chk08032010

0000895126-10-000154.txt : 20100804 0000895126-10-000154.hdr.sgml : 20100804 20100803184100 ACCESSION NUMBER: 0000895126-10-000154 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20100802 ITEM INFORMATION: Results of Operations and Financial Condition ITEM INFORMATION: Financial Statements and Exhibits FILED AS OF DATE: 20100804 DATE AS OF CHANGE: 20100803 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CHESAPEAKE ENERGY CORP CENTRAL INDEX KEY: 0000895126 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 731395733 STATE OF INCORPORATION: OK FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-13726 FILM NUMBER: 10989009 BUSINESS ADDRESS: STREET 1: 6100 N WESTERN AVE CITY: OKLAHOMA CITY STATE: OK ZIP: 73118 BUSINESS PHONE: 4058488000 MAIL ADDRESS: STREET 1: 6100 NORTH WESTERN AVE CITY: OKLAHOMA CITY STATE: OK ZIP: 73118 8-K 1 chk08032010_8k.htm CURRENT REPORT chk08032010_8k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 2, 2010

CHESAPEAKE ENERGY CORPORATION

(Exact name of Registrant as specified in its Charter)

Oklahoma		1-13726		73-1395733
(State or other jurisdiction of incorporation)		(Commission File No.)		(IRS Employer Identification No.)

6100 North Western Avenue, Oklahoma City, Oklahoma		73118
(Address of principal executive offices)		(Zip Code)

	(405) 848-8000
	(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

* Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

* Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

* Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

* Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 2 – Financial Information

Item 2.02 – Results of Operations and Financial Condition

On August 2, 2010, Chesapeake Energy Corporation (the “Company”) issued a press release providing an operational update for the 2010 second quarter. A copy of the press release is attached herewith as Exhibit 99.1 to this Current Report.

On August 3, 2010, the Company issued a press release reporting our financial and operational results for the 2010 second quarter and an updated outlook for 2010 and 2011. The press release also provided information for accessing a related conference call. A copy of the press release is attached herewith as Exhibit 99.2 to this Current Report.

Section 8 – Other Events

Item 8.01 Other Events.

On August 3, 2010, the Company issued a press release announcing cash tender offers and consent solicitations for any and all of its outstanding 7.00% Senior Notes due 2014, 6.625% Senior Notes due 2016 and 6.25% Senior Notes due 2018. A copy of the press release is attached herewith as Exhibit 99.3 to this Current Report.

Section 9 – Financial Statements and Exhibits

Item 9.01 Financial Statements and Exhibits

(d) Exhibits. See "Index to Exhibits" attached to this Current Report on Form 8-K, which is incorporated by reference herein.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	CHESAPEAKE ENERGY CORPORATION

	By:	/s/ JENNIFER M. GRIGSBY
		Jennifer M. Grigsby
		Senior Vice President, Treasurer and Corporate Secretary

Date: August 3, 2010

EXHIBIT INDEX

Exhibit No.		Document Description

99.1		Chesapeake Energy Corporation press release dated August 2, 2010 Operational Update

99.2		Chesapeake Energy Corporation press release dated August 3, 2010 Financial and Operational Results

99.3		Chesapeake Energy Corporation press release dated August 3, 2010 Tender Offer and Consent Solicitations

EX-99.1 2 chk08032010_991.htm PRESS RELEASE - AUGUST 2, 2010 OPERATIONAL RELEASE chk08032010_991.htm

Exhibit 99.1

N e w s R e l e a s e

Chesapeake Energy Corporation

P. O. Box 18496

Oklahoma City, OK 73154

FOR IMMEDIATE RELEASE

AUGUST 2, 2010

INVESTOR CONTACTS:	MEDIA CONTACT:
JEFFREY L. MOBLEY, CFA (405) 767-4763 jeff.mobley@chk.com JOHN J. KILGALLON (405) 935-4441 john.kilgallon@chk.com	JIM GIPSON (405) 935-1310 jim.gipson@chk.com

CHESAPEAKE ENERGY CORPORATION PROVIDES QUARTERLY

OPERATIONAL UPDATE

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 liqui ds 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

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 rais ed 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 compl etion 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 r eceived 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 r igs 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 app roximately 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 201 0 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 approximately 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 availab le 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 timi ng 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 descripti ons 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)

EX-99.2 3 chk08032010_992.htm PRESS RELESE - AUGUST 3, 2010 EARNINGS RELEASE chk08032010_992.htm

Exhibit 99.2

N e w s R e l e a s e

Chesapeake Energy Corporation

P. O. Box 18496

Oklahoma City, OK 73154

FOR IMMEDIATE RELEASE

AUGUST 3, 2010

INVESTOR CONTACTS:	MEDIA CONTACT:
JEFFREY L. MOBLEY, CFA (405) 767-4763 jeff.mobley@chk.com JOHN J. KILGALLON (405) 935-4441 john.kilgallon@chk.com	JIM GIPSON (405) 935-1310 jim.gipson@chk.com

CHESAPEAKE ENERGY CORPORATION REPORTS FINANCIAL RESULTS

FOR THE 2010 SECOND QUARTER

Company Reports 2010 Second Quarter Net Income to Common Stockholders of

$235 Million, or $0.37 per Fully Diluted Common Share, on Revenue of $2.0 Billion;

Company Reports Adjusted Net Income Available to Common Stockholders of

$491 Million, or $0.75 per Fully Diluted Common Share, Adjusted Ebitda

of $1.3 Billion and Operating Cash Flow of $1.1 Billion

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 Total Realized Production Revenue

Company Provides Update on its Strategic and Financial Plan to Reduce

Capital Expenditures on Natural Gas Plays, Increase Capital Expenditures

on Liquids-Rich Plays, Monetize Assets and Reduce Debt

OKLAHOMA CITY, OKLAHOMA, AUGUST 3, 2010 – Chesapeake Energy Corporation (NYSE:CHK) today announced financial results for the 2010 second quarter. For the 2010 second quarter, Chesapeake reported net income to common stockholders of $235 million ($0.37 per fully diluted common share), operating cash flow of $1.127 billion (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $791 million (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization) on revenue of $2.012 billion and production of 254 billion cubic feet of natural gas equivalent (bcfe).

The company’s 2010 second quarter results 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, for the 2010 second quarter, Chesapeake reported adjusted net income to common stockholders of $491 million ($0.75 per fully diluted common share) and adjusted ebitda of $1.256 billion. The excluded items and their effects on 2010 second quarter reported results are detailed as follows:

·	a non-cash unrealized after-tax mark-to-market loss of $214 million resulting from the company’s natural gas, oil and interest rate hedging programs; and

·	an after-tax charge of $42 million related to the redemption of certain of the company’s senior notes.

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 12 – 16 of this release.

Key Operational and Financial Statistics Summarized

The table below summarizes Chesapeake’s key results during the 2010 second quarter and compares them to results during the 2010 first quarter and the 2009 second quarter.

		Three Months Ended
		6/30/10		3/31/10		6/30/09
Average daily production (in mmcfe) (a)			2,789		2,586		2,453
Natural gas as % of total production			90		90		92
Natural gas production (in bcf)			227.2		209.6		204.3
Average realized natural gas price ($/mcf) (b)			5.66		6.31		5.56
Oil and NGL production (in mbbls)			4,429		3,871		3,152
Average realized oil and NGL price ($/bbl) (b)			61.43		67.70		56.72
Natural gas equivalent production (in bcfe)			253.8		232.8		223.2
Natural gas equivalent realized price ($/mcfe) (b)			6.14		6.80		5.89
Marketing, gathering and compression net margin($/mcfe)			.12		.12		.14
Service operations income ($/mcfe)			.02		.03		(.01)
Production expenses ($/mcfe)			(.84)		(.89)		(.95)
Production taxes ($/mcfe)			(.15)		(.21)		(.11)
General and administrative costs ($/mcfe) (c)			(.34)		(.38)		(.25)
Stock-based compensation ($/mcfe)			(.08)		(.09)		(.09)
DD&A of natural gas and oil properties ($/mcfe)			(1.34)		(1.32)		(1.32)
D&A of other assets ($/mcfe)			(.21)		(.21)		(.26)
Interest expense ($/mcfe) (b)			(.13)		(.22)		(.29)
Operating cash flow ($ in millions) (d)			1,127		1,166		1,006
Operating cash flow ($/mcfe)			4.44		5.01		4.51
Adjusted ebitda ($ in millions) (e)			1,256		1,270		1,030
Adjusted ebitda ($/mcfe)			4.95		5.46		4.62
Net income to common stockholders ($ in millions)			235		733		237
Earnings per share – assuming dilution ($)			.37		1.14		.39
Adjusted net income to common stockholders ($ in millions) (f)			491		524		377
Adjusted earnings per share – assuming dilution ($)			.75		.82		.62

(a)	2010 production reflects the sale of a 25% joint venture interest in the company’s Barnett Shale assets on January 25, 2010 (averaging approximately 124 mmcfe per day and 174 mmcfe per day during the 2010 first and second quarters, respectively), the company’s sixth volumetric production payment transaction on February 5, 2010 (averaging approximately 14 mmcfe per day and 22 mmcfe per day during the 2010 first and second quarters, respectively), the company’s seventh volumetric production payment transaction on June 14, 2010 (averaging approximately 5 mmcfe per day during the 2010 second quarter) and the sale of producing properties in Virginia and in the Permian Basin in the 2010 second quarter (averaging approximately 20 mmcfe per day during the 2010 second quarter)
(b)	Includes the effects of realized gains (losses) from hedging, but does not include the effects of unrealized gains (losses) from hedging
(c)	Excludes expenses associated with non-cash stock-based compensation
(d)	Defined as cash flow provided by operating activities before changes in assets and liabilities
(e)	Defined as net income (loss) before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 14
(f)	Defined as net income (loss) available to common stockholders, as adjusted to remove the effects of certain items detailed on page 15

2010 Second Quarter Average Daily Production of 2.789 Bcfe per Day Increases 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

As announced on August 2, 2010, Chesapeake’s daily production for the 2010 second quarter averaged 2.789 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 NGL (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.

Average Realized Prices, Hedging Results and Hedging Positions Detailed

Average prices realized during the 2010 second quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.66 per thousand cubic feet (mcf) and $61.43 per bbl, for a realized natural gas equivalent price of $6.14 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains from natural gas and oil hedging activities during the 2010 second quarter generated a $2.43 gain per mcf and a $4.85 gain per bbl, for a 2010 second quarter realized hedging gain of $573 million, or $2.26 per mcfe.

By comparison, average prices realized during the 2009 second quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.56 per mcf and $56.72 per bbl, for a realized natural gas equivalent price of $5.89 per mcfe. Realized gains from natural gas and oil hedging activities during the 2009 second quarter generated a $2.88 gain per mcf and a $3.13 gain per bbl, for a 2009 second quarter realized hedging gain of $597 million, or $2.68 per mcfe.

The following tables summarize Chesapeake’s 2010 and 2011 open hedge positions through swaps and collars as of August 3, 2010. 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.

Open Swap Positions as of August 3, 2010

	Natural Gas		Oil
Year	% Hedged	$ NYMEX	% Hedged	$ NYMEX
2010	51%	7.58	43%	89.62

2011	30%	7.39	10%	96.09

Open Natural Gas Collar Positions as of August 3, 2010

		Average Floor	Average Ceiling
Year	% Hedged	$ NYMEX	$ NYMEX
2010	2%	7.60	11.75

2011	1%	7.70	11.50

As of July 30, 2010, Chesapeake’s natural gas and oil hedging positions with its 14 different counterparties had a positive mark-to-market value of approximately $110 million. The company’s natural gas and oil realized hedging gains for the first six months of 2010 were $972 million and since January 1, 2001 have been $5.4 billion.

The company’s updated forecasts and hedging positions for 2010 and 2011 are attached to this release in an Outlook dated August 3, 2010, labeled as Schedule “A,” which begins on page 17. This Outlook has been changed from the Outlook dated May 4, 2010, attached as Schedule “B,” which begins on page 21, to reflect various updated information.

Company Provides Update on its Strategic and Financial Plan to Reduce

Capital Expenditures on Natural Gas Plays, Increase Capital Expenditures

on Liquids-Rich Plays, Monetize Assets and Reduce Debt

Chesapeake has accomplished multiple parts of its strategic and financial plan outlined on May 10, 2010. During the 2010 second quarter, the company issued $2.6 billion of convertible preferred stock, called for redemption $1.9 billion of senior notes and sold approximately $750 million of leasehold and producing properties. The asset sales included the company’s seventh volumetric production payment (VPP) for proceeds of approximately $335 million, or $8.73 per mcfe of proved reserves, and producing properties and gathering assets in Virginia and in the Permian Basin for proceeds of approximately $330 million, or $1.70 per mcfe.

During the 2010 first half, the company reduced its net debt to total book capitalization ratio and its net debt per proved reserve ratio from 49% and $0.84 per mcfe, respectively, at December 31, 2009 to 40% and $0.64 per mcfe, respectively, at June 30, 2010 – reductions of 18% and 24% in just six months. The company remains committed to achieving investment grade credit metrics by no later than year-end 2012.

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. Chesapeake’s goal is to reach a balanced mix of natural gas and liquids revenue as quickly as possible through organic drilling, rather than through acquisitions, at very low per net acre leasehold acquisition costs and low drilling and completion costs. Having successfully established itself during the past five years as the industry leader in finding, developing, monetizing and producing unconventiona l natural gas plays, Chesapeake is now focused on achieving the same leadership position in unconventional liquids-rich plays. The company believes that doing so during a period of much higher value for oil and NGLs compared to natural gas will significantly enhance the company’s already strong profitability and returns on invested capital.

Chesapeake’s strategy to accomplish this goal is set forth below:

·	Reduce drilling of natural gas wells except for those required to hold by production (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.

Accordingly, 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%

During the 2010 first half, Chesapeake invested heavily in new leasehold acquisitions in various liquids-rich plays, including: the Anadarko Basin’s Granite Wash, Cleveland, Tonkawa and Mississippian plays; the Permian Basin’s Wolfcamp, Bone Spring, Avalon and Wolfberry plays; the Eagle Ford Shale in South Texas; the Niobrara Shale in the Powder River and DJ Basins; the Frontier Sand in the Powder River Basin; and various other new plays the company is not yet ready to discuss.

During the 2010 second half and throughout 2011, the company will focus on recapturing a significant portion of these new leasehold expenditures through joint ventures in several of its new liquids-rich plays. The first of these is expected to be a joint venture in the Eagle Ford Shale that the company expects to announce in the 2010 third quarter. Further joint ventures are planned for later in 2010 or in early 2011. Other anticipated significant asset monetizations during the second half of 2010 and the first half of 2011 include a volumetric production payment, a Marcellus Shale subsidiary equity investment, a midstream asset sale and various other smaller planned monetizations. In total, Chesapeake is targeting proceeds of approximately $3.0 - 3.5 billion in the 2010 second half and appro ximately $2.5 - 3.0 billion in 2011 from asset monetizations, which will enable the company to further reduce its debt and accelerate drilling on its unconventional liquids-rich plays.

Conference Call Information

A conference call to discuss this release of financial results and the company's release of its operational results issued on August 2, 2010 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 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 expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, planned drilling activity, drilling and completion costs and anticipated asset sales, projected 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.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in millions, except per-share and unit data)

(unaudited)

THREE MONTHS ENDED:	June 30,				June 30,
THREE MONTHS ENDED:	2010				2009
	$		$/mcfe		$		$/mcfe
REVENUES:
Natural gas and oil sales		1,161		4.57		1,097		4.92
Marketing, gathering and compression sales		793		3.13		532		2.38
Service operations revenue		58		0.23		44		0.20
Total Revenues		2,012		7.93		1,673		7.50

OPERATING COSTS:
Production expenses		213		0.84		213		0.95
Production taxes		37		0.15		24		0.11
General and administrative expenses		106		0.41		74		0.33
Marketing, gathering and compression expenses		763		3.01		500		2.24
Service operations expense		53		0.21		46		0.21
Natural gas and oil depreciation, depletion and amortization		340		1.34		295		1.32
Depreciation and amortization of other assets		53		0.21		58		0.26
Impairment of other assets		—		—		5		0.02
Restructuring costs		—		—		34		0.16
Total Operating Costs		1,565		6.17		1,249		5.60

INCOME FROM OPERATIONS		447		1.76		424		1.90

OTHER INCOME (EXPENSE):
Other income (expense)		20		0.08		(2)		(0.01)
Interest income (expense)		16		0.06		(22)		(0.10)
Impairment of investments		—		—		(10)		(0.04)
Loss on redemptions or exchanges of Chesapeake debt		(69)		(0.270		(2)		(0.01)
Total Other Income (Expense)		(33)		(0.13)		(36)		(0.16)

INCOME BEFORE INCOME TAXES		414		1.63		388		1.74

Income Tax Expense:
Current income taxes		5		0.02		1		—
Deferred income taxes		154		0.61		144		0.65
Total Income Tax Expense		159		0.63		145		0.65

NET INCOME		255		1.00		243		1.09

Preferred stock dividends		(20)		(0.07)		(6)		(0.03)

NET INCOME AVAILABLE TO CHESAPEAKE COMMON STOCKHOLDERS		235		0.93		237		1.06

EARNINGS PER COMMON SHARE:
Basic	$	0.37			$	0.39
Diluted	$	0.37			$	0.39

WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)
Basic		631				603
Diluted		635				610

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in millions, except per-share and unit data)

(unaudited)

SIX MONTHS ENDED:	June 30,			June 30,
SIX MONTHS ENDED:	2010			2009
	$		$/mcfe	$		$/mcfe
REVENUES:
Natural gas and oil sales		3,059	6.29		2,494	5.72
Marketing, gathering and compression sales		1,637	3.36		1,084	2.49
Service operations revenue		114	0.24		90	0.20
Total Revenues		4,810	9.89		3,668	8.41

OPERATING COSTS:
Production expenses		421	0.86		451	1.03
Production taxes		85	0.18		46	0.11
General and administrative expenses		215	0.44		164	0.38
Marketing, gathering and compression expenses		1,578	3.24		1,023	2.35
Service operations expense		102	0.21		87	0.20
Natural gas and oil depreciation, depletion and amortization		647	1.33		742	1.70
Depreciation and amortization of other assets		103	0.21		115	0.26
Impairment of natural gas and oil properties and other assets		—	—		9,635	22.08
Restructuring costs		—	—		34	0.08
Total Operating Costs		3,151	6.47		12,297	28.19

INCOME (LOSS) FROM OPERATIONS		1,659	3.42		(8,629)	(19.78)

OTHER INCOME (EXPENSE):
Other income (expense)		35	0.07		5	0.01
Interest expense		(9)	(0.02)		(8)	(0.02)
Impairment of investments		—	—		(162)	(0.37)
Loss on redemptions or exchanges of Chesapeake debt		(71)	(0.15)		(2)	—
Total Other Income (Expense)		(45)	(0.10)		(167)	(0.38)

INCOME (LOSS) BEFORE INCOME TAXES		1,614	3.32		(8,796)	(20.16)

Income Tax Expense (Benefit):
Current income taxes		5	0.01		1	—
Deferred income taxes		616	1.27		(3,299)	(7.56)
Total Income Tax Expense (Benefit)		621	1.28		(3,298)	(7.56)

NET INCOME (LOSS)		993	2.04		(5,498)	(12.60)

Preferred stock dividends		(25)	(0.05)		(12)	(0.03)

NET INCOME (LOSS) AVAILABLE TO CHESAPEAKE COMMON STOCKHOLDERS		968	1.99		(5,510)	(12.63)

EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	1.54		$	(9.18)
Diluted	$	1.49		$	(9.18)

WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)
Basic		630			600
Diluted		665			600

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)

	June 30,		December 31,
	2010		2009

Cash and cash equivalents	$	601	$	307
Other current assets		2,417		2,139
Total Current Assets		3,018		2,446

Property and equipment (net)		27,830		26,710
Other assets		1,321		758
Total Assets	$	32,169	$	29,914

Current liabilities	$	3,655	$	2,688
Long-term debt, net (a)		10,501		12,295
Asset retirement obligations		285		282
Other long-term liabilities		1,367		1,249
Deferred tax liability		1,546		1,059
Total Liabilities		17,354		17,573

Chesapeake stockholders’ equity		14,815		11,444
Noncontrolling interest(b)		—		897
Total Equity		14,815		12,341

Total Liabilities & Equity	$	32,169	$	29,914

Common Shares Outstanding (in millions)		651		648

CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

($ in millions)

(unaudited)

	June 30,			% of Total Book	December 31,			% of Total Book
	2010			Capitalization	2009			Capitalization

Total debt, net of cash (a)		$	9,900	40%		$	11,988	49%
Chesapeake stockholders' equity			14,815	60%			11,444	47%
Noncontrolling interest (b)			—	—			897	4%
Total		$	24,715	100%		$	24,329	100%

(a)	At June 30, 2010, includes $1.521 billion of combined borrowings under the company’s $3.5 billion revolving bank credit facility and the company’s $250 million midstream revolving bank credit facility. At June 30, 2010, the company had $2.215 billion of additional borrowing capacity under these two revolving bank credit facilities.
(b)	Effective January 1, 2010, we no longer consolidate the company’s midstream joint venture and consequently no longer report a noncontrolling interest related to this investment.

CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA – NATURAL GAS AND OIL SALES AND INTEREST EXPENSE

(unaudited)

	THREE MONTHS ENDED				SIX MONTHS ENDED
	JUNE 30,				JUNE 30,
	2010		2009		2010		2009

Natural Gas and Oil Sales ($ in millions):
Natural gas sales	$	733	$	548	$	1,676	$	1,223
Natural gas derivatives – realized gains		552		587		931		1,096
Natural gas derivatives – unrealized gains (losses)		(195)		(192)		219		(123)

Total Natural Gas Sales		1,090		943		2,826		2,196

Oil sales		251		169		493		272
Oil derivatives – realized gains (losses)		21		10		41		19
Oil derivatives – unrealized gains (losses)		(201 )		(25 )		(301)		7

Total Oil Sales		71		154		233		298

Total Natural Gas and Oil Sales	$	1,161	$	1,097	$	3,059	$	2,494

Average Sales Price – excluding gains (losses) on derivatives:
Natural gas ($ per mcf)	$	3.23	$	2.68	$	3.84	$	3.06
Oil ($ per bbl)	$	56.58	$	53.59	$	59.38	$	45.19
Natural gas equivalent ($ per mcfe)	$	3.88	$	3.21	$	4.46	$	3.43

Average Sales Price – excluding unrealized gains (losses) on derivatives:
Natural gas ($ per mcf)	$	5.66	$	5.56	$	5.97	$	5.80
Oil ($ per bbl)	$	61.43	$	56.72	$	64.35	$	48.32
Natural gas equivalent ($ per mcfe)	$	6.14	$	5.89	$	6.46	$	5.98

Interest Expense (Income) ($ in millions):
Interest	$	35	$	69	$	90	$	107
Derivatives – realized gains		(2 )		(5 )		(4 )		(12 )
Derivatives – unrealized gains		(49 )		(42 )		(77 )		(87 )
Total Interest Expense (Income)	$	(16)	$	22	$	9	$	8

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

($ in millions)

(unaudited)

THREE MONTHS ENDED:		June 30,		June 30,
THREE MONTHS ENDED:		2010		2009

Beginning cash	$	516	$	83
Cash provided by operating activities	$	1,795	$	737
Cash (used in) provided by investing activities:
Exploration and development of natural gas and oil properties	$	(1,311)	$	(753)
Acquisitions of natural gas and oil companies, proved and unproved properties and leasehold, net of cash acquired		(1,825)		(305)
Divestitures of proved and unproved properties, leasehold and VPPs		688		228
Investments, net		(103)		10
Other property and equipment, net		(150)		(277)
Other		(17)		(1)
Total cash (used in) investing activities	$	(2,718)	$	(1,098)
Cash provided by financing activities	$	1,008	$	832
Ending cash	$	601	$	554

SIX MONTHS ENDED:		June 30,		June 30,
SIX MONTHS ENDED:		2010		2009

Beginning cash	$	307	$	1,749
Cash provided by operating activities	$	2,978	$	1,998
Cash (used in) provided by investing activities:
Exploration and development of natural gas and oil properties	$	(2,331)	$	(2,108)
Acquisitions of natural gas and oil companies, proved and unproved properties and leasehold, net of cash acquired		(2,855)		(710)
Divestitures of proved and unproved properties, leasehold and VPPs		1,933		228
Investments, net		(109)		2
Other property and equipment, net		(373)		(876)
Other		3		(1)
Total cash (used in) investing activities	$	(3,732)	$	(3,465)
Cash provided by financing activities	$	1,048	$	272
Ending cash	$	601	$	554

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)

THREE MONTHS ENDED:	June 30,		March 31,		June 30,
THREE MONTHS ENDED:	2010		2010		2009

CASH PROVIDED BY OPERATING ACTIVITIES	$	1,795	$	1,183	$	737

Changes in assets and liabilities		(668)		(17)		269

OPERATING CASH FLOW (a)	$	1,127	$	1,166	$	1,006

THREE MONTHS ENDED:	June 30,		March 31,		June 30,
THREE MONTHS ENDED:	2010		2010		2009

NET INCOME (LOSS)	$	255	$	738	$	243

Income tax expense (benefit)		159		462		145
Interest expense (income)		(16)		25		22
Depreciation and amortization of other assets		53		50		58
Natural gas and oil depreciation, depletion and amortization		340		308		295

EBITDA (b)	$	791	$	1,583	$	763

THREE MONTHS ENDED:	June 30,		March 31,		June 30,
THREE MONTHS ENDED:	2010		2010		2009

CASH PROVIDED BY OPERATING ACTIVITIES	$	1,795	$	1,183	$	737

Changes in assets and liabilities		(668)		(17)		269
Interest expense (income)		(16)		25		22
Unrealized gains (losses) on natural gas and oil derivatives		(396)		315		(216)
Other items		76		77		(49)

EBITDA (b)	$	791	$	1,583	$	763

(a)

Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial perfor mance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity.

(b)

Ebitda represents net income (loss) before income tax expense, interest expense and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements and our senior note indentures. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)

SIX MONTHS ENDED:	June 30,		June 30,
SIX MONTHS ENDED:	2010		2009

CASH PROVIDED BY OPERATING ACTIVITIES	$	2,978	$	1,998

Changes in assets and liabilities		(684)		7

OPERATING CASH FLOW (a)	$	2,294	$	2,005

SIX MONTHS ENDED:	June 30,		June 30,
SIX MONTHS ENDED:	2010		2009

NET INCOME (LOSS)	$	993	$	(5,498)

Income tax expense (benefit)		621		(3,298)
Interest expense (income)		9		8
Depreciation and amortization of other assets		103		115
Natural gas and oil depreciation, depletion and amortization		647		742

EBITDA (b)	$	2,373	$	(7,931)

SIX MONTHS ENDED:	June 30,		June 30,
SIX MONTHS ENDED:	2010		2009

CASH PROVIDED BY OPERATING ACTIVITIES	$	2,978	$	1,998

Changes in assets and liabilities		(684)		7
Interest expense (income)		9		8
Unrealized gains (losses) on natural gas and oil derivatives		(82)		(116)
Impairment of natural gas and oil properties and other assets		—		(9,635)
Other items		152		(193)

EBITDA (b)	$	2,373	$	(7,931)

(a)

(b)

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED EBITDA

($ in millions)

(unaudited)

	June 30,		March 31,		June 30,
THREE MONTHS ENDED:	2010		2010		2009

EBITDA	$	791	$	1,583	$	763

Adjustments:
Unrealized (gains) losses on natural gas and oil derivatives		396		(315)		216
Loss on redemptions or exchanges of Chesapeake debt		69		2		2
Impairment of other assets		—		—		5
Impairment of investments		—		—		10
Restructuring costs		—		—		34

Adjusted EBITDA (a)	$	1,256	$	1,270	$	1,030

(a)	Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to ebitda because:
	i.	Management uses adjusted ebitda to evaluate the company’s operational trends and performance relative to other natural gas and oil producing companies.
	ii.	Adjusted ebitda is more comparable to estimates provided by securities analysts.
	iii.	Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

	June 30,		June 30,
SIX MONTHS ENDED:	2010		2009

EBITDA	$	2,373	$	(7,931)

Adjustments:
Unrealized (gains) losses on natural gas and oil derivatives		82		116
Loss on redemptions or exchanges of Chesapeake debt		71		2
Impairment of natural gas and oil properties and other assets		—		9,635
Impairment of investments		—		162
Restructuring costs		—		34

Adjusted EBITDA (a)	$	2,526	$	2,018

(a)	Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to ebitda because:
	i.	Management uses adjusted ebitda to evaluate the company’s operational trends and performance relative to other natural gas and oil producing companies.
	ii.	Adjusted ebitda is more comparable to estimates provided by securities analysts.
	iii.	Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS

($ in millions, except per-share data)

(unaudited)

	June 30,		March 31,		June 30,
THREE MONTHS ENDED:	2010		2010		2009

Net income available to Chesapeake common stockholders	$	235		733	$	237

Adjustments:
Unrealized (gains) losses on derivatives, net of tax		214		(210)		109
Loss on redemptions or exchanges of Chesapeake debt, net of tax		42		1		1
Impairment of other assets, net of tax		—		—		3
Impairment of investments, net of tax		—		—		6
Restructuring costs, net of tax		—		—		21

Adjusted net income available to Chesapeake common stockholders (a)		491		524		377
Preferred stock dividends		20		6		6
Total adjusted net income	$	511	$	530	$	383

Weighted average fully diluted shares outstanding (b)		682		647		622

Adjusted earnings per share assuming dilution(a)	$	0.75	$	0.82	$	0.62

(a)	Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:
	i.	Management uses adjusted net income available to common stockholders to evaluate the company’s operational trends and performance relative to other natural gas and oil producing companies.
	ii.	Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts.
	iii.	Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.
(b)	Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS

($ in millions, except per-share data)

(unaudited)

	June 30,		June 30,
SIX MONTHS ENDED:	2010		2009

Net income (loss) available to Chesapeake common stockholders	$	968	$	(5,510)

Adjustments:
Unrealized (gains) losses on derivatives, net of tax		3		19
Loss on redemptions or exchanges of Chesapeake debt, net of tax		44		1
Impairment of natural gas and oil properties and other assets, net of tax		—		6,022
Impairment of investments, net of tax		—		102
Restructuring costs, net of tax		—		21

Adjusted net income available to Chesapeake common stockholders (a)		1,015		655
Preferred stock dividends		25		12
Total adjusted net income	$	1,040	$	667

Weighted average fully diluted shares outstanding (b)		665		618

Adjusted earnings per share assuming dilution(a)	$	1.56	$	1.08

(a)	Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:
	i.	Management uses adjusted net income available to common stockholders to evaluate the company’s operational trends and performance relative to other natural gas and oil producing companies.
	ii.	Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts.
	iii.	Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.
(b)	Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

SCHEDULE “A”

CHESAPEAKE’S OUTLOOK AS OF AUGUST 3, 2010

Years Ending December 31, 2010 and 2011

Our policy is to periodically provide guidance on certain factors that affect our future financial performance. As of August 3, 2010, we are using the following key assumptions in our projections for 2010 and 2011.

The primary changes from our May 4, 2010 Outlook are in italicized bold and are explained as follows:

1)	Our production guidance has been increased;

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

3)	Equivalent shares outstanding and interest expense has been updated to reflect our private placement of $2.6 billion of preferred stock and the calling and subsequent repayment of certain senior notes; and

4)	Our cash flow projections and drilling and completion capital expenditures have been updated.

	Year Ending 12/31/2010	Year Ending 12/31/2011
Estimated Production:
Natural gas – bcf	898 – 918	990 – 1,010
Oil – mbbls	19,000	34,000
Natural gas equivalent – bcfe	1,012 – 1,032	1,194 – 1,214

Daily natural gas equivalent midpoint – mmcfe	2,800	3,300

Year-over-year (YOY) estimated production increase	12 – 14%	17 – 19%
YOY estimated production increase excluding asset sales	20 – 22%	19 – 21%

NYMEX Price(a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$4.97	$5.50
Oil - $/bbl	$79.19	$80.00

Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$1.88	$0.62
Oil - $/bbl	$3.98	$2.81

Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	15 – 20%	15 – 20%
Oil - $/bbl	20 – 25%	20 – 25%

Operating Costs per Mcfe of Projected Production:
Production expense	$0.85 – 0.95	$0.85 – 0.95
Production taxes (~ 5% of O&G revenues)	$0.25 – 0.30	$0.25 – 0.30
General and administrative(b)	$0.30 – 0.35	$0.30 – 0.35
Stock-based compensation (non-cash)	$0.09 – 0.11	$0.09 – 0.11
DD&A of natural gas and oil assets	$1.35 – 1.55	$1.35 – 1.55
Depreciation of other assets	$0.20 – 0.25	$0.20 – 0.25
Interest expense(c)	$0.15 – 0.20	$0.20 – 0.25

Other Income per Mcfe:
Marketing, gathering and compression net margin	$0.09 – 0.11	$0.09 – 0.11
Service operations net margin	$0.02 – 0.04	$0.02 – 0.04
Other income (including equity investments)	$0.06 – 0.08	$0.06 – 0.08

Book Tax Rate (all deferred)	38.5%	38.5%

Equivalent Shares Outstanding (in millions):
Basic	630 – 635	640 – 645
Diluted	705 – 710	750 – 755

Operating cash flow before changes in assets and liabilities(d)(e)	$4,900 – 5,000	$5,000 – 5,600
Drilling and completion costs, net of joint venture carries	($4,500 – 4,600)	($4,500 – 4,600)
Note: refer to footnotes on following page

(a)	NYMEX natural gas prices have been updated for actual contract prices through August 2010 and NYMEX oil prices have been updated for actual contract prices through June 2010.

(b)	Excludes expenses associated with noncash stock compensation.

(c)	Does not include gains or losses on interest rate derivatives.

(d)	A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.

(e)	Assumes NYMEX prices of $5.00 to $6.00 per mcf and $80.00 per bbl in 2010 and in 2011.

At June 30, 2010, the company had approximately $2.8 billion of cash and cash equivalents and additional borrowing capacity under its two 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:

1)	Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.
2)	Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call strike price, no payments are due from either party.
3)	Knockout swaps: Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain pre-determined knockout prices.
4)	Call options: Chesapeake sells call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess and if the market price settles below the fixed price of the call option, no payment is due from either party.
5)	Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. For non-Appalachian Basin basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

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. In accordance with generally accepted accounting principles, 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 unrea lized gains (losses) within natural gas and oil sales. 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.

The company currently has the following open natural gas swaps in place for 2010 and 2011 and also has the following gains from lifted natural gas trades:

	Open Swaps (Bcf)	Avg. NYMEX Strike Price of Open Swaps		Assuming Natural Gas Production (Bcf)	Open Swap Positions as a % of Estimated Total Natural Gas Production	Total Gains from Lifted Trades ($ millions)			Total Lifted Gain per Mcf of Estimated Total Natural Gas Production
Q3 2010	119	$	7.46				$	59.1
Q4 2010	120	$	7.70				$	62.1
Q3-Q4 2010(a)	239	$	7.58	472	51%		$	121.2		$	0.26

Total 2011(a)	303	$	7.39	1,000	30%		$	59.6		$	0.06

(a)	Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at prices ranging from $6.50 to $6.75 covering 5 bcf in Q3-Q4 2010 and $5.75 to $6.50 covering 24 bcf in 2011.

The company currently has the following open natural gas collars in place for 2010 and 2011:

	Open Collars (Bcf)	Avg. NYMEX Floor Price		Avg. NYMEX Ceiling Price		Assuming Natural Gas Production (Bcf)	Open Collars as a % of Estimated Total Natural Gas Production
Q3 2010	4	$	7.60	$	11.75
Q4 2010	4	$	7.60	$	11.75
Q3-Q4 2010	8	$	7.60	$	11.75	472	2%

Total 2011	7	$	7.70	$	11.50	1,000	1%

The company currently has the following natural gas written call options in place for 2010 and 2011:

	Call Options (Bcf)	Avg. NYMEX Strike Price		Avg. Premium per mcf		Assuming Natural Gas Production (Bcf)	Call Options as a % of Estimated Total Natural Gas Production
Q3 2010	34	$	10.01	$	1.25
Q4 2010	39	$	10.07	$	1.10
Q3-Q4 2010	73	$	10.04	$	1.17	472	15%

Total 2011	69	$	9.51	$	0.61	1,000	7%

The company has the following natural gas basis protection swaps in place for 2010, 2011 and 2012:

	Non-Appalachia			Appalachia
	Volume (Bcf)	NYMEX less(a)		Volume (Bcf)	NYMEX plus(a)
Q3-Q4 2010	—	$	—	5	$	0.26
2011	45		0.82	12		0.25
2012	43		0.85	—		—
Totals	88	$	0.84	17	$	0.25

(a)	weighted average

The company also has the following crude oil swaps in place for 2010 and 2011:

	Open Swaps (mbbls)	Avg. NYMEX Strike Price		Assuming Oil Production (mbbls)	Open Swap Positions as a % of Estimated Total Oil Production	Total Gains (Losses) from Lifted Trades ($ millions)			Total Lifted Gains (Losses) per bbl of Estimated Total Oil Production
Q3 2010	2,300	$	89.62	—	—	$	(4.1	)		—
Q4 2010	2,300	$	89.62	—	—	$	(4.1	)		—
Q3-Q4 2010(a)	4,600	$	89.62	10,700	43%	$	(8.2	)	$	(0.76	)

Total 2011(a)	3,285	$	96.09	34,000	10%	$	32.9		$	0.96

(a)	Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 2 mmbbls and 1 mmbbls in Q3-Q4 2010 and 2011, respectively.

Note: Not shown above are written call options covering 1 mmbbls of oil production in Q3-Q4 2010 at a weighted average price of $101.25 per bbl for a weighted average discount of $1.93 per bbl and 5 mmbbls of oil production in 2011 at a weighted average price of $88.08 per bbl for a weighted average premium of $3.29 per bbl.

SCHEDULE “B”

CHESAPEAKE’S OUTLOOK AS OF MAY 4, 2010

(PROVIDED FOR REFERENCE ONLY)

NOW SUPERSEDED BY OUTLOOK AS OF AUGUST 3, 2010

Years Ending December 31, 2010 and 2011

Our policy is to periodically provide guidance on certain factors that affect our future financial performance. As of May 4, 2010, we are using the following key assumptions in our projections for 2010 and 2011.

The primary changes from our February 17, 2010 Outlook are in italicized bold and are explained as follows:

1)	Our production guidance has been increased;

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

3)	Equivalent shares outstanding has been updated to reflect exchanges of convertible senior notes; and

4)	Our cash flow projections have been updated, including increased drilling capital expenditures to reflect additional drilling on oil and natural gas liquids rich plays and anticipated cost inflation, partially offset by improved drilling efficiencies.

	Year Ending 12/31/2010	Year Ending 12/31/2011
Estimated Production:
Natural gas – bcf	874 – 894	990 – 1,010
Oil – mbbls	17,000	26,500
Natural gas equivalent – bcfe	976 – 996	1,149 – 1,169

Daily natural gas equivalent midpoint – mmcfe	2,700	3,175

Year-over-year (YOY) estimated production increase	8 – 10%	16 – 18%
YOY estimated production increase excluding asset sales	15 – 17%	17 – 19%

NYMEX Price(a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$5.21	$6.50
Oil - $/bbl	$79.68	$80.00

Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$1.82	$0.33
Oil - $/bbl	$4.05	$3.82

Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	15 – 20%	15 – 20%
Oil - $/bbl	15 – 20%	15 – 20%

Operating Costs per Mcfe of Projected Production:
Production expense	$0.85 – 0.95	$0.85 – 0.95
Production taxes (~ 5% of O&G revenues)	$0.25 – 0.30	$0.30 – 0.35
General and administrative(b)	$0.30 – 0.35	$0.30 – 0.35
Stock-based compensation (non-cash)	$0.09 – 0.11	$0.09 – 0.11
DD&A of natural gas and oil assets	$1.35 – 1.55	$1.35 – 1.55
Depreciation of other assets	$0.20 – 0.25	$0.20 – 0.25
Interest expense(c)	$0.30 – 0.35	$0.30 – 0.35

Other Income per Mcfe:
Marketing, gathering and compression net margin	$0.07 – 0.09	$0.07 – 0.09
Service operations net margin	$0.04 – 0.06	$0.04 – 0.06
Equity in income of midstream joint venture (CMP)	$0.04 – 0.06	$0.04 – 0.06

Book Tax Rate (all deferred)	38.5%	38.5%

Equivalent Shares Outstanding (in millions):
Basic	630 – 635	640 – 645
Diluted	645 – 650	650 – 655

Operating cash flow before changes in assets and liabilities(d)(e)	$4,800 – 4,900	$5,100 – 5,800
Drilling and completion costs(f)	($4,200 – 4,500)	($4,300 – 4,600)
Dividends, capitalized interest, cash income taxes, etc.	($350 – 400)	($500 – 600)
Note: refer to footnotes on following page

(a)	NYMEX natural gas prices have been updated for actual contract prices through May 2010 and NYMEX oil prices have been updated for actual contract prices through March 2010.

(b)	Excludes expenses associated with noncash stock compensation.

(c)	Does not include gains or losses on interest rate derivatives.

(d)	A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.

(e)	Assumes NYMEX prices of $5.00 to $6.00 per mcf and $80.00 per bbl in 2010 and $6.00 to $7.00 per mcf and $80.00 per bbl in 2011.

(f)	Net of drilling carries.

At March 31, 2010, the company had approximately $2.4 billion of cash and cash equivalents and additional borrowing capacity under its two 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:

1)	Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.
2)	Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call strike price, no payments are due from either party. Three-way collars include an additional put option in exchange for a more favorable strike price on the collar. This eliminates the counterparty’s downside exposure below the second put option.
3)	Knockout swaps: Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain pre-determined knockout prices.
4)	Call options: Chesapeake sells call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess and if the market price settles below the fixed price of the call option, no payment is due from either party.
5)	Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. For non-Appalachian Basin basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

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.

The company currently has the following open natural gas swaps in place for 2010 and 2011 and also has the following gains from lifted natural gas trades:

	Open Swaps (Bcf)	Avg. NYMEX Strike Price of Open Swaps		Assuming Natural Gas Production (Bcf)	Open Swap Positions as a % of Estimated Total Natural Gas Production	Total Gains from Lifted Trades ($ millions)			Total Lifted Gain per Mcf of Estimated Total Natural Gas Production
Q2 2010	129	$	7.40				$	36.9
Q3 2010	119	$	7.46				$	64.8
Q4 2010	120	$	7.70				$	64.4
Q2-Q4 2010(a)	368	$	7.52	675	55%		$	166.1		$	0.25

Total 2011(a)	157	$	7.91	1,000	16%		$	59.6		$	0.06

(a)	Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at prices ranging from $6.50 to $6.75 covering 5 bcf in Q2-Q4 2010 and $5.75 to $6.50 covering 24 bcf in 2011.

The company currently has the following open natural gas collars in place for 2010 and 2011:

	Open Collars (Bcf)	Avg. NYMEX Floor Price		Avg. NYMEX Ceiling Price		Assuming Natural Gas Production (Bcf)	Open Collars as a % of Estimated Total Natural Gas Production
Q2 2010	16	$	7.04	$	9.17
Q3 2010	4	$	7.60	$	11.75
Q4 2010	4	$	7.60	$	11.75
Q2-Q4 2010(a)	24	$	7.21	$	9.97	675	4%

Total 2011	7	$	7.70	$	11.50	1,000	1%

(a)	Certain collar arrangements include three-way collars that include written put options with a strike price of $4.35 covering 4 bcf in 2010.

The company currently has the following natural gas written call options in place for 2010 and 2011:

	Call Options (Bcf)	Avg. NYMEX Floor Price		Avg. Premium per mcf		Assuming Natural Gas Production (Bcf)	Call Options as a % of Estimated Total Natural Gas Production
Q2 2010	28	$	9.94	$	1.46
Q3 2010	39	$	9.89	$	1.10
Q4 2010	39	$	10.07	$	1.10
Q2-Q4 2010	106	$	9.97	$	1.20	675	16%

Total 2011	69	$	9.51	$	0.61	1,000	7%

The company has the following natural gas basis protection swaps in place for 2010, 2011 and 2012:

	Non-Appalachia			Appalachia
	Volume (Bcf)	NYMEX less(a)		Volume (Bcf)	NYMEX plus(a)
Q2-Q4 2010	—	$	—	8	$	0.26
2011	45		0.82	12		0.25
2012	43		0.85	—		—
Totals	88	$	0.84	20	$	0.26

(a)	weighted average

The company also has the following crude oil swaps in place for 2010 and 2011:

	Open Swaps (mbbls)	Avg. NYMEX Strike Price		Assuming Oil Production (mbbls)	Open Swap Positions as a % of Estimated Total Oil Production	Total Gains (Losses) from Lifted Trades ($ millions)		Total Lifted Gains (Losses) per bbl of Estimated Total Oil Production
Q2 2010	2,275	$	89.62	—	—	$	(4.0)		—
Q3 2010	2,300	$	89.62	—	—	$	(4.1)		—
Q4 2010	2,300	$	89.62	—	—	$	(4.1)		—
Q2-Q4 2010(a)	6,875	$	89.62	13,100	52%	$	(12.2)	$	(0.93)

Total 2011(a)	3,285	$	96.09	26,500	12%	$	32.9	$	1.24

(a)	Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 4 mmbbls and 1 mmbbls in Q2-Q4 2010 and 2011, respectively.

Note: Not shown above are written call options covering 1 mmbbls of oil production in Q2-Q4 2010 at a weighted average price of $101.25 per bbl for a weighted average discount of $1.93 per bbl and 3 mmbbls of oil production in 2011 at a weighted average price of $93.13 per bbl for a weighted average premium of $5.34 per bbl.

EX-99.3 4 chk08032010_993.htm PRESS RELEASE - AUGUST 3, 2010 TENDER OFFER chk08032010_993.htm

Exhibit 99.3

N e w s R e l e a s e

Chesapeake Energy Corporation

P. O. Box 18496

Oklahoma City, OK 73154

FOR IMMEDIATE RELEASE

AUGUST 3, 2010

INVESTOR CONTACTS:	MEDIA CONTACT:
JEFFREY L. MOBLEY, CFA (405) 767-4763 jeff.mobley@chk.com JOHN J. KILGALLON (405) 935-4441 john.kilgallon@chk.com	JIM GIPSON (405) 935-1310 jim.gipson@chk.com

CHESAPEAKE ENERGY CORPORATION ANNOUNCES CASH TENDER OFFERS

AND CONSENT SOLICITATIONS FOR CERTAIN SERIES OF SENIOR NOTES

OKLAHOMA CITY, OKLAHOMA, AUGUST 3, 2010 – Chesapeake Energy Corporation (NYSE:CHK) today announced that it has commenced tender offers to purchase for cash any and all of its outstanding 7.00% Senior Notes due 2014, 6.625% Senior Notes due 2016 and 6.25% Senior Notes due 2018 (collectively, the "Notes"). In conjunction with each tender offer, Chesapeake is soliciting consents ("Consents") to the adoption of certain proposed amendments to each of the indentures governing the Notes to, among other things, eliminate substantially all of the restrictive covenants, certain events of default and other related provisions.

The Notes and material pricing terms for each tender offer are set forth in the table below.

CUSIP Nos.	Outstanding Principal Amount	Title of Security	Purchase Price(1)(2)	Consent Payment(1)(2)	Total Consideration(1)
165167BJ5	$300,000,000	7.00% Senior Notes due 2014	$1,001.50	$25.00	$1,026.50
165167BN6	$600,000,000	6.625% Senior Notes due 2016	$1,011.25	$25.00	$1,036.25
165167BQ9	$600,000,000	6.25% Senior Notes due 2018	$1,009.00	$25.00	$1,034.00

(1)	Per $1,000 principal amount of Notes and excluding Accrued Interest (as defined below), which will be paid in addition to the Total Consideration or Purchase Price, as applicable, up to the applicable payment date.

(2)	Included in Total Consideration.

Each tender offer will expire at 12:00 midnight, New York City time, on August 30, 2010, unless extended (such time and date, as the same may be extended with respect to a tender offer, the "Expiration Date"). Holders of Notes must validly tender (and not validly withdraw) their Notes and validly deliver (and not validly revoke) their corresponding Consents at or prior to 5:00 P.M., New York City time, on August 16, 2010, unless extended (such time and date, as the same may be extended with respect to a tender offer, the "Consent Time"), to be eligible to receive the applicable Total Consideration per $1,000 principal amount of Notes tendered, which includes a Consent Payment per $1,000 principal amount of Notes tendered, in each case set forth in the table above. Holders who tender their Notes after the applicabl e Consent Time and on or prior to the applicable Expiration Date will be eligible to receive the applicable Purchase Price per $1,000 principal amount of Notes tendered set forth in the table above, but not the Consent Payment. Tendered Notes may be withdrawn and Consents may be revoked at or prior to 5:00 P.M., New York City time, on August 16, 2010 (such time and date, as the same may be extended with respect to a tender offer, the "Withdrawal Deadline") but may not thereafter be withdrawn or revoked. The Company may extend the Consent Time of a tender offer without extending the Withdrawal Deadline of such tender offer. A Holder cannot deliver a Consent without tendering its corresponding Notes or tender its Notes without delivering a corresponding Consent.

Upon the terms and conditions described in the Offer to Purchase and Consent Solicitation Statement and the related Letter of Transmittal and Consent, payment for Notes accepted for purchase will be made (1) with respect to Notes validly tendered and not validly withdrawn at or prior to the applicable Consent Time, promptly after such acceptance for purchase (which is currently expected to be August 17, 2010, unless the applicable Consent Time is extended), and (2) with respect to Notes validly tendered after the Consent Time but at or before the applicable Expiration Date, promptly after such Expiration Date (which is currently expected to be August 31, 2010, unless the applicable tender offer is extended).

In addition to the Total Consideration or Purchase Price, as applicable, holders of Notes tendered and accepted for payment will receive accrued and unpaid interest on such Notes from the last interest payment date for the Notes up to, but not including, the applicable payment date ("Accrued Interest").

The consummation of each tender offer is conditioned upon the timely receipt of Consents at or prior to the Consent Time from holders of at least a majority of the outstanding aggregate principal amount of the Notes to which such tender offer relates. In addition, Chesapeake’s obligation to purchase Notes pursuant to the tender offers is conditioned upon the receipt by Chesapeake of at least $1.6 billion in gross proceeds from a public offering of one or more series of new senior notes, the proceeds of which, along with cash on hand, will be used to fund the purchase of the Notes in the tender offers. Each tender offer is also subject to the satisfaction or waiver of certain other conditions as set forth in the Offer to Purchase and Consent Solicitation Statement in respect of the tender offers.

Following the payment for Notes validly tendered pursuant to the terms of the tender offers, Chesapeake currently anticipates that it will, but it is not obligated to, call for redemption any Notes that remain outstanding following consummation of the tender offers.

This announcement is not an offer to purchase, a solicitation of an offer to purchase, or a solicitation of an offer to sell securities with respect to the Notes. The tender offers are only being made pursuant to the terms of the Offer to Purchase and Consent Solicitation Statement and the related Letter of Transmittal and Consent.

The complete terms and conditions of the tender offers are set forth in an Offer to Purchase and Consent Solicitation Statement that is being sent to holders of the Notes. Holders are urged to read the tender offer documents carefully before making any decision with respect to the tender offers and consent solicitations. Holders of Notes must make their own decisions as to whether to tender their Notes and provide the related consents, and if they decide to do so, the principal amount of the Notes to tender.

Holders may obtain copies of the Offer to Purchase and Consent Solicitation Statement and the related Letter of Transmittal and Consent from the Information Agent and Depositary for the tender offers, Global Bondholder Services Corporation, at (212) 430-3774 (collect, for banks and brokers only) and (866) 952-2200 (toll free).

Credit Suisse Securities (USA) LLC is the Dealer Manager for the tender offers and Solicitation Agent for the consent solicitations. Questions regarding the tender offers and consent solicitations may be directed to Credit Suisse Securities (USA) LLC at (800) 820-1653 (toll free) and (212) 325-5912 (collect).

None of Chesapeake, the Dealer Manager and Solicitation Agent, the Information Agent and Depositary or any other person makes any recommendation as to whether holders of Notes should tender their Notes or provide the related consents, and no one has been authorized to make such a recommendation.

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