Chesapeake Energy Corporation Reports Financial and Operational Results for the 2012 Second Quarter

Chesapeake Energy Corporation (NYSE:CHK) today announced financial and
operational results for the 2012 second quarter. For the 2012 second
quarter, Chesapeake reported net income to common stockholders of $929
million ($1.29 per fully diluted common share), ebitda of $2.385 billion
(defined as net income before income taxes, interest expense, and
depreciation, depletion and amortization) and operating cash flow of
$895 million (defined as cash flow from operating activities before
changes in assets and liabilities) on revenue of $3.389 billion and
production of 347 billion cubic feet of natural gas equivalent (bcfe).

The company′s 2012 second quarter results include various items that are
typically not included in published estimates of the company′s financial
results by certain securities analysts. Excluding such items for the
2012 second quarter, Chesapeake reported adjusted net income to common
stockholders of $3 million ($0.06 per fully diluted common share) and
adjusted ebitda of $803 million. The primary excluded items from the
2012 second quarter reported results are a net after-tax gain on
investments of $584 million, primarily related to the sale of all of the
company′s interests in Access Midstream Partners, L.P. (NYSE:ACMP;
formerly named Chesapeake Midstream Partners, L.P.), unrealized noncash
after-tax mark-to-market gains of $490 million resulting from the
company′s oil, natural gas liquids (NGL) and natural gas and interest
rate hedging programs and a noncash after-tax charge of $148 million
related to the impairment of certain of the company′s property and
equipment. 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 20 ? 24 of this release.

Key Operational and Financial Statistics Summarized

The table below summarizes Chesapeake′s key results during the 2012
second quarter and compares them to results during the 2012 first
quarter and the 2011 second quarter.

2012 Second Quarter Average Daily Total Production of 3.808 Bcfe per
Day Increases 25% Year over Year and 4% Sequentially; 2012 Second
Quarter Daily Liquids Production Increases 65% Year over Year and 15%
Sequentially to 130,200 Bbls per Day

Chesapeake′s daily production for the 2012 second quarter averaged 3.808
bcfe, an increase of 25% from the average 3.049 bcfe produced per day in
the 2011 second quarter and an increase of 4% from the average 3.658
bcfe produced per day in the 2012 first quarter. Chesapeake′s average
daily production of 3.808 bcfe for the 2012 second quarter consisted of
approximately 3.027 billion cubic feet (bcf) of natural gas (79% on a
natural gas equivalent basis) and approximately 130,200 barrels (bbls)
of liquids, consisting of approximately 80,500 bbls of oil (13% on a
natural gas equivalent basis) and approximately 49,700 bbls of NGL (8%
on a natural gas equivalent basis) (oil and NGL collectively referred to
as 'liquids?).

For the 2012 second quarter, the company′s year-over-year growth rate of
natural gas production was 18%, or approximately 450 million cubic feet
(mmcf) per day, and its year-over-year growth rate of liquids production
was 65%, or approximately 51,200 bbls per day. Chesapeake′s
year-over-year liquids production growth consisted of oil production
growth of 88%, or approximately 37,700 bbls per day, and NGL production
growth of 37%, or approximately 13,500 bbls per day. Production amounts
above were affected by curtailments of natural gas production, which
averaged an estimated 330 mmcf of natural gas per day net to Chesapeake
in both the 2012 second quarter and 2012 first quarter compared to no
curtailments in the 2011 second quarter. Had the company not curtailed a
portion of its natural gas production, its year-over-year production
growth rate in the 2012 second quarter would have been 36%. The company
ended its natural gas production curtailment program at the end of the
2012 second quarter and does not anticipate needing to implement new
material curtailments during the remainder of 2012.

As a result of reduced drilling activity currently planned by the
company for 2012 and 2013 in its dry natural gas plays, Chesapeake is
projecting an approximate 12% decline in its natural gas productive
capacity in 2013 compared to 2012 after adjusting for estimated
production curtailments of approximately 60 bcf in 2012. Management
expects the company′s absolute natural gas production to decline 7% in
2013 and expects its liquids production to increase 32% in 2013.
Management and the board of directors are currently reviewing operations
for 2013 and beyond, which could result in changes to the company′s
drilling activity and production levels in 2013. This information is
expected to be updated in connection with the 2012 third quarter
earnings release.

Average Realized Prices and Hedging Results and Positions Detailed

Average prices realized during the 2012 second quarter (including
realized gains or losses from oil, NGL and natural gas derivatives and
excluding unrealized gains or losses on such derivatives) were $1.88 per
thousand cubic feet (mcf) of natural gas, $91.58 per barrel (bbl) of oil
and $25.94 per bbl of NGL, for a realized natural gas equivalent price
of $3.77 per thousand cubic feet of natural gas equivalent (mcfe).
Realized gains from natural gas and liquids hedging activities during
the 2012 second quarter generated a $0.66 gain per mcf of natural gas, a
$2.09 gain per bbl of oil and a $0.46 loss per bbl of NGL for a 2012
second quarter realized hedging gain of $195 million, or $0.56 per mcfe.

By comparison, average prices realized during the 2011 second quarter
(including realized gains or losses from oil, NGL and natural gas
derivatives and excluding unrealized gains or losses on such
derivatives) were $5.19 per mcf of natural gas, $87.99 per bbl of oil
and $38.37 per bbl of NGL, for a realized natural gas equivalent price
of $6.07 per mcfe. Realized gains from natural gas and liquids hedging
activities during the 2011 second quarter generated a $1.93 gain per mcf
of natural gas, an $8.70 loss per bbl of oil and a $3.29 loss per bbl of
NGL for a 2011 second quarter realized hedging gain of $407 million, or
$1.46 per mcfe. The company′s realized cash hedging gains since January
1, 2006 have been $8.7 billion, or $1.46 per mcfe.

The following table summarizes Chesapeake′s 2012 and 2013 open swap
positions as of August 6, 2012. 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 increase or decrease some
or all of its hedging positions at any time in the future without notice.

Details of the company′s quarter-end hedging positions will be provided
in the company′s Form 10-Q filing with the Securities and Exchange
Commission (SEC), and current positions are disclosed in summary format
in management′s Outlook dated August 6, 2012, which is attached to this
release as Schedule 'A,? beginning on page 25. The Outlook has been
changed from the Outlook dated May 1, 2012, attached as Schedule 'B,?
which begins on page 28, to reflect various updated information.
Management and the board of directors are currently reviewing operations
for 2013 and beyond, which could result in changes to the Outlook
attached as Schedule A. This information is expected to be updated in
connection with the 2012 third quarter earnings release.

Strong 2012 First Half Proved Reserve Additions of 4.2 Tcfe Exceeded
by Price-Related Downward Revisions of 4.6 Tcfe Largely Attributable to
Removing Barnett and Haynesville PUDs; Total Proved Reserves Decrease 7%
to 17.4 Tcfe, or 2.9 Bboe

During the 2012 first half, Chesapeake developed 4.2 trillion cubic feet
of natural gas equivalent (tcfe), or 690 million barrels of oil
equivalent (mmboe), of new proved reserves through the drillbit at a
drilling and completion cost of $1.14 per mcfe, or $6.84 per boe.

As a result of lower U.S. natural gas prices, the company recorded
price-related downward revisions of 4.6 tcfe, or 760 mmboe, during the
2012 first half, primarily attributable to the removal of proved
undeveloped reserves (PUD) in the company′s Barnett and Haynesville
Shale plays. The company's June 30, 2012 proved reserves were 17.4 tcfe,
or 2.9 billion barrels of oil equivalent (bboe), a 7% decrease from
year-end 2011.

The following table presents Chesapeake′s June 30, 2012 proved reserves,
proved reserve changes, reserve replacement ratio, estimated future net
cash flows from proved reserves (discounted at an annual rate of 10%
before income taxes (PV-10)), proved developed percentage and 2012 first
half proved well costs based on the trailing 12-month average price
required under SEC rules and the 10-year average NYMEX strip prices as
of June 30, 2012. Additional information regarding the data in the table
below is presented in pages 16 and 17.

Using SEC pricing, the PV-10 value of the added proved reserves was
$10.2 billion ($2.43 per mcfe, or $14.57 per boe). The difference
between 2012 first half drilling and completion costs of $1.14 per mcfe
and the $2.43 per mcfe PV-10 value of the proved reserves added provides
evidence of the net asset value creation capability of the company′s
drilling program.

Company Completes $4.7 Billion of Sales in the 2012 First Half and
Anticipates Sales of Approximately $7.0 Billion in the 2012 Third Quarter

In the 2012 first half, Chesapeake completed $4.7 billion of sales,
including: the sale of preferred shares of an unrestricted, nonguarantor
consolidated subsidiary, CHK Cleveland Tonkawa, L.L.C., and an
overriding royalty interest in the Cleveland and Tonkawa plays for
proceeds of $1.25 billion; the sale of a 10-year volumetric production
payment (VPP) for proceeds of $745 million for certain producing assets
in its Anadarko Basin Granite Wash play; the sale of oil and natural gas
assets in the Texoma Woodford play for approximately $575 million; the
sale of all of CHK′s common and general partner interests in ACMP to
Global Infrastructure Partners (GIP) for $2.0 billion; and other
miscellaneous asset sales totaling approximately $100 million.

During the 2012 third quarter, Chesapeake expects to enter into
agreements to sell three Permian Basin asset packages. A Purchase and
Sale Agreement (PSA) has been signed with affiliates of Houston-based
EnerVest, Ltd. for the company′s producing assets in the Midland Basin
portion of the Permian Basin. Bids have also been received and accepted
on two other packages in the Delaware Basin portion of the Permian
Basin. Chesapeake is currently negotiating PSAs for the two Delaware
Basin packages with the goal of entering into PSAs in the next 30 days
and closing the transactions in the 2012 third quarter. Negotiations for
the sale of substantially all of Chesapeake′s remaining midstream assets
are also underway with GIP, which has an exclusive offer right until
August 13, 2012. Chesapeake also expects to close various other asset
sales during the 2012 third quarter.

Chesapeake anticipates net proceeds of approximately $7.0 billion for
asset sales in the 2012 third quarter, including those discussed above,
which if successfully completed, would bring the company′s 2012 asset
sales to approximately $11.7 billion. For the full year, the company has
previously discussed a range of $11.5-14.0 billion in sales and
management has updated its range to $13.0-14.0 billion. Assuming
completion of its planned asset sales in the 2012 second half,
Chesapeake plans to repay its $4.0 billion term loans and also achieve
the 25% two-year debt reduction goal of the company′s 25/25 Plan, which
was first announced on January 6, 2011.

Company Achieves Strong Operational Results in its Liquids-Rich Plays
with Liquids Production Increasing by 65% Year over Year and 15%
Sequentially, Led by 745% Year-over-Year and 71% Sequential Production
Growth in its Eagle Ford Shale Play; Oil Production Has Increased More
Quickly than NGL Production and Comprised 62% of Total Liquids
Production in the 2012 Second Quarter

Since 2000, Chesapeake has built the largest combined inventories of
onshore leasehold (15.9 million net acres) and 3-D seismic (33.2 million
acres) in the U.S. and owns a leading position in 10 of what Chesapeake
believes are the Top 15 unconventional plays in the U.S. ? the Eagle
Ford Shale in South Texas; the Marcellus Shale in Pennsylvania and West
Virginia; the Utica Shale in Ohio; the Granite Wash, Cleveland, Tonkawa
and Mississippi Lime plays in the Anadarko Basin in Oklahoma and the
Texas Panhandle; the Niobrara Shale in the Powder River Basin in
Wyoming; the Haynesville/Bossier shales in western Louisiana and east
Texas; and the Barnett Shale in north Texas. These 10 plays represent
Chesapeake′s core assets and will be the nearly exclusive focus of the
company′s drilling efforts in the future.

In response to strong U.S. oil and NGL prices in comparison to weaker
U.S. natural gas prices, during the past four years Chesapeake has
substantially shifted its drilling and completion activity to
liquids-rich plays. During 2012 and 2013, the company projects that only
approximately 16% and 8%, respectively, of its total drilling and
completion capital expenditures will be invested in dry natural gas
plays. The company continues to achieve strong operational results in
its liquids-rich plays, particularly in the key plays highlighted below.

Eagle Ford Shale (South Texas):Chesapeake′s activities in the Eagle Ford Shale in South Texas
continue to drive strong results, yielding net production of 36,300
barrels of oil equivalent (boe) per day (gross 75,400 boe per day) for
the 2012 second quarter, an increase of 615% year over year and 58%
sequentially, which included an increase in liquids production of 745%
year over year and 71% sequentially. Approximately 66% of total Eagle
Ford production during the 2012 second quarter was oil, 17% was NGL and
17% was natural gas. Production growth in the play has been augmented by
the continued build out of new compression facilities and new pipelines
as well as securing additional short-term truck transportation for oil
production. Chesapeake expects price realizations for its Eagle Ford
production to improve by approximately $5 per bbl beginning in October
2012 as new oil gathering pipelines and other infrastructure are
completed.

As of June 30, 2012, Chesapeake had 337 producing wells in the Eagle
Ford play, which included 121 wells that reached first production in the
2012 second quarter, compared to 62 in the 2012 first quarter and 27 in
the 2011 second quarter. Also, as of June 30, 2012, Chesapeake had
approximately 220 Eagle Ford wells drilled, but not yet producing, that
were in various stages of completion and/or waiting on pipeline
connection. Recent efficiency gains in drilling cycles of well spud to
rig release and well spud to first sales, in addition to certain
reductions in service costs, have resulted in cost savings of
approximately 15% per well in the Eagle Ford. As a consequence of this
greater drilling efficiency, the company is planning to reduce its
drilling activity in the Eagle Ford from 28 rigs currently to 25 rigs by
December 2012 and plans to average 22 rigs during 2013.

Of the 121 wells which commenced first production in the 2012 second
quarter, 110 wells (or 91%) had peak production rates of more than 500
boe per day, including 37 wells (or 31%) with peak rates of more than
1,000 boe per day.

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

• 
  The Gates 010-CHK-B TR1-D6H in Webb County, TX achieved a peak rate of
  approximately 2,070 boe per day, consisting of 710 bbls of oil, 665
  bbls of NGL and 4.2 mmcf of natural gas per day;
  
• 
  The Holubar Dim C 2H in Dimmit County, TX achieved a peak rate of
  approximately 1,900 boe per day, consisting of 1,730 bbls of oil, 110
  bbls of NGL and 0.4 mmcf of natural gas per day; and
  
• 
  The Foley MCM A 1H in McMullen County, TX achieved a peak rate of
  approximately 1,500 boe per day, consisting of 1,335 bbls of oil, 55
  bbls of NGL and 0.6 mmcf of natural gas per day.
  

Hogshooter Wash (western Oklahoma, Texas
Panhandle):On June 1, 2012, Chesapeake
announced a significant new discovery in the Texas Panhandle portion of
the Hogshooter Wash play, where the company owns approximately 30,000
net acres. The company reported its Thurman Horn 406H well averaged
approximately 7,350 boe per day (90% liquids) in its first eight days of
stabilized production. This well is currently flowing at a rate of
approximately 5,100 boe per day (65% liquids). In its first 60 days of
production, the well has produced cumulative volumes of approximately
265,000 bbls of oil, ?65,000 bbls of NGL and 350 mmcf of natural gas. On
July 13, 2012, ?Chesapeake placed the Zybach 6010H on production and this
Hogshooter well is currently producing approximately 2,400 boe per day
(85% liquids). Chesapeake′s oldest operated well ?in the Hogshooter
play, ?the Meek 41 9H, is currently producing approximately 720 boe per
day (85% liquids) after more than 90 days on production.

Chesapeake currently has two wells drilling in the Hogshooter play, the
Meek 41 10H and the Thurman Horn 4010H, and is scheduled to spud another
11 Hogshooter wells before year-end 2012. Chesapeake has identified
approximately 60 potential drilling locations in the Hogshooter play.

Utica Shale (eastern Ohio):
Chesapeake continues to focus on developing the wet gas and dry gas
windows of the Utica Shale play in eastern Ohio, where the company holds
approximately 1.3 million net acres of leasehold, the industry′s largest
position. As of June 30, 2012, Chesapeake had drilled a total of 87
wells in the Utica play and the company′s production techniques and
geologic understanding of the Utica play are continuing to improve. Of
the 28 wells with production information in the focus area, on a
post-processing basis, peak rates have averaged approximately 1,000 boe
per day, consisting of approximately 205 bbls of oil, 150 bbls of NGL
and 3.8 mmcf of natural gas per day. As of June 30, 2012 there were 28
additional wells waiting on pipeline connection, with the others in
various stages of completion.

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

• 
  The Brown 10H in Jefferson County, OH achieved a peak rate of
  approximately 1,445 boe per day, which included 8.7 mmcf of natural
  gas per day;
  
• 
  The Bailey 3H in Carroll County, OH achieved a peak rate of
  approximately 1,420 boe per day, which included 205 bbls of oil, 270
  bbls of NGL and 5.7 mmcf of natural gas per day; and
  
• 
  The Snoddy 6H in Carroll County, OH achieved a peak rate of
  approximately 1,260 boe per day, which included 320 bbls of oil, 250
  bbls of NGL and 4.2 mmcf of natural gas per day.
  

Chesapeake and its midstream partners are making substantial progress in
the construction of gathering and processing systems that will be
essential for accelerating production from this rapidly expanding and
important play. Chesapeake is currently operating 11 rigs in the Utica
play and plans to exit 2012 with 16 operated rigs. As of June 30, 2012,
the company′s remaining drilling carry from Total was approximately
$1.35 billion. Chesapeake anticipates using 100% of the drilling carry
by year-end 2014 and the carry will pay for 60% of Chesapeake′s drilling
costs during that time.

Marcellus Shale (Pennsylvania, West Virginia):With approximately 1.8 million net acres, Chesapeake is the
industry′s largest leasehold owner in the Marcellus Shale play that
spans from northern West Virginia across much of Pennsylvania into
southern New York.

During the 2012 second quarter, Chesapeake′s average daily net
production in the northern dry gas portion of the Marcellus play was 495
mmcfe, an increase of 160% year over year and 19% sequentially.
Chesapeake is currently drilling with seven operated rigs in the dry gas
northern portion of the Marcellus and anticipates reducing its drilling
activity to an average of approximately six rigs for the remainder of
2012.

Three notable recent wells completed by Chesapeake in the dry gas
northern portion of the Marcellus are as follows:

• 
  The Stoorza 5H in Bradford County, PA achieved a peak rate of 9.4 mmcf
  of natural gas per day;
  
• 
  The McGavin 5H in Susquehanna County, PA achieved a peak rate of 8.7
  mmcf of natural gas per day; and
  
• 
  The Redmond 2H in Wyoming County, PA achieved a peak rate of 8.7 mmcf
  of natural gas per day.
  

During the 2012 second quarter, Chesapeake′s average daily net
production in the wet gas southern portion of the play was approximately
135 mmcfe. Chesapeake is currently drilling with seven operated rigs in
the wet gas southern portion of the Marcellus and anticipates reducing
its drilling activity to an average of approximately six rigs for the
remainder of 2012.

Three notable recent wells completed by Chesapeake in the wet gas
southern portion of the Marcellus are as follows:

• 
  The O E Burge MSH 10H in Marshall County, WV achieved an initial test
  rate of approximately 1,650 boe per day, consisting of 7.2 mmcf of
  natural gas per day and 445 bbls of liquids;
  
• 
  The O E Burge 6H in Marshall County, WV achieved an initial test rate
  of approximately 1,480 boe per day, consisting of 6.8 mmcf of natural
  gas per day and 345 bbls of liquids; and
  
• 
  The O E Burge 8H in Marshall County, WV achieved an initial test rate
  of approximately 1,160 boe per day, consisting of 5.5 mmcf of natural
  gas per day and 240 bbls of liquids.
  

Mississippi Lime (northern Oklahoma, southern
Kansas): Chesapeake′s approximate 2.0 million net
acres of leasehold is the industry′s largest position in the Mississippi
Lime play in northern Oklahoma and southern Kansas. Production for the
2012 second quarter averaged 20,000 boe per day, up 198% year over year
and 56% sequentially. Approximately 39% of total Mississippi Lime
production during the 2012 second quarter was oil, 12% was NGL and 49%
was natural gas. Since 2009, the company has drilled 158 horizontal
producing wells in the Mississippi Lime play with attractive overall
results and is currently operating 18 rigs in the play. The company
continues to pursue a joint venture and/or sale of a portion of its
Mississippi Lime leasehold and expects to announce a transaction in the
next few months.

Three notable recent wells completed by Chesapeake in the Mississippi
Lime during the quarter are as follows:

• 
  The Smith 27-28-9 1H in Alfalfa County, OK achieved a peak rate of
  approximately 2,190 boe per day, which included 1,655 bbls of oil, 70
  bbls of NGL and 2.8 mmcf of natural gas per day;
  
• 
  The Loy Puffinbarger 29-28-9 1H in Alfalfa County, OK achieved a peak
  rate of approximately 1,630 boe per day, which included 1,100 bbls of
  oil, 80 bbls of NGL and 2.7 mmcf of natural gas per day; and
  
• 
  MWK 16-27-12 1H in Alfalfa County, OK achieved a peak rate of
  approximately 1,290 boe per day, which included 800 bbls of oil, 90
  bbls of NGL and 2.4 mmcf of natural gas per day.
  

Cleveland and Tonkawa Tight Sand (western
Oklahoma, Texas Panhandle):Chesapeake owns
approximately 525,000 net acres of leasehold in the Cleveland play and
285,000 net acres in the Tonkawa play in western Oklahoma and the Texas
Panhandle, which it believes is the industry′s largest position in the
combined plays. Production for the 2012 second quarter averaged 21,400
boe per day, up 109% year over year and 14% sequentially. Approximately
45% of total Cleveland and Tonkawa production during the quarter was
oil, 20% was NGL and 35% was natural gas. The company is currently
operating 13 rigs in the two plays and plans to exit 2012 with 13
operated rigs.

Three notable wells completed by Chesapeake in the Cleveland Sand during
the quarter are as follows:

• 
  The Big Lake 1022H in Hemphill County, TX achieved a peak rate of
  approximately 3,960 boe per day, which included 730 bbls of oil, 1,190
  bbls of NGL and 12.2 mmcf of natural gas per day;
  
• 
  The Betty 1H in Ellis County, OK achieved a peak rate of approximately
  1,435 boe per day, which included 1,000 bbls of oil, 215 bbls of NGL
  and 1.3 mmcf of natural gas per day; and
  
• 
  The Andrew 1H in Ellis County, OK achieved a peak rate of
  approximately 1,160 boe per day, which included 905 bbls of oil, 130
  bbls of NGL and 0.8 mmcf of natural gas per day.
  

Three notable wells completed by Chesapeake in the Tonkawa Sand during
the quarter are as follows:

• 
  The Ireton 1H in Dewey County, OK achieved a peak rate of
  approximately 775 boe per day, which included 525 bbls of oil, 45 bbls
  of NGL and 1.2 mmcf of natural gas per day;
  
• 
  The Little 1H in Roger Mills County, OK achieved a peak rate of
  approximately 660 boe per day, which included 605 bbls of oil, 20 bbls
  of NGL and 0.2 mmcf of natural gas per day; and
  
• 
  The Vessels 1H in Roger Mills County, OK achieved a peak rate of
  approximately 680 boe per day, which included 555 bbls of oil, 50 bbls
  of NGL and 0.5 mmcf of natural gas per day.
  

Powder River Basin Niobrara (Wyoming):
Chesapeake owns approximately 350,000 net acres in the Powder River
Basin Niobrara play in Wyoming. The company has drilled 44 horizontal
wells in the play to date and results continue to improve steadily with
an increasing focus on a newly-identified core area that has much higher
pressures and hydrocarbons in place than in other portions of the play.
Chesapeake has drilled 18 wells in the identified core area of the play
and believes it has the ability to drill more than 1,000 wells in this
focus area in the years to come. Chesapeake is currently operating eight
rigs in the play and plans to exit 2012 with 11 operated rigs.

Three notable recent wells completed by Chesapeake in the Powder River
Basin Niobrara are as follows:

• 
  The Combs Ranch 1-H in Converse County, WY achieved a peak rate of
  approximately 2,460 boe per day, which included 1,120 bbls of oil, 575
  bbls of NGL and 4.6 mmcf of natural gas per day;
  
• 
  The York Ranch 1H in Converse County, WY achieved a peak rate of
  approximately 1,950 boe per day, which included 1,020 bbls of oil, 370
  bbls of NGL and 3.4 mmcf of natural gas per day; and
  
• 
  The Northwest Fetter 1H in Converse County, WY achieved a peak rate of
  approximately 1,460 boe per day, which included 1,150 bbls of oil, 125
  bbls of NGL and 1.1 mmcf of natural gas per day.
  

As of June 30, 2012, the company′s remaining drilling carry from CNOOC
was approximately $520 million. Chesapeake anticipates using 100% of the
carry by year-end 2014 and the carry will pay for 67% of Chesapeake′s
drilling costs during that time.

Management Comments

Aubrey K. McClendon, Chesapeake′s Chief Executive Officer, said, 'We are
taking aggressive and focused actions to increase cash flow and net
asset value per share while also reducing long-term debt as we continue
our ongoing transformation to a more balanced asset base between
higher-margin liquids and lower-margin natural gas. We are prudently
deploying our capital as we focus on developing and harvesting the 10
core plays in which Chesapeake has built a #1 or #2 position.

'As importantly, we continue to execute on our asset sale process. In
the 2012 third quarter, we anticipate entering into approximately $7.0
billion of asset sales, including the sale of Permian Basin and
midstream assets. These transactions will be in addition to the $4.7
billion of asset sales completed in the 2012 first half. In combination
with further asset sales planned for the 2012 fourth quarter, we have
increased our plans for asset sales this year to a range of $13.0 to
$14.0 billion, which will enable us to accomplish our planned 25%
long-term debt reduction to $9.5 billion by year-end 2012 in accordance
with our 25/25 Plan we announced in January 2011.

'Finally, as a result of Chesapeake′s strong operational performance,
ongoing drilling efficiency gains and an increased focus on optimal
asset development, we have increased our production guidance for 2013
despite a $750 million decrease in our drilling and completion capital
expenditure plans for next year.?

2012 Second Quarter Financial and Operational Results Conference Call
Information

A conference call to discuss this release has been scheduled for
Tuesday, August 7, 2012 at 9:00 am EDT. The telephone number to access
the conference call is 913-312-1296 or toll-free 800-239-9838.
The passcode for the call is 4584085. We encourage those who
would like to participate in the call to place calls between 8:50 and
9:00 am EDT. For those unable to participate in the conference call, a
replay will be available for audio playback at 1:00 pm EDT on Tuesday,
August 7, 2012 and will run through midnight Monday, August 20, 2012.
The number to access the conference call replay is 719-457-0820
or toll-free 888-203-1112. The passcode for the replay is 4584085.
The conference call will also be webcast live on Chesapeake′s website at www.chk.com
in the 'Events? subsection of the 'Investors? section of the company′s
website. The webcast of the conference will be available on the
company′s website for one year.

This news 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 are statements other than
statements of historical fact and give our current expectations or
forecasts of future events.They include estimates of natural gas
and oil reserves, projected production, planned development drilling,
projected drilling and completion expenditures and leasehold investment,
anticipated asset sales and related proceeds, projected cash flow and
liquidity, business strategy and other plans and objectives for future
operations.Disclosures concerning the fair value of derivative
contracts and their estimated contribution to our future results of
operations are based upon market information as of a specific date.These
market prices are subject to significant volatility.We caution
you not to place undue reliance on our forward-looking statements, which
speak only as of the date of this news 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
2011 annual report on Form 10-K filed with the U.S. Securities and
Exchange Commission on February ?29, 2012.These risk factors
include the volatility of natural gas and oil prices; the limitations
our level of indebtedness may have on our financial flexibility;
declines in the values of our natural gas and oil properties resulting
in ceiling test write-downs; the availability of capital on an economic
basis, including through planned asset sales, 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; inability to generate
profits or achieve targeted results in drilling and well operations;
leasehold terms expiring before production can be established; hedging
activities resulting in lower prices realized on natural gas and oil
sales; the need to secure hedging liabilities and the inability of
hedging counterparties to satisfy their obligations; drilling and
operating risks, including potential environmental liabilities;
legislative and regulatory changes adversely affecting our industry and
our business, including initiatives related to hydraulic fracturing;
general economic conditions negatively impacting us and our business
counterparties; oilfield services shortages and transportation capacity
constraints and interruptions that could adversely affect our cash flow;
and losses possible from pending or future litigation.We do not
have binding agreements for all of the asset sales we expect to complete
in 2012, including multiple Permian Basin sales transactions, the sale
of our remaining midstream assets and other miscellaneous asset sales.
Our ability to consummate each of these transactions is subject to
changes in market conditions and other factors. To the extent one or
more of the transactions is not completed in the anticipated time frame
or at all or for less proceeds than anticipated, we may not be able to
reduce our indebtedness as planned.

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.

Chesapeake Energy Corporation (NYSE:CHK) is the second-largest
producer of natural gas, a Top 15 producer of oil and natural gas
liquids and the most active driller of new wells in the U.S.
Headquartered in Oklahoma City, the company's operations are focused on
discovering and developing unconventional natural gas and oil fields
onshore in the U.S. Chesapeake owns leading positions in the Eagle Ford,
Utica, Granite Wash, Cleveland, Tonkawa, Mississippi Lime and Niobrara
unconventional liquids plays and in the Marcellus, Haynesville/Bossier
and Barnett unconventional natural gas shale plays. The company has also
vertically integrated its operations and owns substantial marketing,
midstream and oilfield services businesses directly and indirectly
through its subsidiaries Chesapeake Energy Marketing, Inc., Chesapeake
Midstream Development, L.P. and COS Holdings, L.L.C.Further
information is available at www.chk.com
where Chesapeake routinely posts announcements, updates, events,
investor information, presentations and news releases.