BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT JUNE 30, 2010
($ in millions, except per-unit data)
(unaudited)
  Proved
Reserves
  Cost   Bcfe(a)   $/mcfe
Drilling and completion costs(b) $
2,306
2,366
(c)
0.97
Acquisition of proved properties
76
35
2.17
Sale of proved properties
(1,716)
(1,186)
1.45
Drilling, completion and net acquisition costs
666
1,215
0.55
Revisions – price
(122)
Acquisition of unproved properties and leasehold
2,356
Sale of unproved properties and leasehold
(200)
Net unproved properties and leasehold acquisition
2,156
Capitalized interest on leasehold and unproved property
339
Geological and geophysical costs
84
Capitalized interest and geological and geophysical costs
423
Subtotal
3,245
1,093
2.97
Asset retirement obligation and other
(3)
Total costs $
3,242
1,093
2.97
CHESAPEAKE ENERGY CORPORATION
ROLL-FORWARD OF PROVED RESERVES
SIX MONTHS ENDED JUNE 30, 2010
BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT JUNE 30, 2010
(unaudited)
  Bcfe (a) 
Beginning balance, 1/01/10
15,540
Production
(487
)
Acquisitions
35
Divestitures
(1,186
)
Revisions – changes to previous estimates
108
Revisions – price
(122
)
Extensions and discoveries
2,258
Ending balance, 6/30/10
16,146
Proved reserves annual growth rate
3.9
%
Proved developed reserves
8,838
Proved developed reserves percentage
55
%
Reserve replacement
1,093
Reserve replacement ratio(d)
225
%

(a)Reserve volumes estimated using SEC reserve recognition standards and 10-year average NYMEX strip prices as of June 30, 2010 of $6.30 per mcf of natural gas and $84.38 per bbl of oil, before field differential adjustments.  Futures prices, such as the 10-year average NYMEX strip prices, represent an unbiased consensus estimate by market participants about the likely prices to be received for our future production.  Chesapeake uses such forward-looking market-based data in developing its drilling plans, assessing its capital expenditure needs and projecting future cash flows.  Chesapeake believes these prices are better indicators of the likely economic producibility of proved reserves than the trailing 12-month average price required by the SEC's reporting rule. 

(b)Includes drilling and completion carries associated with the Statoil and Total joint ventures.

(c)Includes 108 bcfe of positive revisions resulting from changes to previous estimates and excludes downward revisions of 122 bcfe resulting from lower natural gas and oil prices using 10-year average NYMEX strip prices as of June 30, 2010 compared to NYMEX strip prices as of December 31, 2009.

(d) The company uses the reserve replacement ratio as an indicator of the company’s ability to replenish annual production volumes and grow its reserves.  It should be noted that the reserve replacement ratio is a statistical indicator that has limitations.  The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions.  Its predictive and comparative value is also limited for the same reasons.  In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

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