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--(Business Wire)--
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 Est. Risk Risked Est. Avg. Reserves Total Risked Unproved Reserves (bcfe) Total Proved Unrisked Unproved Reserves Est. IRR Current Daily Production (mmcfe) Current Operated Rig Count
Net Acreage Drilling Density (Acres) Factor Net Undrilled Wells Per Well (bcfe) Proved Reserves (bcfe) and Risked Unproved Reserves (bcfe) (bcfe) at $7 Gas/ $70 Oil
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 PlaySubtotals 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 40,000 80 25% 200 4.75 464 400 864 700 135% 70 1
Granite Wash
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.

See Graph 1: Haynesville Type Curve and Normalized Production History

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.

See Graph 2: Barnett Shale Type Curve and Normalized Production History

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.

See Graph 3: Fayetteville Type Curve and Normalized Production History

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.

See Graph 4: Colony Wash Type Curve and Normalized Production History

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.

See Graph 5: Texas Panhandle Granite Wash Type Curve and Normalized Production
History

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.

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Chesapeake Energy Corporation
Investor Contact:
Jeffrey L. Mobley, CFA, 405-767-4763
Senior Vice President -
Investor Relations and Research
jeff.mobley@chk.com
or
Media Contact:
Jim Gipson, 405-935-1310
Director - Media Relations
jim.gipson@chk.com

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