chk08032009

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

JULY 30, 2009

INVESTOR CONTACT:	MEDIA CONTACT:
JEFFREY L. MOBLEY, CFA SENIOR VICE PRESIDENT – INVESTOR RELATIONS AND RESEARCH (405) 767-4763 jeff.mobley@chk.com	JIM GIPSON DIRECTOR – MEDIA RELATIONS (405) 935-1310 jim.gipson@chk.com

CHESAPEAKE ENERGY CORPORATION PROVIDES OPERATIONAL UPDATE

Company Reports 2009 Second Quarter Production of 2.453 Bcfe per Day, an Increase of 4%

over 2009 First Quarter Production and 5% over 2008 Second Quarter Production

Company Increases Proved Reserves by 0.7 Tcfe to 12.5 Tcfe, Anticipates Reporting 2009

Second Quarter Drilling and Net Acquisition Costs of Less Than $1.00 per Mcfe; Year-End

Proved Reserve Targets for 2009 and 2010 Reaffirmed at 14 and 16 Tcfe, Respectively

Company Raises Per-Well Reserve Expectations for Marcellus and Fayetteville Shale Plays,

Completes Prolific Wells in the Haynesville, Marcellus and Barnett Shale Plays and

Announces Strong Results from Granite Wash Plays in the Anadarko Basin

OKLAHOMA CITY, OKLAHOMA, JULY 30, 2009 – Chesapeake Energy Corporation (NYSE:CHK) today provided a comprehensive update on its operational activities. For the 2009 second quarter, daily production averaged 2.453 billion cubic feet of natural gas equivalent (bcfe), an increase of 86 million cubic feet of natural gas equivalent (mmcfe), or 4%, over the 2.367 bcfe produced per day in the 2009 first quarter and an increase of 125 mmcfe, or 5%, over the 2.328 bcfe produced per day in the 2008 second quarter. Adjusted for the company’s voluntary production curtailments due to low natural gas and oil prices (which averaged approximately 74 mmcfe per day during the 2009 second quarter), the company’s three 2008 volumetric production payment sales (which averaged approximately 139 mmcfe per day during the 2009 second quarter) and the estimated impact from the company’s 2008 sales of Woodford Shale and Fayetteville Shale properties (which would have averaged approximately 81 mmcfe per day during the 2009 second quarter), Chesapeake’s sequential and year-over-year production growth rates would have been 4% and 16%, respectively, after making similar adjustments to prior quarters. The company is not currently curtailing production, but may do so again later this summer or fall as market conditions dictate. The company also expects that rising pipeline and gathering system pressures during the next few months will likely result in involuntary natural gas production curtailments across the industry.

Chesapeake’s average daily production for the 2009 second quarter consisted of 2.245 billion cubic feet of natural gas (bcf) and 34,637 barrels of oil and natural gas liquids (bbls). The company’s 2009 second quarter production of 223.2 bcfe was comprised of 204.3 bcf (92% on a natural gas equivalent basis) and 3.152 million barrels of oil and natural gas liquids (mmbbls) (8% on a natural gas equivalent basis).

Company Increases Proved Natural Gas and Oil Reserves by 0.7 Tcfe to 12.5 Tcfe,

Anticipates Reporting 2009 Second Quarter Drilling and Net Acquisition Costs of Less

Than $1.00 per Mcfe; Company Record Set for Organic Reserve Additions and Reserve

Replacement Over a Six-Month Period; Year-End Proved Reserve Targets

for 2009 and 2010 Reaffirmed at 14 and 16 Tcfe, Respectively

Chesapeake began the 2009 second quarter with estimated proved reserves of 11.851 trillion cubic feet of natural gas equivalent (tcfe) and ended the 2009 second quarter with 12.525 tcfe, an increase of 674 bcfe, or 5.7%. During the 2009 second quarter, Chesapeake replaced 223 bcfe of production with an estimated 897 bcfe of new proved reserves for a reserve replacement rate of 402%. The quarter’s reserve movement includes 493 bcfe of extensions, 343 bcfe of positive performance revisions, 156 bcfe of positive revisions resulting from natural gas and oil price increases between March 31, 2009 and June 30, 2009 and 95 bcfe of net divestitures.

During the 2009 first half, Chesapeake increased its estimated proved reserves by 474 bcfe, or 3.9%, from 12.051 tcfe at year-end 2008. For the 2009 first half, Chesapeake replaced 436 bcfe of production with an estimated 910 bcfe of new proved reserves for a reserve replacement rate of 209%. The reserve movement in the 2009 first half includes 920 bcfe of extensions, 740 bcfe of positive performance revisions, 664 bcfe of downward revisions resulting from natural gas and oil price decreases between December 31, 2008 and June 30, 2009 and 86 bcfe of net divestitures. Chesapeake’s 1,660 bcfe of extensions and performance revisions in the 2009 first half set a company record for the highest level of organic reserve additions over a six-month period and its organic reserve replacement rate of 381% for the six-month period was also the highest in the company’s history.

Chesapeake anticipates reporting total drilling and net acquisition costs for the 2009 second quarter of less than $1.00 per mcfe. This estimate excludes costs for the acquisition of unproved properties and leasehold, capitalized interest on unproved properties, seismic and costs relating to asset retirement obligations, and also excludes positive revisions of proved reserves from higher natural gas and oil prices. The estimate includes the benefit of drilling carries associated with the Haynesville ($118 million), Fayetteville ($166 million) and Marcellus ($27 million) joint ventures. A complete reconciliation of 2009 second quarter proved reserves and finding and acquisition costs will be provided on August 3, 2009 in conjunction with the company’s release of financial and operational results for the 2009 second quarter.

Chesapeake continued the industry’s most active drilling program during the 2009 first half, and drilled 580 gross operated wells (432 net wells with an average working interest of 74%) and participated in another 581 gross wells operated by other companies (44 net wells with an average working interest of 8%). The company’s drilling success rate was 99% for both company-operated and non-operated wells. Also during the 2009 first half, Chesapeake used an average of 104 operated rigs and an average of 53 non-operated rigs.

As of June 30, 2009, the present value of future net cash flows, discounted at 10% per year, of Chesapeake’s estimated proved reserves (PV-10) was $11.076 billion using field differential adjusted prices based on NYMEX quarter-end prices of $3.89 per thousand cubic feet (mcf) and $70.00 per bbl. Chesapeake’s PV-10 changes by approximately $400 million for every $0.10 per mcf change in natural gas prices and approximately $65 million for every $1.00 per bbl change in oil prices.

By comparison, the December 31, 2008 PV-10 of the company’s proved reserves was $15.601 billion ($11.833 billion applying the SFAS 69 standardized measure) using field differential adjusted prices based on NYMEX year-end prices of $5.71 per mcf and $44.61 per bbl. The June 30, 2008 PV-10 of the company’s proved reserves was $51.5 billion using field differential adjusted prices based on NYMEX quarter-end prices of $13.10 per mcf and $140.02 per bbl.

Chesapeake’s Leasehold and 3-D Seismic Inventories Total 14.3 Million Net Acres and 22.7

Million Acres; Risked Unproved Reserves in the Company’s Inventory Total 62 Tcfe

and Unrisked Unproved Reserves Total 172 Tcfe

Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (14.3 million net acres) and 3-D seismic (22.7 million acres) in the U.S. and the largest inventory of U.S. Big 4 shale play leasehold (2.7 million net acres). On its leasehold at June 30, 2009, Chesapeake had identified an estimated 12.5 tcfe of proved reserves, approximately 62 tcfe of risked unproved reserves and 172 tcfe of unrisked unproved reserves. The company is currently using 95 operated drilling rigs to further develop its inventory of approximately 36,000 net drillsites, which represents more than a 10-year inventory of drilling projects.

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

Play Type/Area	CHK Net Acreage	Est. Drilling Density (Acres)	Risk Factor	Risked Net Undrilled Wells	Est. Avg. Reserves Per Well (bcfe)	Total Proved Reserves (bcfe)	Risked Unproved Reserves (bcfe)	Total Proved and Risked Unproved Reserves (bcfe)	Unrisked Unproved Reserves (bcfe)	Est. IRR at $7 Gas/ $70 Oil	Current Daily Production (mmcfe)	Current Operated Rig Count
Big 4 Shale Plays:
Haynesville Shale	510,000	80	40%	3,750	6.50	870	17,900	18,770	30,100	42%	175	29
Marcellus Shale	1,450,000	80	75%	4,550	4.20	125	16,100	16,225	64,600	71%	30	15
Barnett Shale	310,000	60	15%	2,750	2.65	3,202	4,700	7,902	6,300	32%	655	19
Fayetteville Shale	440,000	80	20%	4,100	2.40	1,018	7,800	8,818	9,800	24%	240	20
Big 4 Shale Play Subtotals	2,710,000			15,150		5,215	46,500	51,715	110,800		1,100	83

Colony Granite Wash	60,000	160	15%	300	5.70	316	1,100	1,416	1,250	140%	90	2
Texas Panhandle Granite Wash	40,000	80	25%	200	4.75	464	400	864	700	135%	70	1
Other	11,490,000	Various	Various	20,100	Various	6,530	13,600	20,130	59,650	Various	1,225	9

Total	14,300,000			35,750		12,525	61,600	74,125	172,400	Various	2,485	95

Haynesville Shale (Northwest Louisiana, East Texas): Chesapeake is the largest leasehold owner and most active driller of new wells in the Haynesville Shale play in Northwest Louisiana and East Texas. Chesapeake now owns approximately 510,000 net acres of leasehold in the Haynesville Shale play, an increase of approximately 40,000 net acres since March 31, 2009. Chesapeake and its 20% partner, Plains Exploration & Production Company (NYSE:PXP) (which owns approximately 113,000 additional net acres), have drilled and completed 74 Chesapeake-operated horizontal wells in the Haynesville play and continue to experience outstanding drilling results. During the 2009 second quarter, Chesapeake’s average daily net production of 135 mmcfe in the Haynesville increased approximately 85% over the 2009 first quarter and approximately 865% over the 2008 second quarter. Chesapeake is currently producing approximately 175 mmcfe net per day (285 mmcfe gross operated) from the Haynesville and anticipates exceeding approximately 275 mmcfe net per day (575 mmcfe gross operated) by year-end 2009 and approximately 450 mmcfe net per day (1.025 bcfe gross operated) by year-end 2010. To further develop its 510,000 net acres of Haynesville leasehold, Chesapeake is currently drilling with 29 operated rigs and anticipates operating an average of approximately 33 rigs in the second half of 2009 and 36 rigs in 2010 to drill approximately 75 and 180 net wells, respectively. During the first half of 2009, approximately $204 million of Chesapeake’s drilling costs in the Haynesville were paid for by its joint venture partner PXP. During the second half of 2009 and in 2010, 50% of Chesapeake’s drilling costs in the Haynesville will be paid for by PXP, or approximately $275 million and $675 million in each year, respectively.

The following chart illustrates Chesapeake’s aggregate drilling results from 56 company-operated horizontal wells drilled in the Haynesville since January 1, 2008 and completed using at least 10-stage fracture stimulations. To date, initial production rates from horizontal wells completed with at least 10-stage fracture stimulations have exceeded the company’s expectations. As a result, Chesapeake has recently adjusted its targeted type curve while maintaining an estimated average estimated ultimate recovery (EUR) of 6.5 bcfe per well, but now recognizing higher initial production rates (IPs), faster recovery rates and enhanced present value from each well, as illustrated in the chart below.

Assuming flat NYMEX natural gas prices of $7.00 per mcf over the life of the well (compared to a recent 10-year NYMEX strip price of approximately $7.02 per mcf), the company’s estimated pre-tax rate of return from a 6.5 bcfe horizontal Haynesville well drilled for $7.5 million is approximately 42% excluding the benefit of drilling carries and more than 345% including the benefit of drilling carries. Chesapeake’s 50% drilling carry from PXP will provide CHK with an estimated return from its Haynesville drilling that is more than 800% greater than the returns other companies will likely experience without the benefit of drilling carries. This should result in Chesapeake delivering lower finding costs, higher returns on invested capital and higher production growth levels than other companies will likely deliver from the Haynesville. In addition, Chesapeake’s leasehold investment in the Haynesville to date has been approximately $4.7 billion, of which approximately $1.7 billion, or 35%, has been recouped to date by selling a 20% interest in the company’s leasehold to PXP. The company’s net investment in its Haynesville leasehold is now about $6,000 per net acre on average.

Three notable wells completed by Chesapeake in the Haynesville during the 2009 second quarter are as follows:

·	The CLD 23 H-1 in Caddo Parish, LA commenced production on June 22, 2009 and achieved a peak rate of 29.1 mmcfe per day and a pipeline-constrained first 30-day average rate of 15.3 mmcfe per day.

·	The Frith 29 H-1 in De Soto Parish, LA commenced production on June 27, 2009 and achieved a pipeline-constrained peak rate of 23.7 mmcfe per day and a pipeline-constrained first 30-day average rate of 14.2 mmcfe per day.

·	The Chesapeake Royalty LLC 30 H-1 in De Soto Parish, LA commenced production on June 27, 2009 and achieved a pipeline-constrained peak rate of 22.6 mmcfe per day and a pipeline-constrained first 30-day average rate of 15.2 mmcfe per day.

Marcellus Shale (West Virginia, Pennsylvania and New York): Having increased its leasehold ownership by 150,000 net acres to 1.45 million net acres during the 2009 second quarter, Chesapeake has solidified its position as the largest leasehold owner in the Marcellus Shale play that spans from northern West Virginia across much of Pennsylvania into southern New York. The company’s joint venture partner, StatoilHydro (NYSE:STO, OSE:STL), owns approximately 625,000 net acres of additional Marcellus leasehold. Chesapeake remains the most active driller and expects to become the largest gross producer of natural gas from the play by year-end 2009. During the 2009 second quarter, Chesapeake’s average daily net production of approximately 30 mmcfe in the Marcellus increased approximately 155% over the 2009 first quarter and approximately 600% over the 2008 second quarter. Chesapeake is currently producing approximately 30 mmcfe net per day (50 mmcfe gross operated) from the Marcellus and anticipates reaching approximately 80 mmcfe net per day (200 mmcfe gross operated) by year-end 2009 and approximately 200 mmcfe net per day (500 mmcfe gross operated) by year-end 2010. To further develop its 1.45 million net acres of Marcellus leasehold, Chesapeake is currently drilling with 15 operated rigs and anticipates operating an average of approximately 19 rigs in the second half of 2009 and 28 rigs in 2010 to drill approximately 60 and 165 net wells, respectively. During the first half of 2009, approximately $39 million of Chesapeake’s drilling costs in the Marcellus were paid for by STO. During the second half of 2009 and in 2010, 75% of Chesapeake’s drilling costs in the Marcellus will be paid for by STO, or approximately $200 million and $550 million in each year, respectively.

Since January 1, 2008, Chesapeake has drilled and completed 25 company-operated horizontal wells in the Marcellus. To date, production rates and reserve recoveries in the Marcellus have exceeded the company’s expectations while decline rates have been lower than anticipated. Based on drilling results by Chesapeake and others in the industry, the company has recently increased its targeted average EUR in the Marcellus from 3.75 bcfe per well to 4.2 bcfe per well. Assuming flat NYMEX natural gas prices of $7.00 per mcf (compared to a recent 10-year NYMEX strip price of approximately $7.02 per mcf), the company’s estimated pre-tax rate of return from a 4.2 bcfe horizontal Marcellus well drilled for $4.5 million is approximately 71% excluding the benefit of drilling carries and more than 1,000% including the benefit of drilling carries. Chesapeake’s 75% drilling carry from STO will provide CHK with an estimated return from its Marcellus drilling that is more than 1,000% greater than the returns other companies will likely experience without the benefit of drilling carries. This should result in Chesapeake delivering lower finding costs, higher returns on invested capital and higher production growth levels than other companies will likely deliver from the Marcellus. In addition, Chesapeake’s leasehold investment in the Marcellus to date has been approximately $1.3 billion, of which $1.2 billion, or 91%, has been recouped to date by selling a 32.5% interest in the company’s leasehold to STO. The company’s net investment in its Marcellus leasehold is now about $80 per net acre on average.

Three notable wells completed by Chesapeake in the Marcellus during the 2009 second quarter are as follows:

·	The Vargson 1H in Bradford County, PA commenced production on April 13, 2009 and achieved a peak rate of 7.0 mmcfe per day and a first 30-day average rate of 4.6 mmcfe per day.

·	The Evanchick 2H in Bradford County, PA commenced production on May 6, 2009 and achieved a peak rate of 6.9 mmcfe per day and a first 30-day average rate of 5.3 mmcfe per day.

·	The James Messenger 3H in Wetzel County, WV commenced production on April 10, 2009 and achieved a peak rate of 5.1 mmcfe per day and a first 30-day average rate of 3.4 mmcfe per day.

Barnett Shale (North Texas): The Barnett Shale is currently the largest natural gas producing field in the U.S. and is producing approximately 70% of all shale gas in the U.S. In this play, Chesapeake is the second-largest producer, the most active driller and the largest leasehold owner in the Core and Tier 1 sweet spots of Tarrant and Johnson counties. During the 2009 second quarter, Chesapeake’s average daily net production of approximately 650 mmcfe in the Barnett was flat compared to the 2009 first quarter and increased approximately 40% over the 2008 second quarter. Chesapeake is currently producing approximately 655 mmcfe net per day (925 mmcfe gross operated) from the Barnett and anticipates reaching approximately 725 mmcfe net per day (1,050 mmcfe gross operated) by year-end 2009 and approximately 750 mmcfe net per day (1,100 mmcfe gross operated) by year-end 2010. To further develop its 310,000 net acres of leasehold, of which 280,000 net acres are located in the prime Core and Tier 1 areas, Chesapeake anticipates operating an average of approximately 18 rigs in the second half of 2009 and 20 rigs in 2010 to drill approximately 145 and 310 net wells, respectively. If Chesapeake is successful in finding a joint venture partner in the second half of 2009 for some or all of its Barnett Shale leasehold, the company plans to significantly increase Barnett drilling activity and production in 2010 and beyond. Assuming flat NYMEX natural gas prices of $7.00 per mcf (compared to a recent 10-year NYMEX strip price of approximately $7.02 per mcf), the company’s estimated pre-tax rate of return from a 2.65 bcfe horizontal Barnett well drilled for $2.6 million is approximately 32%.

The following chart illustrates Chesapeake’s aggregate drilling results from 849 company-operated horizontal wells with laterals at least 2,500 feet drilled in the Barnett since January 1, 2008.

Three notable wells completed by Chesapeake in the Barnett during the 2009 second quarter are as follows:

·	The Armet Dale Street 7H in Tarrant County, TX commenced production on June 3, 2009 and achieved a peak rate of 7.8 mmcfe per day and a first 30-day average rate of 4.4 mmcfe per day.

·	The Chevy 2H in Johnson County, TX commenced production on June 12, 2009 and achieved a peak rate of 7.4 mmcfe per day and a first 30-day average rate of 5.8 mmcfe per day.

·	The Gann 4H in Johnson County, TX commenced production on June 5, 2009 and achieved a peak rate of 7.0 mmcfe per day and a first 30-day average rate of 5.4 mmcfe per day.

In addition, Chesapeake has drilled two of the best three wells ever drilled in the Barnett, the Donna Ray 1H and Donna Ray 3H. These two wells averaged 9.6 and 8.8 mmcfe per day, respectively, during their first 30 days of production.

Fayetteville Shale (Arkansas): The Fayetteville Shale is currently the second most productive shale play in the U.S. and one of the nation’s 10-largest natural gas fields of any type. In the Fayetteville, Chesapeake is the second-largest leasehold owner in the Core area of the play with 440,000 net acres. During the 2009 second quarter, Chesapeake’s average daily net production of 220 mmcfe in the Fayetteville increased approximately 15% over the 2009 first quarter and approximately 60% over the 2008 second quarter. Chesapeake is currently producing approximately 240 mmcfe net per day (325 mmcfe gross operated) from the Fayetteville and anticipates reaching approximately 300 mmcfe net per day (400 mmcfe gross operated) by year-end 2009 and approximately 375 mmcfe net per day (500 mmcfe gross operated) by year-end 2010. To further develop its 440,000 net acres of Core Fayetteville leasehold, Chesapeake anticipates operating an average of approximately 18 rigs in the second half of 2009 and 16 rigs in 2010 to drill approximately 80 and 140 net wells, respectively. During the first half of 2009, approximately $337 million of Chesapeake’s drilling costs in the Fayetteville were paid for by its joint venture partner BP America (NYSE:BP). During the second half of 2009, nearly all of Chesapeake’s drilling costs, or approximately $300 million, will be paid for by BP.

The following chart illustrates Chesapeake’s aggregate drilling results from 239 company-operated horizontal wells drilled in the Fayetteville since January 1, 2008. To date, production rates and reserve recoveries have exceeded the company’s expectations.

As a result of continued strong drilling results, Chesapeake has increased its targeted average EUR in the Fayetteville from 2.2 bcfe per well to 2.4 bcfe per well. Assuming flat NYMEX natural gas prices of $7.00 per mcf (compared to a recent 10-year NYMEX strip price of approximately $7.02 per mcf), the company’s estimated pre-tax rate of return from a 2.4 bcfe horizontal Fayetteville well drilled for $3.0 million is approximately 24% excluding the benefit of drilling carries and is infinite including the benefit of drilling carries. During the last few months of 2008 and throughout 2009, Chesapeake’s 100% drilling carry from BP has provided Chesapeake with an infinitely greater return from its Fayetteville drilling than the returns other companies will likely experience without the benefit of drilling carries. This has resulted in lower finding costs, higher returns on invested capital and higher production growth levels than other companies have been able to deliver from the Fayetteville. In addition, Chesapeake’s leasehold investment in the Fayetteville to date has been approximately $525 million. By selling a 25% interest in the company’s leasehold to BP for $883 million, the company has more than recouped its entire leasehold investment in the Fayetteville.

Three notable wells completed by Chesapeake in the Fayetteville during the 2009 second quarter are as follows:

·	The Maxwell 8-8 4-34H in White County, AR commenced production on May 29, 2009 and achieved a peak rate of 5.0 mmcfe per day and a first 30-day average rate of 3.5 mmcfe per day.

·	The Terry Bomar 8-9 3-17H in White County, AR commenced production on April 27, 2009 and achieved a peak rate of 3.5 mmcfe per day and a first 30-day average rate of 2.8 mmcfe per day.

·	The Don Shipp 9-15 1-11H in Conway County, AR commenced production on April 18, 2009 and achieved a peak rate of 4.1 mmcfe per day and a first 30-day average rate of 2.4 mmcfe per day.

Anadarko Basin Granite Wash (western Oklahoma and Texas Panhandle): In the various Wash plays of the Anadarko Basin, Chesapeake is the largest leasehold owner with approximately 360,000 net acres and also the most active driller and largest producer. The Colony Granite Wash and the Texas Panhandle Granite Wash plays highlighted below are two particularly prolific areas within the Anadarko Basin Granite Wash and have become the two highest rate-of-return plays in the company.

Colony Granite Wash (western Oklahoma): Discovered by Chesapeake in February 2007, the Colony Granite Wash play is located in Custer and Washita counties, Oklahoma and is a subset of the greater Granite Wash plays of the Anadarko Basin. In the Colony Granite Wash, Chesapeake is the largest leasehold owner with 60,000 net acres and is also the most active driller and largest producer in the play. During the 2009 second quarter, Chesapeake’s average daily net production of 75 mmcfe in the Colony Granite Wash increased approximately 30% over the 2009 first quarter and approximately 85% over the 2008 second quarter. Chesapeake is currently producing approximately 90 mmcfe net per day (165 mmcfe gross operated) from the Colony Granite Wash and anticipates reaching approximately 105 mmcfe net per day (190 mmcfe gross operated) by year-end 2009 and approximately 140 mmcfe net per day (250 mmcfe gross operated) by year-end 2010. To further develop its 60,000 net acres of Colony Granite Wash leasehold, Chesapeake anticipates operating an average of approximately four rigs in the second half of 2009 to drill approximately 10 net wells and seven rigs in 2010 to drill approximately 40 net wells. Due in large part to the play’s high oil and natural gas liquids content, the Colony Granite Wash is Chesapeake’s highest rate of return play. Assuming flat NYMEX natural gas and oil prices of $7.00 per mcf and $70 per bbl, respectively (compared to recent 10-year NYMEX strip natural gas and oil prices of approximately $7.02 per mcf and $82 per bbl), the company’s estimated pre-tax rate of return from a 5.7 bcfe horizontal Colony Granite Wash well drilled for $6.25 million is approximately 140%.

The following chart illustrates Chesapeake’s aggregate drilling results from 58 company-operated horizontal wells drilled in the Colony Granite Wash. To date, production rates and reserve recoveries have exceeded the company’s expectations.

Three notable wells completed by Chesapeake in the Colony Granite Wash during the 2009 second quarter are as follows:

·	The Balzar 2-7H in Washita County, OK commenced production on June 11, 2009 and achieved a peak rate of 23.6 mmcfe per day (including 1,800 bbls per day of oil) and a first 30-day average rate of 17.1 mmcfe per day (including 1,300 bbls per day of oil).

·	The Miller 1-21H in Washita County, OK commenced production on June 27, 2009 and achieved a peak rate of 22.7 mmcfe per day (including 1,500 bbls per day of oil) and a first 30-day average rate of 16.0 mmcfe per day (including 900 bbls per day of oil).

·	The Martin 1-16H in Washita County, OK commenced production on May 30, 2009 and achieved a peak rate of 19.7 mmcfe per day (including 1,400 bbls per day of oil) and a first 30-day average rate of 15.4 mmcfe per day (including 1,100 bbls per day of oil).

Texas Panhandle Granite Wash: The Texas Panhandle Granite Wash play is located in Hemphill and Wheeler counties, Texas and is a subset of the greater Granite Wash plays of the Anadarko Basin. In the Texas Panhandle Granite Wash, Chesapeake is one of the largest leasehold owners with 40,000 net acres and also one of the most active drillers and largest producers in the play. During the 2009 second quarter, Chesapeake’s average daily net production of 70 mmcfe in the Texas Panhandle Granite Wash increased approximately 5% over the 2009 first quarter and approximately 15% over the 2008 second quarter. Chesapeake is currently producing approximately 70 mmcfe net per day (95 mmcfe gross operated) from the Texas Panhandle Granite Wash and anticipates reaching approximately 75 mmcfe net per day (100 mmcfe gross operated) by year-end 2009 and approximately 80 mmcfe net per day (110 mmcfe gross operated) by year-end 2010. To further develop its 40,000 net acres of Texas Panhandle Granite Wash leasehold, Chesapeake anticipates operating an average of two rigs in the second half of 2009 and in 2010 to drill approximately 10 and 20 net wells, respectively. Assuming flat natural gas and oil prices of $7.00 per mcf and $70 per bbl, respectively (compared to recent 10-year NYMEX strip natural gas and oil prices of approximately $7.02 per mcf and $82 per bbl), the company’s estimated pre-tax rate of return from a 4.75 bcfe horizontal Texas Panhandle Granite Wash well drilled for $5.5 million is approximately 135%.

The following chart illustrates Chesapeake’s aggregate drilling results from 12 company-operated horizontal wells drilled in the Texas Panhandle Granite Wash. To date, production rates and reserve recoveries have exceeded the company’s expectations.

Three notable wells completed by Chesapeake in the Texas Panhandle Granite Wash during the 2009 second quarter are as follows:

·	The Stiles Ranch 23-11H in Wheeler County, TX commenced production on June 24, 2009 and achieved a peak rate of 6.6 mmcfe per day (including 650 bbls per day of oil) and a first 30-day average rate of 3.2 mmcfe per day (including 200 bbls per day of oil).

·	The Reed 70-6H in Wheeler County, TX commenced production on June 25, 2009 and achieved a peak rate of 4.8 mmcfe per day (including 220 bbls per day of oil) and a first 30-day average rate of 3.6 mmcfe per day (including 130 bbls per day of oil).

·	The Lott 2 4H in Wheeler County, TX commenced production on May 31, 2009 and achieved a peak rate of 4.5 mmcfe per day (including 350 bbls per day of oil) and a first 30-day average rate of 3.2 mmcfe per day (including 210 bbls per day of oil).

Management Comments

Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, “We are once again pleased to highlight a strong quarterly operational performance by our company. Chesapeake owns an unrivalled U.S asset base and, through our joint ventures, we have now constructed an unrivalled financing plan for the development of these assets – a plan that over the next four years should enable us to deliver the lowest finding costs, highest returns on capital and highest growth rates among large-cap E&P companies in the U.S. The company’s performance this quarter provides a great deal of insight into what is to come for Chesapeake’s investors in the years ahead. We are particularly proud of our strong organic reserve additions of 836 bcfe and our outstanding drilling and net acquisition costs below $1.00 per mcfe. In addition, our 2009 first half organic reserve additions of 1.7 tcfe and reserve replacement rate of 381% set a remarkable six-month record for the company. We believe this is likely the best reserve growth performance in the industry during the 2009 first half.

“Furthermore, despite voluntary production curtailments and asset sales during the quarter, we achieved strong production growth of 4% sequentially and 5% year-over-year, led by production growth in the Haynesville, Marcellus, Fayetteville and the Colony Granite Wash plays. Notably, we were successful in holding our production levels flat in the Barnett Shale and in our non-Big 4 shale plays, despite substantially reduced drilling activity levels during the past year. We remain on track to reach estimated proved reserves of 14 tcfe by year-end 2009 and 16 tcfe by year-end 2010. This proved reserve growth of 33% from our year-end 2008 proved reserve levels will reduce our debt per mcfe of proved reserves by approximately 25% in just two years, resulting in substantial deleveraging. In addition, we remain optimistic that we will also be able to reduce the absolute levels of our debt as we reduce our relative debt levels.

“Our drilling activities in each of our Big 4 shale plays continue to generate outstanding results and we have raised our recovery expectations in the Marcellus and Fayetteville Shale plays. Additionally, our Colony Granite Wash and Texas Panhandle Granite Wash plays are delivering exceptional rates of return even in the current low commodity price environment. We have been very successful in reducing our drilling and operating costs and are also benefiting from substantially lower oilfield service prices relative to year-ago levels. We look forward to providing additional details on 2009 second quarter results next week.”

2009 Second Quarter Financial and Operational Results and Conference Call Information

Chesapeake is scheduled to release its 2009 second quarter Financial and Operational Results after the close of trading on the New York Stock Exchange on Monday, August 3, 2009. Also, a conference call to discuss this release and the August 3 release has been scheduled for Tuesday morning, August 4, 2009, at 9:00 a.m. EDT. The telephone number to access the conference call is 913-981-5574 or toll-free 888-596-2560. The passcode for the call is 3824854. 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, 2009 through midnight EDT on August 18, 2009. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 3824854. The conference call will also be webcast live on the Internet and can be accessed by going to Chesapeake’s website at www.chk.com in the “Events” subsection of the “Investors” section of our website. The webcast of the conference call will be available on our website for one year.

This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of natural gas and oil reserves, expected natural gas and oil production and ultimate recoveries, assumptions regarding future natural gas and oil prices, planned drilling activity and costs, as well as statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.

Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in Item 1A of our 2008 Annual Report on Form 10-K we filed with the U.S. Securities and Exchange Commission on March 2, 2009. These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; impacts the current financial crisis may have on our business and financial condition; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; the availability of capital on an economic basis, including planned asset monetization transactions, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the amount and timing of development expenditures; exploration and development drilling that does not result in commercially productive reserves; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas and oil sales and the need to secure hedging liabilities; uncertainties in evaluating natural gas and oil reserves of acquired properties and potential liabilities; the negative impact lower natural gas and oil prices could have on our ability to borrow; drilling and operating risks, including potential environmental liabilities; transportation capacity constraints and interruptions that could adversely affect our cash flow; potential increased operating costs resulting from legislative and regulatory changes such as those proposed with respect to commodity derivatives trading, natural gas and oil tax incentives and deductions, hydraulic fracturing and climate change; and adverse results in pending or future litigation.

Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.

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

The company calculates the standardized measure of future net cash flows of proved reserves in accordance with SFAS 69 only at year end because applicable income tax information on properties, including recently acquired natural gas and oil interests, is not readily available at other times during the year. As a result, the company is not able to reconcile interim period-end PV-10 values to the standardized measure at such dates. The only difference between the two measures is that PV-10 is calculated before considering the impact of future income tax expenses, while the standardized measure includes such effects.

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

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, 2009

INVESTOR CONTACT:	MEDIA CONTACT:
JEFFREY L. MOBLEY, CFA SENIOR VICE PRESIDENT – INVESTOR RELATIONS AND RESEARCH (405) 767-4763 jeff.mobley@chk.com	JIM GIPSON DIRECTOR – MEDIA RELATIONS (405) 935-1310 jim.gipson@chk.com

CHESAPEAKE ENERGY CORPORATION REPORTS FINANCIAL AND OPERATIONAL

RESULTS FOR THE 2009 SECOND QUARTER

Company Reports 2009 Second Quarter Adjusted Net Income to Common Shareholders of

$377 Million, or $0.62 per Fully Diluted Common Share, on Revenue of $1.67 Billion;

Net Income Available to Common Shareholders Was $237 Million,

or $0.39 per Fully Diluted Common Share

Company Reports 2009 Second Quarter Production of 2.453 Bcfe per Day, an Increase of 4%

over 2009 First Quarter Production and 5% over 2008 Second Quarter Production

Company Increases Proved Reserves by 0.7 Tcfe to 12.5 Tcfe and Delivers 2009 Second

Quarter Drilling and Net Acquisition Costs of $0.72 per Mcfe; Company Record Set for

Organic Reserve Additions and Reserve Replacement During a Six-Month Period

Company Provides Update on 2009 Asset Monetization Initiatives and Hedging Positions

OKLAHOMA CITY, OKLAHOMA, AUGUST 3, 2009 – Chesapeake Energy Corporation (NYSE:CHK) today announced financial and operating results for the 2009 second quarter. For the quarter, Chesapeake reported net income to common shareholders of $237 million ($0.39 per fully diluted common share), operating cash flow of $1.006 billion (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $763 million (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $1.673 billion and production of 223 billion cubic feet of natural gas equivalent (bcfe).

The company’s 2009 second quarter results include a realized natural gas and oil hedging gain of $597 million. The results also include various items that are typically not included in published estimates of the company’s financial results by certain securities analysts. Excluding the items detailed below, Chesapeake generated adjusted net income to common shareholders for the 2009 second quarter of $377 million ($0.62 per fully diluted common share) and adjusted ebitda of $1.030 billion. The excluded items and their effects on 2009 second quarter reported results are detailed as follows:

·	a net unrealized noncash after-tax mark-to-market loss of $109 million resulting from the company’s natural gas, oil and interest rate hedging programs;

·	an after-tax charge of $21 million related to restructuring and relocation costs in the company’s Eastern Division and certain other work force reduction costs; and

·	a combined after-tax charge of $10 million related to estimated bad debts owed to Chesapeake that may be uncollectible, the impairment of an investment and a loss on exchanges of certain of the company’s contingent convertible senior notes for shares of common stock.

The various items described above do not materially affect the calculation of operating cash flow. A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 15 – 19 of this release.

Key Operational and Financial Statistics Summarized

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

	Three Months Ended
	6/30/09	3/31/09	6/30/08(a)
Average daily production (in mmcfe)	2,453	2,367	2,328
Natural gas as % of total production	92	92	92
Natural gas production (in bcf)	204.3	195.7	195.0
Average realized natural gas price ($/mcf) (b)	5.56	6.05	8.18
Oil production (in mbbls)	3,152	2,874	2,816
Average realized oil price ($/bbl) (b)	56.72	39.12	76.96
Natural gas equivalent production (in bcfe)	223.2	213.0	211.9
Natural gas equivalent realized price ($/mcfe) (b)	5.89	6.09	8.55
Natural gas and oil marketing income ($/mcfe)	.14	.14	.12
Service operations income (loss) ($/mcfe)	(.01)	.03	.04
Production expenses ($/mcfe)	(.95)	(1.12)	(1.03)
Production taxes ($/mcfe)	(.11)	(.11)	(.41)
General and administrative costs ($/mcfe) (c)	(.25)	(.33)	(.38)
Stock-based compensation ($/mcfe)	(.09)	(.09)	(.10)
DD&A of natural gas and oil properties ($/mcfe)	(1.32)	(2.10)	(2.47)
D&A of other assets ($/mcfe)	(.26)	(.27)	(.19)
Interest expense ($/mcfe) (b)	(.29)	(.14)	(.32)
Operating cash flow ($ in millions) (d)	1,006	999	1,468
Operating cash flow ($/mcfe)	4.51	4.69	6.93
Adjusted ebitda ($ in millions) (e)	1,030	988	1,435
Adjusted ebitda ($/mcfe)	4.62	4.64	6.77
Net income (loss) to common shareholders ($ in millions)	237	(5,746)	(1,643)
Earnings (loss) per share – assuming dilution ($)	.39	(9.63)	(3.16)
Adjusted net income to common shareholders ($ in millions) (f)	377	277	485
Adjusted earnings per share – assuming dilution ($)	.62	.46	.90

(a)	reflects the adoption and retrospective application of FSP APB 14-1 “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion”
(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 noncash 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 19
(f)	defined as net income (loss) available to common shareholders, as adjusted to remove the effects of certain items detailed on page 17

2009 Second Quarter Average Daily Production Increases 4% over 2009 First Quarter

Production and 5% over 2008 Second Quarter Production

As announced on July 30, 2009, the company’s daily production for the 2009 second quarter averaged 2.453 bcfe, an increase of 86 million cubic feet of natural gas equivalent (mmcfe), or 4%, over the 2.367 bcfe produced per day in the 2009 first quarter and an increase of 125 mmcfe, or 5%, over the 2.328 bcfe produced per day in the 2008 second quarter. Adjusted for the company’s 2009 voluntary production curtailments due to low natural gas and oil prices (which averaged approximately 74 mmcfe per day during the 2009 second quarter), the company’s three 2008 volumetric production payment sales (which averaged approximately 139 mmcfe per day during the 2009 second quarter) and the estimated impact from the company’s 2008 sales of Woodford Shale and Fayetteville Shale properties (which would have averaged approximately 81 mmcfe per day during the 2009 second quarter), Chesapeake’s sequential and year-over-year production growth rates would have been 4% and 16%, respectively, after making similar adjustments to prior quarters. The company is not currently curtailing production, but may do so again later this summer or fall as market conditions dictate. The company also expects that rising pipeline and gathering system pressures during the next few months will likely result in involuntary natural gas production curtailments across the industry.

Average Realized Prices, Hedging Results and Hedging Positions Detailed

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 thousand cubic feet (mcf) and $56.72 per bbl, for a realized natural gas equivalent price of $5.89 per thousand cubic feet of natural gas equivalent (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. Without realized hedging gains, the company’s average realized prices for the 2009 second quarter would have been $2.68 per mcf and $53.59 per bbl, for a natural gas equivalent price of $3.21 per mcfe. Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2009 second quarter were a negative $0.83 per mcf and a negative $6.03 per bbl.

By comparison, average prices realized during the 2008 second quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $8.18 per mcf and $76.96 per bbl, for a realized natural gas equivalent price of $8.55 per mcfe. Realized losses from natural gas and oil hedging activities during the 2008 second quarter generated a $1.55 loss per mcf and a $42.85 loss per bbl for a 2008 second quarter realized hedging loss of $423 million, or $1.99 per mcfe. Without realized hedging gains, the company’s average realized prices for the 2008 second quarter would have been $9.73 per mcf and $119.81 per bbl, for a natural gas equivalent price of $10.54 per mcfe. Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2008 second quarter were a negative $1.21 per mcf and a negative $4.17 per bbl.

The following tables summarize Chesapeake’s open hedge position through swaps and collars as of August 3, 2009. Depending on changes in natural gas and oil futures markets and management’s view of underlying natural gas and oil supply and demand trends, Chesapeake may either increase or decrease its hedging positions at any time in the future without notice.

Open Swap Positions as of August 3, 2009

	Natural Gas		Oil
Year	% Hedged	$ NYMEX	% Hedged	$ NYMEX
3Q-4Q 2009 Total(a)	52%	7.34	35%	87.05

2010 Total(a)	13%	9.78	40%	90.25

Open Natural Gas Collar Positions as of August 3, 2009

		Average Floor	Average Ceiling
Year	% Hedged	$ NYMEX	$ NYMEX
3Q-4Q 2009 Total(a)	38%	7.12	8.80

2010 Total(a)	8%	6.78	9.18

(a)

Certain open natural gas swap positions include knockout swaps with knockout provisions at prices ranging from $6.00 to $6.50 per mcf covering 5 bcf in 2009 and $5.45 to $6.75 per mcf covering 70 bcf in 2010, or approximately 63% of the company’s natural gas swap positions in 2010. Certain open natural gas collar positions include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 per mcf covering 36 bcf in 2009 and ranging from $4.25 to $6.00 per mcf covering 30 bcf in 2010, or approximately 23% and 42% of the company’s natural gas collar positions in 2009 and 2010, respectively. Also, certain open oil swap positions include knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $50 to $60 per bbl covering 3 mmbbls in 2009 and $60 per bbl covering 5 mmbbls in 2010, or virtually all of the company’s oil swap positions in 2009 and 2010.

As of July 31, 2009, Chesapeake’s natural gas and oil hedging positions with 14 different counterparties had a positive mark-to-market value of approximately $900 million.

The company’s updated forecasts for 2009 and 2010 are attached to this release in an Outlook dated August 3, 2009, labeled as Schedule “A,” which begins on page 20. This Outlook has been changed from the Outlook dated May 4, 2009, attached as Schedule “B,” which begins on page 25, to reflect various updated information.

Company Increases Proved Natural Gas and Oil Reserves by 0.7 Tcfe to 12.5 Tcfe and

Delivers 2009 Second Quarter Drilling and Net Acquisition Costs of $0.72 per Mcfe;

Company Record Set for Organic Reserve Additions and Reserve

Replacement During a Six-Month Period

Chesapeake began the 2009 second quarter with estimated proved reserves of 11.851 trillion cubic feet of natural gas equivalent (tcfe) and ended the 2009 second quarter with 12.525 tcfe, an increase of 674 bcfe, or 6%. During the 2009 second quarter, Chesapeake replaced 223 bcfe of production with an estimated 897 bcfe of new proved reserves for a reserve replacement rate of 402%. The quarter’s reserve movement included 493 bcfe of extensions, 343 bcfe of positive performance revisions, 156 bcfe of positive revisions resulting from natural gas and oil price increases between March 31, 2009 and June 30, 2009 and 95 bcfe of net divestitures.

Chesapeake’s total drilling and net acquisition costs for the 2009 second quarter were $0.72 per mcfe. This calculation excludes costs of $236 million for the acquisition of unproved properties and leasehold, $153 million for capitalized interest on unproved properties, and $26 million for seismic and asset retirement obligations, and also excludes positive revisions of proved reserves from higher natural gas and oil prices. Excluding these items and acquisition and divestiture activity, Chesapeake’s exploration and development costs through the drillbit during the 2009 second quarter were $0.87 per mcfe, giving effect to the benefit of $311 million in drilling carries associated with the Haynesville ($118 million), Fayetteville ($166 million) and Marcellus ($27 million) joint ventures. A complete reconciliation of 2009 second quarter proved reserves and finding and acquisition costs is presented on page 11 of this release.

During the 2009 first half, Chesapeake increased its estimated proved reserves 474 bcfe, or 4%, from 12.051 tcfe at year-end 2008. For the 2009 first half, Chesapeake replaced 436 bcfe of production with an estimated 910 bcfe of new proved reserves for a reserve replacement rate of 209%. The reserve movement in the 2009 first half included 920 bcfe of extensions, 740 bcfe of positive performance revisions, 664 bcfe of downward revisions resulting from a decrease in natural gas prices between December 31, 2008 and June 30, 2009 and 86 bcfe of net divestitures. Chesapeake’s 1,660 bcfe of extensions and performance revisions in the 2009 first half set a company record for the highest level of organic reserve additions during a six-month period and its organic reserve replacement rate of 381% for the six-month period was also the highest in the company’s history.

Chesapeake’s total drilling and net acquisition costs for the 2009 first half were $1.18 per mcfe. This calculation excludes costs of $746 million for the acquisition of unproved properties and leasehold, $314 million for capitalized interest on unproved properties, and $95 million for seismic and asset retirement obligations, and also excludes downward revisions of proved reserves from lower natural gas and oil prices. Excluding these items and acquisition and divestiture activity, Chesapeake’s exploration and development costs through the drillbit during the 2009 first half were $1.15 per mcfe, giving effect to the benefit of $580 million in drilling carries associated with the Haynesville ($204 million), Fayetteville ($337 million) and Marcellus ($39 million) joint ventures. A complete reconciliation of 2009 first half proved reserves and finding and acquisition costs is presented on page 12 of this release.

Chesapeake continued the industry’s most active drilling program during the 2009 first half, and drilled 580 gross operated wells (432 net wells with an average working interest of 74%) and participated in another 581 gross wells operated by other companies (44 net wells with an average working interest of 8%). The company’s drilling success rate was 99% for both company-operated and non-operated wells. Also during the 2009 first half, Chesapeake invested $1.509 billion in operated wells (using an average of 104 operated rigs) and $401 million in non-operated wells (using an average of 53 non-operated rigs) for total drilling, completing and equipping costs of $1.910 billion (net of carries).

As of June 30, 2009, the present value of future net cash flows, discounted at 10% per year, of Chesapeake’s estimated proved reserves (PV-10) was $11.076 billion using field differential adjusted prices based on NYMEX quarter-end prices of $3.89 per mcf and $70.00 per bbl. Chesapeake’s PV-10 changes by approximately $400 million for every $0.10 per mcf change in natural gas prices and approximately $65 million for every $1.00 per bbl change in oil prices.

The company calculates the standardized measure of future net cash flows in accordance with SFAS 69 only at year end because applicable income tax information on properties, including recently acquired natural gas and oil interests, is not readily available at other times during the year. As a result, the company is not able to reconcile the interim period-end PV-10 values to the standardized measure at such dates. The only difference between the two measures is that PV-10 is calculated before considering the impact of future income tax expenses, while the standardized measure includes such effects.

In addition to the PV-10 value of its proved reserves and the very significant value of its undeveloped leasehold, particularly in the Haynesville, Marcellus, Barnett and Fayetteville Shale plays and in the Colony and Texas Panhandle Granite Wash plays, the net book value of the company’s other assets (including gathering systems, compressors, land and buildings, investments and other noncurrent assets) was $6.369 billion as of June 30, 2009, $5.822 billion as of December 31, 2008 and $4.585 billion as of June 30, 2008.

Company Updates Asset Monetization Plans

During 2009 and 2010, Chesapeake plans to increase its liquidity, reduce its borrowings under its revolving credit facility and also strengthen its balance sheet through asset monetizations and the growth of its proved reserve base. As part of this plan, Chesapeake is targeting to monetize leasehold, producing properties, midstream assets and other assets for a range of $2.35 to $3.05 billion in 2009 and $1.25 to $1.80 billion in 2010. The company anticipates utilizing the monetization proceeds for capital expenditures and to reduce borrowings under its revolving credit facility.

Since March 31, 2009, the company has sold or agreed to sell approximately $900 million of assets including producing properties and gathering assets located primarily in Louisiana for $208 million (closed June 30), certain midstream and real estate surface assets for $172 million (closed on various dates in the second quarter), producing properties in central Texas for $75 million (closed July 1), and certain other midstream assets in multiple transactions for a total of approximately $70 million (closings anticipated on various dates in the third quarter). In addition, the company today sold certain Chesapeake-operated long-lived producing assets in South Texas in its fifth volumetric production payment transaction (VPP) for proceeds of $371 million, or $5.46 per mcfe of proved reserves. The assets included proved reserves of approximately 68 bcfe and current net production of approximately 55 mmcfe per day.

Chesapeake is planning to sell certain non-Haynesville Shale producing assets in Louisiana in its sixth VPP in the next 90 days for approximately $225-$250 million and also other mature producing assets in the second half of 2009 for approximately $200 million. The company is also working to finalize agreements with a private equity investor to sell a 50% minority interest in its Barnett Shale and Mid-Continent natural gas gathering and processing assets in the company’s midstream subsidiary, Chesapeake Midstream Partners. The company anticipates completing the midstream transaction in the 2009 third quarter for proceeds of more than $550 million. Finally, Chesapeake continues to have discussions with several companies about a possible joint venture on some or all of its Barnett Shale leasehold in a transaction targeted for completion by year-end 2009.

Management Comments

Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, “We are pleased to report our financial and operational results for the 2009 second quarter. Chesapeake was able to deliver very solid results for the quarter despite the 70% drop in natural gas prices over the past year as a result of our successful hedging program, strong operating capabilities, low cost structure, powerful assets and very attractive joint venture arrangements.

“We are particularly proud of our very strong quarterly proved reserve additions of 741 bcfe at a finding and net acquisition cost of $0.72 per mcfe and our outstanding organic reserve additions of 836 bcfe at a drilling cost of only $0.87 per mcfe. During the quarter, we benefited from $311 million of drilling carries and we anticipate receiving more than $3.7 billion of additional carries through 2013. We believe these carries, in combination with our very low-cost Big 4 shale and two major Granite Wash plays will result in very high returns on invested capital, reduced capital expenditures and a rapidly improving balance sheet for years to come.

“Our high level of hedging at attractive prices should continue to insulate Chesapeake from potentially soft natural gas prices during the remainder of 2009. We believe that dramatically reduced U.S. drilling activity should soon lead to steep natural gas production declines in the industry. This should work to tighten natural gas markets, lift natural gas prices and improve the company’s profitability in 2010 and beyond.

“Chesapeake’s 2009 asset monetization program is on track with $900 million of proceeds captured to date and multiple transactions progressing toward completion in the second half of 2009 that will lead to total asset monetizations for the year of between $2.35 and $3.05 billion. We anticipate this program, combined with strong operating cash flow, will enable the company to continue funding its highly economic investment program solely from internal resources while at the same time reducing the company’s debt levels both absolutely and on a per proved mcfe basis. We believe Chesapeake is very well positioned to deliver substantial quarterly increases in value to our investors in the years ahead.”

Conference Call Information

A conference call to discuss this release has been scheduled for Tuesday morning, August 4, 2009, at 9:00 a.m. EDT. The telephone number to access the conference call is913-981-5574 or toll-free 888-596-2560. The passcode for the call is 3824854. 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, 2009 through midnight EDT on August 18, 2009. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 3824854. The conference call will also be webcast live on the Internet and can be accessed by going to Chesapeake’s website at www.chk.com in the “Events” subsection of the “Investors” section of our website. The webcast of the conference call will be available on our website for one year.

This press release and the accompanying Outlooks include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of natural gas and oil reserves, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, planned capital expenditures and anticipated asset acquisitions and sales, as well as statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures concerning the fair value of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.

CHESAPEAKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)

THREE MONTHS ENDED:	June 30,			June 30,
THREE MONTHS ENDED:	2009			2008 (a)
	$		$/mcfe	$		$/mcfe
REVENUES:
Natural gas and oil sales		1,097	4.92		(1,594)	(7.53)
Natural gas and oil marketing sales		532	2.38		1,099	5.19
Service operations revenue		44	0.20		40	0.19
Total Revenues		1,673	7.50		(455)	(2.15)

OPERATING COSTS:
Production expenses		213	0.95		219	1.03
Production taxes		24	0.11		88	0.41
General and administrative expenses		74	0.33		101	0.48
Natural gas and oil marketing expenses		500	2.24		1,075	5.08
Service operations expense		46	0.21		32	0.15
Natural gas and oil depreciation, depletion andamortization		295	1.32		523	2.47
Depreciation and amortization of other assets		58	0.26		40	0.19
Impairment of other assets		5	0.02		—	—
Restructuring costs		34	0.16		—	—
Total Operating Costs		1,249	5.60		2,078	9.81

INCOME (LOSS) FROM OPERATIONS		424	1.90		(2,533)	(11.96)

OTHER INCOME (EXPENSE):
Other income (expense)		(2)	(0.01)		(1)	(0.01)
Interest expense		(22)	(0.10)		(54)	(0.25)
Impairment of investments		(10)	(0.04)		—	—
Loss on exchanges of Chesapeake debt		(2)	(0.01)		—	—
Total Other Income (Expense)		(36)	(0.16)		(55)	(0.26)

INCOME (LOSS) BEFORE INCOME TAXES		388	1.74		(2,588)	(12.22)

Income Tax Expense (Benefit):
Current		1	—		3	0.01
Deferred		144	0.65		(999)	(4.71)
Total Income Tax Expense (Benefit)		145	0.65		(996)	(4.70)

NET INCOME (LOSS)		243	1.09		(1,592)	(7.52)

Preferred stock dividends		(6)	(0.03)		(9)	(0.04)
Loss on conversion/exchange of preferred stock		—	—		(42)	(0.20)

NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS		237	1.06		(1,643)	(7.76)

EARNINGS (LOSS) PER COMMON SHARE:

Basic	$	0.39		$	(3.16)
Assuming dilution	$	0.39		$	(3.16)

WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)

Basic		603			521
Assuming dilution		610			521

(a)	Adjusted for the retrospective application of FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion.”

CHESAPEAKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)

SIX MONTHS ENDED:	June 30,			June 30,
SIX MONTHS ENDED:	2009			2008 (a)
	$		$/mcfe	$		$/mcfe
REVENUES:
Natural gas and oil sales		2,494	5.72		(821)	(1.97)
Natural gas and oil marketing sales		1,084	2.49		1,895	4.55
Service operations revenue		90	0.20		82	0.20
Total Revenues		3,668	8.41		1,156	2.78

OPERATING COSTS:
Production expenses		451	1.03		419	1.01
Production taxes		46	0.11		163	0.39
General and administrative expenses		164	0.38		180	0.44
Natural gas and oil marketing expenses		1,023	2.35		1,849	4.44
Service operations expense		87	0.20		67	0.16
Natural gas and oil depreciation, depletion andamortization		742	1.70		1,038	2.49
Depreciation and amortization of other assets		115	0.26		76	0.18
Impairment of natural gas and oil properties and other assets		9,635	22.08		—	—
Restructuring costs		34	0.08		—	—
Total Operating Costs		12,297	28.19		3,792	9.11

INCOME (LOSS) FROM OPERATIONS		(8,629)	(19.78)		(2,636)	(6.33)

OTHER INCOME (EXPENSE):
Other income (expense)		5	0.01		(11)	(0.03)
Interest expense		(8)	(0.02)		(153)	(0.37)
Impairment of investments		(162)	(0.37)		—	—
Loss on exchanges of Chesapeake debt		(2)	—		—	—
Total Other Income (Expense)		(167)	(0.38)		(164)	(0.40)

INCOME (LOSS) BEFORE INCOME TAXES		(8,796)	(20.16)		(2,800)	(6.73)

Income Tax Expense (Benefit):
Current		1	—		3	0.01
Deferred		(3,299)	(7.56)		(1,081)	(2.60)
Total Income Tax Expense (Benefit)		(3,298)	(7.56)		(1,078)	(2.59)

NET INCOME (LOSS)		(5,498)	(12.60)		(1,722)	(4.14)

Preferred stock dividends		(12)	(0.03)		(21)	(0.05)
Loss on conversion/exchange of preferred stock		—	—		(42)	(0.10)

NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS		(5,510)	(12.63)		(1,785)	(4.29)

EARNINGS (LOSS) PER COMMON SHARE:

Basic	$	(9.18)		$	(3.52)
Assuming dilution	$	(9.18)		$	(3.52)

WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)

Basic		600			507
Assuming dilution		600			507

(a)	Adjusted for the retrospective application of FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion.”

CHESAPEAKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)

	June 30,		December 31,
	2009		2008 (a)

Cash and cash equivalents	$	554	$	1,749
Other current assets		2,394		2,543
Total Current Assets		2,948		4,292

Property and equipment (net)		26,736		33,308
Other assets		785		993
Total Assets	$	30,469	$	38,593

Current liabilities	$	2,974	$	3,621
Long-term debt, net (b)		13,568		13,175
Asset retirement obligation		279		269
Other long-term liabilities		740		311
Deferred tax liability		906		4,200
Total Liabilities		18,467		21,576

Stockholders’ Equity		12,002		17,017

Total Liabilities & Stockholders’ Equity	$	30,469	$	38,593

Common Shares Outstanding (in millions)		630		607

CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

($ in millions)

(unaudited)

	June 30,		% of Total Book	December 31,		% of Total Book
	2009		Capitalization	2008 (a)		Capitalization

Total debt, net cash (b)	$	13,014	52%	$	11,426	40%
Stockholders' equity		12,002	48%		17,017	60%
Total	$	25,016	100%	$	28,443	100%

(a)	Adjusted for the retrospective application of FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion.”
(b)	Includes $3.131 billion of borrowings under both the company’s $3.5 billion revolving bank credit facility and the company’s $460 million midstream revolving bank credit facility. At June 30, 2009, the company had $792 million of additional borrowing capacity under these two revolving bank credit facilities.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADDITIONS TO NATURAL GAS AND OIL PROPERTIES

($ in millions, except per-unit data)

(unaudited)

	Reserves
THREE MONTHS ENDED JUNE 30, 2009	Cost			(in bcfe)	$/mcfe

Exploration and development costs	$	724		836	0.87
Acquisition of proved properties		—		4	—
Divestitures of proved properties		(193)		(99)	1.96
Other		2	(b)	—	—
Drilling and net acquisition cost		533		741	0.72

Revisions – price		—		156	—

Acquisition of unproved properties and leasehold		236		—	—
Capitalized interest		153	(c)	—	—
Geological and geophysical costs		30		—	—
Leasehold, capitalized interest, geological and geophysical		419		—	—

Subtotal		952		897	1.06

Asset retirement obligation and other		(4)		—	—
Total	$	948		897	1.06

(a)	Includes 343 bcfe of performance revisions (247 bcfe relating to infill drilling and increased density locations and 96 bcfe of other performance related revisions) and excludes upward revisions of 156 bcfe resulting from natural gas and oil price increases between March 31, 2009 and June 30, 2009.
(b)	Includes adjustments to certain acquisitions and divestitures that closed during prior periods.
(c)	Includes capitalized interest on unproved leasehold and geological and geophysical costs.

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

THREE MONTHS ENDED JUNE 30, 2009

(unaudited)

	Bcfe

Beginning balance, 04/01/09	11,851
Production	(223)
Acquisitions	4
Divestitures	(99)
Revisions – performance	343
Revisions – price	156
Extensions and discoveries	493
Ending balance, 06/30/09	12,525

Reserve replacement	897
Reserve replacement ratio (a)	402%

(a)

The company uses the reserve replacement ratio as an indicator of the company’s ability to replenish 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 ADDITIONS TO NATURAL GAS AND OIL PROPERTIES

($ in millions, except per-unit data)

(unaudited)

	Reserves
SIX MONTHS ENDED JUNE 30, 2009	Cost			(in bcfe)		$/mcfe

Exploration and development costs	$	1,910		1,660	(a)		1.15
Acquisition of proved properties		17		13			1.30
Divestitures of proved properties		(193)		(99)			1.96
Other		118	(b)	—			—
Drilling and net acquisition cost		1,852		1,574			1.18

Revisions – price		—		(664)			—

Acquisition of unproved properties and leasehold		746		—			—
Capitalized interest		314	(c)	—			—
Geological and geophysical costs		97		—			—
Leasehold, capitalized interest, geological and geophysical		1,157		—			—

Subtotal		3,009		910			3.30

Asset retirement obligation and other		(2)		—			—
Total	$	3,007		910			3.30

(a)	Includes 740 bcfe of performance revisions (564 bcfe relating to infill drilling and increased density locations and 176 bcfe of other performance related revisions) and excludes downward revisions of 664 bcfe resulting from natural gas and oil price declines between December 31, 2008 and June 30, 2009.
(b)	Includes adjustments to certain acquisitions and divestitures that closed during prior periods.
(c)	Includes capitalized interest on unproved leasehold and geological and geophysical costs.

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

SIX MONTHS ENDED JUNE 30, 2009

(unaudited)

	Bcfe

Beginning balance, 01/01/09	12,051
Production	(436)
Acquisitions	13
Divestitures	(99)
Revisions – performance	740
Revisions – price	(664)
Extensions and discoveries	920
Ending balance, 06/30/09	12,525

Reserve replacement	910
Reserve replacement ratio (a)	209%

(a)

CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA – NATURAL GAS AND OIL SALES AND INTEREST EXPENSE

(unaudited)

	THREE MONTHS ENDED				SIX MONTHS ENDED
	June 30,				June 30,
	2009		2008		2009		2008

Natural Gas and Oil Sales ($ in millions):
Natural gas sales	$	548	$	1,896	$	1,223	$	3,329
Natural gas derivatives – realized gains (losses)		587		(302)		1,096		(34)
Natural gas derivatives – unrealized losses		(192)		(2,526)		(123)		(3,528 )

Total Natural Gas Sales		943		(932)		2,196		(233)

Oil sales		169		337		272		596
Oil derivatives – realized gains (losses)		10		(121)		19		(174)
Oil derivatives – unrealized gains (losses)		(25)		(878)		7		(1,010)

Total Oil Sales		154		(662)		298		(588)

Total Natural Gas and Oil Sales	$	1,097	$	(1,594)	$	2,494	$	(821)

Average Sales Price – excluding gains (losses) on derivatives:
Natural gas ($ per mcf)	$	2.68	$	9.73	$	3.06	$	8.70
Oil ($ per bbl)	$	53.59	$	119.81	$	45.19	$	107.13
Natural gas equivalent ($ per mcfe)	$	3.21	$	10.54	$	3.43	$	9.43

Average Sales Price – excluding unrealized gains (losses) on derivatives:
Natural gas ($ per mcf)	$	5.56	$	8.18	$	5.80	$	8.61
Oil ($ per bbl)	$	56.72	$	76.96	$	48.32	$	75.86
Natural gas equivalent ($ per mcfe)	$	5.89	$	8.55	$	5.98	$	8.93

Interest Expense (Income) ($ in millions):
Interest	$	69	$	72	$	107	$	158
Derivatives – realized gains		(5)		(4)		(12)		(4)
Derivatives – unrealized gains		(42)		(14)		(87)		(1)
Total Interest Expense	$	22	$	54	$	8	$	153

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

($ in millions)

(unaudited)

THREE MONTHS ENDED:		June 30,		June 30,
THREE MONTHS ENDED:		2009		2008 (a)

Beginning cash	$	83	$	1
Cash provided by operating activities	$	737	$	1,283
Cash (used in) provided by investing activities:
Exploration and development of natural gas and oil properties	$	(745)	$	(1,529)
Acquisitions proved and unproved properties and leasehold		(160)		(1,917)
Divestitures of proved and unproved properties and leasehold and VPPs		228		620
Additions to other property and equipment		(313)		(678)
Capitalized interest on unproved properties		(153)		(121)
Other		45		(56)
Total cash used in investing activities	$	(1,098)	$	(3,681)
Cash provided by financing activities	$	832	$	2,397
Ending cash	$	554	$	—

SIX MONTHS ENDED:		June 30,		June 30,
SIX MONTHS ENDED:		2009		2008 (a)

Beginning cash	$	1,749	$	1
Cash provided by operating activities	$	1,998	$	2,798
Cash (used in) provided by investing activities:
Exploration and development of natural gas and oil properties		( 2,092)		(2,935)
Acquisitions proved and unproved properties and leasehold		( 412)		(2,835)
Divestitures of proved and unproved properties, leasehold and VPPs		228		863
Additions to other property and equipment		( 980)		(1,229)
Capitalized interest on unproved properties		( 314)		(224)
Other		105		(13)
Total cash used in investing activities	$	( 3,465)	$	(6,373)
Cash provided by financing activities	$	272	$	3,574
Ending cash	$	554	$	—

(a)	2008 data adjusted for the retrospective application of FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion.”

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:	2009		2009		2008 (a)

CASH PROVIDED BY OPERATING ACTIVITIES	$	737	$	1,261	$	1,283

Adjustments:
Changes in assets and liabilities		269		(262)		185

OPERATING CASH FLOW (b)	$	1,006	$	999	$	1,468

THREE MONTHS ENDED:	June 30,		March 31,		June 30,
THREE MONTHS ENDED:	2009		2009		2008 (a)

NET INCOME (LOSS)	$	243	$	(5,740)	$	(1,592)

Income tax expense (benefit)		145		(3,444)		(996)
Interest expense		22		(14)		54
Depreciation and amortization of other assets		58		57		40
Natural gas and oil depreciation, depletion and amortization		295		447		523

EBITDA (c)	$	763	$	(8,694)	$	(1,971)

THREE MONTHS ENDED:	June 30,		March 31,		June 30,
THREE MONTHS ENDED:	2009		2009		2008 (a)

CASH PROVIDED BY OPERATING ACTIVITIES	$	737	$	1,261	$	1,283

Changes in assets and liabilities		269		(262)		185
Interest expense		22		(14)		54
Unrealized gains (losses) on natural gas and oil derivatives		(216)		101		(3,406)
Impairment of natural gas and oil properties and other assets		(5)		(9,630)		—
Impairment of investments		—		(153)		—
Restructuring costs		(29)		—		—
Other non-cash items		(15)		3		(87)

EBITDA (c)	$	763	$	(8,694)	$	(1,971)

(a)	Adjusted for the retrospective application of FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion.”
(b)	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 performance 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.
(c)	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:	2009		2008 (a)

CASH PROVIDED BY OPERATING ACTIVITIES	$	1,998	$	2,798

Adjustments:
Changes in assets and liabilities		7		202

OPERATING CASH FLOW (b)	$	2,005	$	3,000

SIX MONTHS ENDED:	June 30,		June 30,
SIX MONTHS ENDED:	2009		2008 (a)

NET INCOME (LOSS)	$	(5,498)	$	(1,722)

Income tax expense (benefit)		(3,298)		(1,078)
Interest expense		8		153
Depreciation and amortization of other assets		115		76
Natural gas and oil depreciation, depletion and amortization		742		1,038

EBITDA (c)	$	(7,931)	$	(1,533)

SIX MONTHS ENDED:	June 30,		June 30,
SIX MONTHS ENDED:	2009		2008 (a)

CASH PROVIDED BY OPERATING ACTIVITIES	$	1,998	$	2,798

Changes in assets and liabilities		7		202
Interest expense		8		153
Unrealized gains (losses) on natural gas and oil derivatives		(116)		(4,538)
Impairment of natural gas and oil properties and other assets		(9,635)		—
Impairment of investments		(153)		—
Restructuring costs		(29)		—
Other non-cash items		(11)		(148)

EBITDA (c)	$	(7,931)	$	(1,533)

(a)	Adjusted for the retrospective application of FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion.”
(b)	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 performance 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.
(c)	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 ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS

($ in millions, except per-share data)

(unaudited)

	June 30,		March 31,		June 30,
THREE MONTHS ENDED:	2009		2009		2008 (a)

Net income (loss) available to common shareholders	$	237		(5,746)	$	(1,643)

Adjustments:
Unrealized (gains) losses on derivatives, net of tax		109		(91)		2,086
Impairment of natural gas and oil properties and other assets, net of tax		3		6,019		—
Impairment of investments, net of tax		6		95		—
Restructuring costs, net of tax		21		—		—
Loss on exchanges of Chesapeake debt, net of tax		1		—		—
Loss on conversions or exchanges of preferred stock		—		—		42

Adjusted net income available to common shareholders (b)		377		277		485
Preferred stock dividends		6		6		9
Interest on 2.75% contingent convertible notes, net of tax		—		—		3
Total adjusted net income	$	383	$	283	$	497

Weighted average fully diluted shares outstanding (c)		622		613		553

Adjusted earnings per share assuming dilution(b)	$	0.62	$	0.46	$	0.90

(a)	Adjusted for the retrospective application of FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion.”
(b)	Adjusted net income available to common shareholders 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 shareholders 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 shareholders 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.
(c)	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 SHAREHOLDERS

($ in millions, except per-share data)

(unaudited)

	June 30,		June 30,
SIX MONTHS ENDED:	2009		2008 (a)

Net income (loss) available to common shareholders	$	(5,510)	$	(1,785)

Adjustments:
Unrealized (gains) losses on derivatives, net of tax		19		2,790
Impairment of natural gas and oil properties and other assets, net of tax		6,022		—
Impairment of investments, net of tax		102		—
Restructuring cost, net of tax		21		—
Loss on exchanges of Chesapeake debt, net of tax		1		—
Loss on conversions or exchanges of preferred stock		—		42

Adjusted net income available to common shareholders (b)		655		1,047
Preferred stock dividends		12		21
Interest on 2.75% contingent convertible notes, net of tax		—		3
Total adjusted net income	$	667	$	1,071

Weighted average fully diluted shares outstanding (c)		618		541

Adjusted earnings per share assuming dilution(b)	$	1.08	$	1.98

(a)	Adjusted for the retrospective application of FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion.”
(b)	Adjusted net income available to common shareholders 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 shareholders 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 shareholders 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.
(c)	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 EBITDA

($ in millions)

(unaudited)

	June 30,		March 31,		June 30,
THREE MONTHS ENDED:	2009		2009		2008 (a)

EBITDA	$	763	$	(8,694)	$	(1,971)

Adjustments, before tax:
Unrealized (gains) losses on natural gas and oil derivatives		216		(101)		3,406
Loss on exchanges of Chesapeake debt		2		—
Impairment of natural gas and oil properties and other assets		5		9,630		—
Impairment of investments		10		153		—
Restructuring costs		34		—		—

Adjusted ebitda (b)	$	1,030	$	988	$	1,435

(a)	Adjusted for the retrospective application of FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion.”
(b)	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 EBITDA

($ in millions)

(unaudited)

	June 30,		June 30,
SIX MONTHS ENDED:	2009		2008 (a)

EBITDA	$	(7,931)	$	(1,533)

Adjustments, before tax:
Unrealized (gains) losses on natural gas and oil derivatives		116		4,538
Loss on exchanges of Chesapeake debt		2		—
Impairment of natural gas and oil properties and other assets		9,635		—
Impairment of investments		162		—
Restructuring costs		34

Adjusted ebitda (b)	$	2,018	$	3,005

(a)	Adjusted for the retrospective application of FSP APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion.”
(b)	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.

SCHEDULE “A”

CHESAPEAKE’S OUTLOOK AS OF AUGUST 3, 2009

Years Ending December 31, 2009 and 2010

Our policy is to periodically provide guidance on certain factors that affect our future financial performance. As of August 3, 2009, we are using the following key assumptions in our projections for 2009 and 2010.

The primary changes from our May 4, 2009 Outlook are in italicized bold and are explained as follows:

1)	Our production guidance has been updated. It reflects anticipated volumetric production payment transactions in 2009 and 2010 and does not assume any future voluntary production curtailments;

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

3)	Our NYMEX natural gas and oil price assumptions for realized hedging effects and estimating future operating cash flow have been updated for 2009 and 2010; and

4)	Certain cost, book and cash income tax and share assumptions have been updated.

	Year Ending 12/31/2009		Year Ending 12/31/2010
Estimated Production:
Natural gas – bcf		805 – 815		865 – 885
Oil – mbbls		12,000		12,000
Natural gas equivalent – bcfe		875 – 885		940 – 960

Daily natural gas equivalent midpoint – mmcfe		2,410		2,600

Year-over-year estimated production increase		4 – 5%		7 – 8%
Year-over-year estimated production increase excluding divestitures and curtailments		8 – 9%		9 – 10%

NYMEX Prices (a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$	4.30	$	6.25
Oil - $/bbl	$	55.67	$	70.00

Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$	2.68	$	0.93
Oil - $/bbl	$	5.65	$	7.37

Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf		20 – 30%		15 – 20%
Oil - $/bbl		7 – 10%		5 – 7%

Operating Costs per Mcfe of Projected Production:
Production expense	$	1.10 – 1.20	$	1.10 – 1.20
Production taxes (~ 5% of O&G revenues)(b)	$	0.20 – 0.25	$	0.30 – 0.35
General and administrative(c)	$	0.33 – 0.37	$	0.33 – 0.37
Stock-based compensation (non-cash)	$	0.10 – 0.12	$	0.10 – 0.12
DD&A of natural gas and oil assets	$	1.50 – 1.70	$	1.50 – 1.70
Depreciation of other assets	$	0.25 – 0.30	$	0.25 – 0.30
Interest expense(d)	$	0.30 – 0.35	$	0.35 – 0.40

Other Income per Mcfe:
Natural gas and oil midstream income	$	0.10 – 0.12	$	0.09 – 0.11
Service operations income	$	0.04 – 0.06	$	0.04 – 0.06

Book Tax Rate (all deferred)		37.5%		39%

Equivalent Shares Outstanding (in millions):
Basic		610 – 615		625 – 630
Diluted		625 – 630		640 – 645
Cash Flow Projections ($ in millions):

Net inflows:
Operating cash flow before changes in assets and liabilities(e)(f)	$	3,700 – 3,750	$	3,950 – 4,650

Leasehold and producing property transactions:
Sale of leasehold and producing properties	$	1,750 – 2,250	$	1,000 – 1,500
Acquisition of leasehold and producing properties:	$	(500 – 750)	$	(350 – 500)
Net leasehold and producing property transactions	$	1,250 – 1,500	$	650 – 1,000

Midstream equity financings and system sales	$	600 – 800	$	250 – 300
Midstream credit facility draws (repayments)	$	(200 – 300)	$	150 – 200
Proceeds from investments and other	$	450		–
Total Cash Inflows	$	5,800 – 6,200	$	5,000 – 6,150

Net outflows:
Drilling	$	3,000 – 3,200	$	3,400 – 3,700
Geophysical costs	$	100 – 125	$	100 – 125
Midstream infrastructure and compression	$	700 – 900	$	300 – 400
Other PP&E	$	400 – 450	$	200 – 250
Dividends, senior notes redemption, capitalized interest, etc.	$	600 – 800	$	600 – 700
Cash income taxes	$	175 – 200	$	(200 – 300)
Total Cash Outflows	$	4,975 – 5,675	$	4,400 – 4,875

Net Cash Change	$	525 – 825	$	600 – 1,275

At June 30, 2009, the company had $1.3 billion of cash and cash equivalents and additional borrowing capacity under its two revolving bank credit facilities.

(a)	NYMEX natural gas prices have been updated for actual contract prices through August 2009 and NYMEX oil prices have been updated for actual contract prices through June 2009.
(b)	Severance tax per mcfe is based on NYMEX prices of $55.67 per bbl of oil and $5.00 to $6.00 per mcf of natural gas during 2009 and $70.00 per bbl of oil and $7.00 to $8.00 per mcf of natural gas during 2010.
(c)	Excludes expenses associated with noncash stock compensation.
(d)	Does not include gains or losses on interest rate derivatives (SFAS 133).
(e)	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.
(f)	Assumes NYMEX natural gas prices of $5.00 to $6.00 per mcf and NYMEX oil prices of $60.00 per bbl in 2009 and NYMEX natural gas prices of $6.00 to $7.00 per mcf and NYMEX oil prices of $70.00 per bbl in 2010.

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)	For swap instruments, Chesapeake receives a fixed price for the commodity and pays a floating market price to the counterparty.
2)	Collars 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 call and the put strike price, no payments are due from either party.
3)	For 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)	For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake.
5)	Basis protection swaps are arrangements that guarantee a price differential to NYMEX for natural gas or oil from a specified delivery point. For Mid-Continent 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.
6)	A three-way collar contract consists of a standard collar contract plus a written put option with a strike price below the floor price of the collar. In addition to the settlement of the collar, the put option requires Chesapeake to make a payment to the counterparty equal to the difference between the put option price and the settlement price if the settlement price for any settlement period is below the put option strike price.

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

Commodity markets are volatile, and as a result, Chesapeake’s hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction.

Chesapeake enters into natural gas and oil derivative transactions in order to mitigate a portion of its exposure to adverse market changes in natural gas and oil prices. Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to natural gas and oil sales. All realized gains and losses from natural gas and oil derivatives are included in natural gas and oil sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these nonqualifying derivatives that occur prior to their maturity (i.e., because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within natural gas and oil sales. Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in natural gas and oil sales.

Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas trades:

	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 2009	75.4	$	7.38			$	19.4
Q4 2009	126.7	$	7.33			$	31.2
Q3-Q4 2009(a)	202.0	$	7.35	410	49%	$	50.6	$	0.12

Total 2010(a)	110.2	$	9.78	875	13%	$	224.6	$	0.26

(a)	Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at prices ranging from $6.00 to $6.50 covering 5 bcf in 2009 and $5.45 to $6.75 covering 70 bcf in 2010.

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

	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 2009	102.7	$	7.02	$	8.76
Q4 2009	52.1	$	7.34	$	8.88
Q3-Q4 2009(a)	154.8	$	7.12	$	8.80	410	38%

Total 2010(a)	70.6	$	6.78	$	9.18	875	8%

(a)	Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 36 bcf in 2009 and ranging from $4.25 to $6.00 covering 30 bcf in 2010.

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

	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

Q3 2009	14.0	$	6.75	$	1.61
Q4 2009	13.3	$	6.78	$	1.63
Q3-Q4 2009	27.3	$	6.76	$	1.62	410	7%

Total 2010	298.5	$	10.19	$	0.58	875	34%

The company has the following natural gas basis protection swaps in place:

	Mid-Continent			Appalachia
	Volume (Bcf)	NYMEX less(a)		Volume (Bcf)	NYMEX plus(a)
2009	10.9	$	1.57	8.9	$	0.27
2010	—		—	10.2		0.26
2011	45.1		0.82	12.1		0.25
2012	43.2		0.85	—		—
Totals	99.2	$	0.92	31.2	$	0.26

(a)	weighted average

We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition in November 2005. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($19 million as of June 30, 2009). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our natural gas and oil revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to natural gas and oil revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in natural gas and oil revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.

Pursuant to SFAS 149 “Amendment of SFAS 133 on Derivative Instruments and Hedging Activities,” the assumed CNR derivative instruments are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows.

The following details the CNR derivatives (natural gas swaps) we have assumed:

	Open Swaps (Bcf)	Avg. NYMEX Strike Price Of Open Swaps		Avg. Fair Value Upon Acquisition of Open Swaps		Initial Liability Acquired		Assuming Natural Gas Production (Bcf)	Open Swap Positions as a % of Estimated Total Natural Gas Production
Q3 2009	4.6	$	5.18	$	6.89	$	(1.71)
Q4 2009	4.6	$	5.18	$	7.32	$	(2.14)
Q3-Q4 2009	9.2	$	5.18	$	7.11	$	(1.92)	410	2%

Note: Not shown above are collars covering 1.84 bcf of production in 2009 at an average floor and ceiling of $4.50 and $6.00.

The company also has the following crude oil swaps in place:

	Open Swaps (mbbls)	Avg. NYMEX Strike Price		Assuming Oil Production (mbbls)	Open Swap Positions as a % of Estimated Total Oil Production	Total Losses from Lifted Trades ($ millions)		Total Lifted Losses per bbl of Estimated Total Oil Production
Q3 2009	1,058	$	87.05			$	(0.3)
Q4 2009	1,058	$	87.05			$	(0.4)
Q3-Q4 2009(a)	2,116	$	87.05	5,974	35%	$	(0.7)	$	(0.12)

Total 2010(a)	4,745	$	90.25	12,000	40%	$	(6.9)	$	(0.58)

(a)	Certain hedging arrangements knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $50.00 to $60.00 covering 3 mmbbls in 2009 and $60.00 covering 5 mmbbls in 2010.

Note: Not shown above are written call options covering 3 mmbbls of oil production in 2009 at a weighted average price of $101.79 per bbl for a weighted average premium of $0.64 per bbl and 5 mmbbls of oil production in 2010 at a weighted average price of $100.71 per bbl for a weighted average premium of $1.20 per bbl.

SCHEDULE “B”

CHESAPEAKE’S PREVIOUS OUTLOOK AS OF MAY 4, 2009

(PROVIDED FOR REFERENCE ONLY)

NOW SUPERSEDED BY OUTLOOK AS OF AUGUST 3, 2009

Years Ending December 31, 2009 and 2010

Our policy is to periodically provide guidance on certain factors that affect our future financial performance. As of May 4, 2009, we are using the following key assumptions in our projections for 2009 and 2010.

The primary changes from our February 17, 2009 Outlook are in italicized bold and are explained as follows:

1)	Our production guidance has been updated to reflect estimated production curtailments starting in March 2009 and estimated to continue through June 2009 as well as anticipated volumetric production payment transactions in 2009 and in 2010;

2)	Projected effects of changes in our hedging positions have been updated, particularly the restructuring of certain 2010 knockout swap positions;

3)	Our NYMEX natural gas and oil price assumptions for realized hedging effects and estimating future operating cash flow have been reduced for 2009;

4)	Certain cost, book and cash income tax rate and share assumptions have been updated; and

5)	Our rate of DD&A for natural gas and oil assets has been reduced to reflect our 2009 first quarter impairment charge.

	Year Ending 12/31/2009	Year Ending 12/31/2010
Estimated Production:
Natural gas – bcf	795 – 805	840 – 880
Oil – mbbls	12,000	12,000
Natural gas equivalent – bcfe	865 – 875	915 – 955

Daily natural gas equivalent midpoint – mmcfe	2,380	2,560

Year-over-year estimated production increase	3 – 4%	7 – 8%
Year-over-year estimated production increase excluding divestitures and curtailments	7 – 8%	9 – 10%

NYMEX Prices (a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$4.93	$7.00
Oil - $/bbl	$48.27	$70.00

Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$2.29	$0.89
Oil - $/bbl	$1.71	$7.37

Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	20 – 30%	15 – 20%
Oil - $/bbl	7 – 10%	5 – 7%

Operating Costs per Mcfe of Projected Production:
Production expense	$1.10 – 1.20	$1.10 – 1.20
Production taxes (~ 5% of O&G revenues)(b)	$0.20 – 0.25	$0.30 – 0.35
General and administrative(c)	$0.33 – 0.37	$0.33 – 0.37
Stock-based compensation (non-cash)	$0.10 – 0.12	$0.10 – 0.12
DD&A of natural gas and oil assets	$1.50 – 1.70	$1.50 – 1.70
Depreciation of other assets	$0.25 – 0.30	$0.25 – 0.30
Interest expense(d)	$0.30 – 0.35	$0.35 – 0.40

Other Income per Mcfe:
Natural gas and oil midstream income	$0.10 – 0.12	$0.09 – 0.11
Service operations income	$0.04 – 0.06	$0.04 – 0.06

Book Tax Rate (all deferred)	37.5%	39%

Equivalent Shares Outstanding (in millions):
Basic	605 – 610	615 – 620
Diluted	615 – 620	625 – 630
Cash Flow Projections ($ in millions):

Net inflows:
Operating cash flow before changes in assets and liabilities(e)(f)	$3,600 – 3,650	$3,900 – 4,600

Leasehold and producing property transactions:
Sale of leasehold and producing properties	$1,500 – 2,000	$1,000 – 1,500
Acquisition of leasehold and producing properties:	($450 – $600)	($350 - $500)
Net leasehold and producing property transactions	$1,050 – 1,400	$650 – 1,000

Midstream financings	$500 – 600	$500 – 600
Proceeds from investments and other	$450	–
Total Cash Inflows	$5,600 – 6,100	$5,050 – 6,200

Net outflows:
Drilling	$2,700 – 2,900	$3,100 – 3,400
Geophysical costs	$100 – 125	$100 – 125
Midstream infrastructure and compression	$700 – 900	$300 – 400
Other PP&E	$400 – 450	$200 – 250
Dividends, senior notes redemption, capitalized interest, etc.	$600 – 800	$600 – 700
Cash income taxes	$175 – 200	–
Total Cash Outflows	$4,675 – 5,375	$4,300 – 4,875

Net Cash Change	$725 – 925	$750 – 1,325

At March 31, 2009, the company had $1.7 billion of cash and cash equivalents and additional borrowing capacity under its two revolving bank credit facilities.

(a)	NYMEX natural gas prices have been updated for actual contract prices through May 2009 and NYMEX oil prices have been updated for actual contract prices through March 2009.
(b)	Severance tax per mcfe is based on NYMEX prices of $48.27 per bbl of oil and $5.00 to $6.00 per mcf of natural gas during 2009 and $70.00 per bbl of oil and $7.00 to $8.00 per mcf of natural gas during 2010.
(c)	Excludes expenses associated with noncash stock compensation.
(d)	Does not include gains or losses on interest rate derivatives (SFAS 133).
(e)	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.
(f)	Assumes NYMEX natural gas prices of $5.00 to $6.00 per mcf and NYMEX oil prices of $50.00 per bbl in 2009 and NYMEX natural gas prices of $6.00 to $7.00 per mcf and NYMEX oil prices of $70.00 per bbl in 2010.

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)	For swap instruments, Chesapeake receives a fixed price and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
2)	Basis protection swaps are arrangements that guarantee a price differential for oil or natural gas from a specified delivery point. For Mid-Continent basis protection swaps, which 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 basis protection swaps, which 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.
3)	For 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 predetermined knockout prices.
4)	For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a "cap" limiting the counterparty's exposure. In other words, there is no limit to Chesapeake's exposure but there is a limit to the downside exposure of the counterparty.
5)	For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake.
6)	Collars 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 call and the put strike price, no payments are due from either party.
7)	A three-way collar contract consists of a standard collar contract plus a written put option with a strike price below the floor price of the collar. In addition to the settlement of the collar, the put option requires Chesapeake to make a payment to the counterparty equal to the difference between the put option price and the settlement price if the settlement price for any settlement period is below the put option strike price.

	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 2009	64.4	$	7.70			$	18.9
Q3 2009	68.5	$	7.83			$	19.4
Q4 2009	120.4	$	7.57			$	31.2
Q2-Q4 2009(a)	253.3	$	7.67	604	42%	$	69.5	$	0.12

Total 2010(a)	121.2	$	9.69	860	14%	$	224.6	$	0.26

(a)	Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at prices ranging from $6.00 to $6.50 covering 5 bcf in 2009 and $5.45 to $6.75 covering 70 bcf in 2010.

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

	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 2009	97.8	$	7.02	$	8.83
Q3 2009	102.7	$	7.02	$	8.76
Q4 2009	52.1	$	7.34	$	8.88
Q2-Q4 2009(a)	252.6	$	7.08	$	8.81	604	42%

Total 2010(a)	70.6	$	6.78	$	9.18	860	8%

(a)	Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 62 bcf in 2009 and ranging from $4.25 to $6.00 covering 30 bcf in 2010.

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

	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 2009	21.1	$	7.64	$	1.14
Q3 2009	18.9	$	7.53	$	1.19
Q4 2009	18.9	$	7.58	$	1.15
Q2-Q4 2009	58.9	$	7.59	$	1.16	604	10%

Total 2010	298.5	$	10.19	$	0.58	860	35%

The company has the following natural gas basis protection swaps in place:

	Mid-Continent			Appalachia
	Volume (Bcf)	NYMEX less(a)		Volume (Bcf)	NYMEX plus(a)
2009	27.3	$	1.46	13.1	$	0.28
2010	—		—	10.2		0.26
2011	45.1		0.82	12.1		0.25
2012	43.2		0.85	—		—
Totals	115.6	$	0.98	35.4	$	0.26

(a)	weighted average

We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition in November 2005. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($27 million as of March 31, 2009). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our natural gas and oil revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to natural gas and oil revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in natural gas and oil revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.

The following details the CNR derivatives (natural gas swaps) we have assumed:

	Open Swaps (Bcf)	Avg. NYMEX Strike Price Of Open Swaps		Avg. Fair Value Upon Acquisition of Open Swaps		Initial Liability Acquired		Assuming Natural Gas Production (Bcf)	Open Swap Positions as a % of Estimated Total Natural Gas Production
Q2 2009	4.6	$	5.18	$	6.87	$	(1.69)
Q3 2009	4.6	$	5.18	$	6.89	$	(1.71)
Q4 2009	4.6	$	5.18	$	7.32	$	(2.14)
Q2-Q4 2009	13.8	$	5.18	$	7.28	$	(2.10)	604	2%

Note: Not shown above are collars covering 2.75 bcf of production in 2009 at an average floor and ceiling of $4.50 and $6.00.

The company also has the following crude oil swaps in place:

	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 2009	637	$	77.38			$	4.4
Q3 2009	1,058	$	87.05			$	(0.3)
Q4 2009	1,058	$	87.04			$	(0.4)
Q2-Q4 2009(a)	2,753	$	84.81	9,126	30%	$	3.7	$	0.41

Total 2010(a)	4,745	$	90.25	12,000	40%	$	(6.9)	$	(0.58)

(a)	Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $50.00 to $60.00 covering 3 mmbbls in 2009 and $60.00 covering 5 mmbbls in 2010.

Note: Not shown above are written call options covering 3,850 mbbls of oil production in 2009 at a weighted average price of $101.79 per bbl for a weighted average premium of $0.64 per bbl and 5,110 mbbls of oil production in 2010 at a weighted average price of $100.71 per bbl for a weighted average premium of $1.20 per bbl.

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)

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

Exhibit No.		Document Description

99.1*		Chesapeake Energy Corporation press release dated June 30, 2009

99.2*		Chesapeake Energy Corporation press release dated August 3, 2009

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