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

Chesapeake Energy Corporation (NYSE:CHK) today announced financial and
operational results for the 2012 third quarter. For the 2012 third
quarter, Chesapeake reported a net loss to common stockholders of $2.055
billion ($3.19 per fully diluted common share), ebitda of negative
$2.367 billion (defined as net income (loss) before income taxes,
interest expense and depreciation, depletion and amortization) and
operating cash flow of $1.118 billion (defined as cash flow from
operating activities before changes in assets and liabilities) on
revenue of $2.970 billion and production of 381 billion cubic feet of
natural gas equivalent (bcfe).

The company′s 2012 third 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 third quarter, Chesapeake reported adjusted net income to common
stockholders of $33 million ($0.10 per fully diluted common share) and
adjusted ebitda of $1.021 billion. The primary excluded items from the
2012 third quarter reported results are the following:

• 
  a noncash after-tax impairment charge of $2.022 billion related to the
  carrying value of natural gas and oil properties (primarily resulting
  from a 10% decrease in trailing 12-month average
  first-day-of-the-month natural gas prices as of September 30, 2012,
  compared to June 30, 2012, and the impairment of certain undeveloped
  leasehold, primarily in the Williston and DJ Basins);
  
• 
  an unrealized noncash after-tax mark-to-market loss of $63 million
  resulting from the company′s natural gas, oil and natural gas liquids
  (NGL) and interest rate hedging programs;
  
• 
  an after-tax charge of $28 million related to losses on sales and
  impairments of certain fixed assets and other; and
  
• 
  a net after-tax gain of $19 million related to the sale of an
  investment.
  

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 19 ? 22 of this release.

Key Operational and Financial Statistics Summarized

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

See footnotes on the following page

(a) Includes the effect of VPP #10 sale in March 2012 (which had an
average production loss impact of approximately 100 mmcfe and 115 mmcfe
per day in the 2012 third and second quarters, respectively). Also
includes the effect of net natural gas production curtailments of
approximately 30 bcf in the 2012 second quarter, or an average of
approximately 330 mmcf per day.

(b) Includes the effects of realized gains (losses) from hedging, but
excludes the effects of unrealized gains (losses) from hedging.

(c) 'Liquids? includes both oil and NGL.

(d) Includes revenue and operating costs and excludes depreciation and
amortization of other assets.

(e) Excludes expenses associated with noncash stock-based compensation.

(f) Increase from 2012 second quarter due to an increase in the
amortizable base resulting from leasehold impairments and expirations in
addition to a further decrease in estimated proved reserves resulting
from lower natural gas prices.

(g) Decrease from 2012 second quarter due to approximately $2.4 billion
of fixed assets held for sale throughout the 2012 third quarter. Assets
classified as held for sale are not subject to depreciation.

(h) Defined as cash flow provided by operating activities before changes
in assets and liabilities.

(i) 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 21.

(j) Defined as net income (loss) available to common stockholders, as
adjusted to remove the effects of certain items detailed on page 22.

2012 Third Quarter Average Daily Production Increases 24% Year over
Year and 9% Sequentially to 4.142 Bcfe; Average Daily Liquids Production
Increases 51% Year over Year and 10% Sequentially to 143,000 Bbls, or
21% of Total Production; Average Daily Oil Production Increases 96% Year
over Year and 21% Sequentially to 97,800 Bbls

Chesapeake′s daily production for the 2012 third quarter averaged 4.142
bcfe, an increase of 24% from the average 3.329 bcfe produced per day in
the 2011 third quarter and an increase of 9% from the average 3.808 bcfe
produced per day in the 2012 second quarter. Chesapeake′s average daily
production of 4.142 bcfe for the 2012 third quarter consisted of
approximately 3.286 billion cubic feet (bcf) of natural gas (79% on a
natural gas equivalent basis) and approximately 142,675 barrels (bbls)
of liquids, consisting of approximately 97,785 bbls of oil (14% on a
natural gas equivalent basis) and approximately 44,890 bbls of NGL (7%
on a natural gas equivalent basis) (oil and NGL collectively referred to
as 'liquids?).

For the 2012 third quarter, the company′s year-over-year growth rate of
natural gas production was 19%, or approximately 523 million cubic feet
(mmcf) per day, and its year-over-year growth rate of liquids production
was 51%, or approximately 48,450 bbls per day. Chesapeake′s
year-over-year liquids production growth consisted of oil production
growth of 96%, or approximately 47,900 bbls per day, and NGL production
growth of 1%, or approximately 550 bbls per day. NGL production for the
2012 third quarter was reduced by approximately 467,000 bbls, or 5,075
bbls per day, due to the company′s election in certain basins to reject
rather than process ethane, which was additive to natural gas production.

As a result of redirecting its drilling program from dry gas plays to
liquids-rich plays, Chesapeake is projecting its natural gas production
to decline approximately 7% in 2013 and is projecting its liquids
production to increase approximately 29% in 2013. Management and the
board of directors continue to review operational plans for 2013 and
beyond, which could result in changes to the company′s drilling activity
and projected production levels in 2013.

Average Realized Prices and Hedging Results and Positions Detailed

Average prices realized during the 2012 third quarter (including
realized gains or losses from natural gas, oil and NGL derivatives and
excluding unrealized gains or losses on such derivatives) were $1.97 per
thousand cubic feet (mcf) of natural gas, $90.79 per bbl of oil and
$31.22 per bbl of NGL, for a realized natural gas equivalent price of
$4.04 per thousand cubic feet of natural gas equivalent (mcfe). Realized
gains from natural gas, oil and NGL hedging activities during the 2012
third quarter generated a $0.17 gain per mcf of natural gas, a $2.72
gain per bbl of oil and a negligible loss per bbl of NGL for a 2012
third quarter realized hedging gain of $77 million, or $0.20 per mcfe.

By comparison, average prices realized during the 2011 third quarter
(including realized gains or losses from natural gas, oil and NGL
derivatives and excluding unrealized gains or losses on such
derivatives) were $4.82 per mcf of natural gas, $82.47 per bbl of oil
and $41.16 per bbl of NGL, for a realized natural gas equivalent price
of $5.78 per mcfe. Realized gains from natural gas, oil and NGL hedging
activities during the 2011 third quarter generated a $1.43 gain per mcf
of natural gas, a $1.71 loss per bbl of oil and a $2.88 loss per bbl of
NGL for a 2011 third quarter realized hedging gain of $344 million, or
$1.12 per mcfe. The company′s realized cash hedging gains since January
1, 2006, have been $8.8 billion, or $1.39 per mcfe.

The following table summarizes Chesapeake′s 2012 and 2013 open natural
gas and oil swap positions as of November 1, 2012. Depending on changes
in natural gas and oil futures markets and management′s view of
underlying 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 November 1, 2012, which is attached to
this release as Schedule 'A,? beginning on page 24. The Outlook has been
updated from the Outlook dated August 6, 2012, attached as Schedule 'B,?
which begins on page 27, to reflect various updated information.
Management and the board of directors are currently reviewing
operational plans for 2013 and beyond, which could result in changes to
the Outlook attached as Schedule 'A.?

During 2012 First Three Quarters, Company Adds New Net Proved
Reserves of 3.9 Tcfe through the Drillbit; Total Proved Reserves
Decrease 14% to 16.2 Tcfe, or 2.7 Bboe, Due to Downward Price-Related
Revisions and Net Divestitures

The company's September 30, 2012, proved reserves were 16.2 trillion
cubic feet of natural gas equivalent (tcfe), or 2.7 billion barrels of
oil equivalent (bboe), a 14% decrease from year-end 2011. Chesapeake
added 3.9 tcfe, or 650 million barrels of oil equivalent (mmboe), of new
proved reserves (net of 596 bcfe of non-price related revisions) through
the drillbit at a drilling and completion cost of $1.92 per mcfe, or
$11.52 per barrel of oil equivalent (boe) during the first three
quarters of 2012. Primarily as a result of lower U.S. natural gas
prices, the company also recorded downward revisions of 4.9 tcfe, or 810
mmboe, during the first three quarters of 2012, largely associated with
the removal of proved undeveloped reserves (PUDs) in the company′s
Barnett and Haynesville Shale plays. Additionally, during this period,
Chesapeake recorded net divestitures of 507 bcfe, or 85 mmboe.

The following table presents Chesapeake′s September 30, 2012 proved
reserves, estimated future net cash flows from proved reserves
(discounted at an annual rate of 10% before income taxes (PV-10)) and
proved developed percentage, each calculated based on the trailing
12-month average price required under SEC rules and the 10-year average
NYMEX strip prices as of September 30, 2012. Additional information
regarding the SEC case can be found on page 16.

a) Reserve volumes estimated using SEC reserve recognition standards and
pricing assumptions based on the trailing 12-month average
first-day-of-the-month prices as of September 30, 2012. This pricing
yields estimated proved reserves for SEC reporting purposes.

b) Natural gas and oil volumes estimated under the 10-year average NYMEX
strip reflect an alternative pricing scenario that illustrates the
sensitivity of proved reserves to a different pricing assumption.
Futures prices represent an unbiased consensus estimate by market
participants about the likely prices to be received for future
production. Management believes that 10-year average NYMEX strip prices
provide a better indicator of the likely economic producibility of the
company′s proved reserves than the historical 12-month average price.

Company Achieves Strong Operational Results in its Liquids-Rich Plays
with Daily Liquids Production Increasing 51% Year over Year and 10%
Sequentially, Led by 410% Year-over-Year and 43% Sequential Liquids
Production Growth in its Eagle Ford Shale Play; Oil Production Comprised
69% of Total Liquids Production in the 2012 Third Quarter and Increased
96% Year over Year and 21% Sequentially

Since 2000, Chesapeake has built a leading position in 10 of what it
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, West Virginia and Pennsylvania; the
Granite Wash, Cleveland, Tonkawa and Mississippi Lime plays in the
Anadarko Basin in Oklahoma and the Texas Panhandle; the
Haynesville/Bossier shales in western Louisiana and East Texas; the
Barnett Shale in North Texas; and the Niobrara Shale in the Powder River
Basin in Wyoming. These 10 plays represent Chesapeake′s core assets and
will be the nearly exclusive focus of the company′s future drilling
efforts.

During the past four years, Chesapeake has substantially shifted its
drilling and completion activity to liquids-rich plays in response to
strong U.S. oil and NGL prices and relatively weak U.S. natural gas
prices. During 2012 and 2013, the company projects that approximately
85% and 88%, respectively, of its total drilling and completion capital
expenditures will be invested in liquids-rich plays.

The company continues to achieve strong operational results in its
liquids-rich plays, as highlighted below:

Eagle Ford Shale (South Texas):Chesapeake′s activities on its approximately 490,000 net acres of
leasehold in the Eagle Ford Shale in South Texas continue to drive
strong results, yielding net production of 52,200 boe per day (120,500
gross operated boe per day) for the 2012 third quarter. This represents
an increase of 371% year over year and 44% sequentially, which included
an increase in oil production of 462% year over year and 48%
sequentially. Approximately 68% of total Eagle Ford production during
the 2012 third quarter was oil, 14% was NGL and 18% was natural gas.

As of September 30, 2012, Chesapeake had 441 gross company operated
producing wells in the Eagle Ford play, which included 124 wells that
reached first production in the 2012 third quarter, compared to 121 in
the 2012 second quarter and 40 in the 2011 third quarter. Also, as of
September 30, 2012, Chesapeake had approximately 233 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 cycle times will allow the company to achieve its
targeted well count goal utilizing fewer rigs than would have been
required in 2010-12. The company is currently operating 23 rigs in the
play, down from a peak of 34 rigs in April 2012 and plans to exit the
year at 22 rigs. The company is currently on pace to have essentially
all of its core and Tier 1 Eagle Ford acreage held by production by the
2013 fourth quarter.

Of the 124 wells which commenced first production in the 2012 third
quarter, 115 wells (or 93%) had peak production rates of more than 500
boe per day, including 43 wells (or 35%) with peak rates of more than
1,000 boe per day, continuing a trend of steady operational improvement
during the past year. Three notable recent wells completed by Chesapeake
in the Eagle Ford during the quarter are as follows:

• 
  The Faith-Yana A Unit C1H in Dimmit County, TX achieved a peak
  rate of approximately 2,175 boe per day, consisting of 1,580 bbls of
  oil, 295 bbls of NGL and 1.8 mmcf of natural gas per day;
  
• 
  The Gates 010-CHK-B 1286-D3H in Webb County, TX achieved a peak
  rate of approximately 2,100 boe per day, consisting of 660 bbls of
  oil, 655 bbls of NGL and 4.7 mmcf of natural gas per day; and
  
• 
  The Shining Star Ranch B 1H in La Salle County, TX achieved a
  peak rate of approximately 1,580 boe per day, consisting of 1,450 bbls
  of oil, 80 bbls of NGL and 0.3 mmcf of natural gas per day.
  

As part of its 'core of the core? strategy, Chesapeake is currently
pursuing the sale of a portion of its existing leasehold and producing
assets outside its current core development area in the Eagle Ford play.

Utica Shale (eastern Ohio):
Chesapeake continues to focus on developing the core wet gas window of
the Utica Shale in eastern Ohio, a play in which the company holds
approximately 1.3 million net acres of leasehold, the industry′s largest
position. As of September 30, 2012, Chesapeake has drilled a total of
134 wells in the Utica play, which include 32 producing wells and 37
additional wells waiting on pipeline connection, with the other 65 wells
in various stages of completion. Chesapeake is currently operating 13
rigs in the Utica play. Production from the Utica play is growing only
moderately at this time because of the time and capital needed to build
out gas processing and pipeline takeaway infrastructure. The company
expects a much larger contribution to production growth from the Utica
in 2013 and beyond as midstream constraints are reduced.

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

• 
  The Houyouse 15-13-5 8H in Carroll County, OH achieved a peak
  rate of approximately 1,735 boe per day, consisting of 465 bbls of
  oil, 335 bbls of NGL and 5.6 mmcf of natural gas per day;
  
• 
  The White 17-13-5 8H in Carroll County, OH achieved a peak rate
  of approximately 1,360 boe per day, consisting of 390 bbls of oil, 285
  bbls of NGL and 4.1 mmcf of natural gas per day; and
  
• 
  The Stuart Henderson 11-12-6 1H in Harrison County, OH achieved
  a peak rate of approximately 825 boe per day, consisting of 410 bbls
  of oil, 100 bbls of NGL and 1.9 mmcf of natural gas per day.
  

In December 2011, Chesapeake entered into a joint venture with Total to
develop a portion of the Utica play. As of September 30, 2012, the
company′s remaining drilling carry from Total was approximately $1.25
billion. Chesapeake anticipates using 100% of the remaining 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, which
spans from northern West Virginia across much of Pennsylvania into
southern New York.

During the 2012 third quarter, Chesapeake′s average daily net production
in the northern dry gas portion of the Marcellus play was 540 mmcfe per
day (1,229 gross operated mmcfe per day), an increase of 159% year over
year and 9% sequentially. Chesapeake has reduced its operated rig count
to five rigs in the northern dry gas portion of the Marcellus and
anticipates maintaining that level of activity for the remainder of 2012.

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

• 
  The Linski S Bra 4H in Bradford County, PA achieved a peak rate
  of 8.4 mmcf of natural gas per day;
  
• 
  The Folta N Bra 2H in Bradford County, PA achieved a peak rate
  of 8.4 mmcf of natural gas per day; and
  
• 
  The Champluvier 2H in Bradford County, PA achieved a peak rate
  of 8.3 mmcf of natural gas per day.
  

During the 2012 third quarter, Chesapeake′s average daily net production
in the southern wet gas portion of the play was approximately 125 mmcfe
per day (206 gross operated mmcfe per day). Chesapeake is currently
drilling with three operated rigs in the southern wet gas portion of the
Marcellus and anticipates maintaining that level of activity for the
remainder of 2012.

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

• 
  The Roy Ferrell 8H in Ohio County, WV achieved an initial test
  rate of approximately 1,525 boe per day, consisting of 5.3 mmcf of
  natural gas, 220 bbls of oil and 430 bbls of NGL per day;
  
• 
  The Deborah Craig 3H in Ohio County, WV achieved an initial
  test rate of approximately 830 boe per day, consisting of 2.6 mmcf of
  natural gas, 200 bbls of oil and 205 bbls of NGL per day; and
  
• 
  The George Gantzer 8H in Ohio County, WV achieved an initial
  test rate of approximately 800 boe per day, consisting of 2.7 mmcf of
  natural gas, 130 bbls of oil and 220 bbls of NGL per day.
  

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 third quarter averaged approximately 25,000 boe per day (30,100
gross operated boe per day), up 211% year over year and 25%
sequentially. Approximately 41% of total Mississippi Lime production
during the 2012 third quarter was oil, 10% was NGL and 49% was natural
gas. As of September 30, 2012, Chesapeake had 227 producing wells in the
Mississippi Lime play, which included 73 wells that reached first
production in the 2012 third quarter, compared to 49 in the 2012 second
quarter and 11 in the 2011 third quarter. Also, as of September 30,
2012, Chesapeake had approximately 55 wells drilled, but not yet
producing, that were in various stages of completion and/or waiting on
pipeline connection. Chesapeake is currently operating nine rigs in the
Mississippi Lime play.

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

• 
  The Herold 3-28-15 1H in Woods County, OK achieved a peak rate
  of approximately 2,025 boe per day, which included 1,740 bbls of oil,
  100 bbls of NGL and 1.1 mmcf of natural gas per day;
  
• 
  The Rauh 3-26-12 1H in Alfalfa County, OK achieved a peak rate
  of approximately 2,020 boe per day, which included 1,210 bbls of oil,
  225 bbls of NGL and 3.5 mmcf of natural gas per day; and
  
• 
  The Hada Land & Cattle 3-28-15 1H in Woods County, OK
  achieved a peak rate of approximately 1,405 boe per day, which
  included 1,150 bbls of oil, 90 bbls of NGL and 1.0 mmcf of natural gas
  per day.
  

Chesapeake continues to pursue a joint venture and/or sale of a portion
of its Mississippi Lime leasehold and expects to announce a transaction
by year-end 2012.

Cleveland and Tonkawa Tight Sand (western
Oklahoma, Texas Panhandle):Chesapeake owns
approximately 520,000 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 from both plays for the 2012 third quarter
averaged 24,100 boe per day (31,700 gross operated boe per day), up 75%
year over year and 13% sequentially. Approximately 45% of total
Cleveland and Tonkawa production during the quarter was oil, 17% was NGL
and 38% was natural gas. The company is currently operating 12 rigs in
the two plays.

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

• 
  The Sloan HMH 1H in Hemphill County, TX achieved a peak rate of
  approximately 1,345 boe per day, which included 360 bbls of oil, 400
  bbls of NGL and 3.5 mmcf of natural gas per day;
  
• 
  The Larry Imke 9-19-25 1H in Ellis County, OK achieved a peak
  rate of approximately 1,035 boe per day, which included 640 bbls of
  oil, 145 bbls of NGL and 1.5 mmcf of natural gas per day; and
  
• 
  The Mathers 131 HMH 1H in Hemphill County, TX achieved a peak
  rate of approximately 920 boe per day, which included 745 bbls of oil,
  75 bbls of NGL and 0.6 mmcf of natural gas per day.
  

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

• 
  The Fariss 2-16-20 1H in Dewey County, OK achieved a peak rate
  of approximately 775 boe per day, which included 680 bbls of oil, 30
  bbls of NGL and 0.4 mmcf of natural gas per day;
  
• 
  The Mike 11-15-22 1H in Roger Mills County, OK achieved a peak
  rate of approximately 735 boe per day, which included 665 bbls of oil,
  20 bbls of NGL and 0.3 mmcf of natural gas per day; and
  
• 
  The Shrewder 8-16-22 1H in Ellis County, OK achieved a peak
  rate of approximately 595 boe per day, which included 480 bbls of oil,
  30 bbls of NGL and 0.5 mmcf of natural gas per day.
  

Granite Wash and Hogshooter Tight Sand (western
Oklahoma, Texas Panhandle):Chesapeake owns
approximately 190,000 net acres of leasehold in the Granite Wash play
and 30,000 net acres in the Hogshooter 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 third quarter averaged
47,750 boe per day (95,800 gross operated boe per day), up 2%
sequentially. Approximately 28% of total Granite Wash and Hogshooter
production during the quarter was oil, 22% was NGL and 50% was natural
gas. The company is currently operating 10 rigs in the two plays.

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

• 
  The Davis 65 21H in Wheeler County, TX achieved a peak rate of
  approximately 3,765 boe per day, which included 765 bbls of oil, 1,230
  bbls of NGL and 10.6 mmcf of natural gas per day;
  
• 
  The Clarence B 21-11-26 1H in Beckham County, OK achieved a
  peak rate of approximately 2,305 boe per day, which included 750 bbls
  of oil, 490 bbls of NGL and 6.4 mmcf of natural gas per day; and
  
• 
  The Ervin 17-11-17 2H in Washita County, OK achieved a peak
  rate of approximately 1,790 boe per day, which included 460 bbls of
  oil, 495 bbls of NGL and 5.0 mmcf of natural gas per day.
  

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

• 
  The Hannah-Roy Trust 17-11-20 1H in Washita County, OK achieved
  a peak rate of approximately 2,285 boe per day, which included 1,665
  bbls of oil, 215 bbls of NGL and 2.4 mmcf of natural gas per day;
  
• 
  The D E Atherton 5057H in Wheeler County, TX achieved a peak
  rate of approximately 2,280 boe per day, which included 1,710 bbls of
  oil, 220 bbls of NGL and 2.1 mmcf of natural gas per day; and
  
• 
  The Wheeler 10-11-231H in Roger Mills County, OK achieved a
  peak rate of approximately 1,120 boe per day, which included 1,005
  bbls of oil, 45 bbls of NGL and 0.4 mmcf of natural gas per day.
  

Powder River Basin Niobrara (Wyoming):
Chesapeake owns approximately 340,000 net acres in the Powder River
Basin Niobrara play in Wyoming. The company has drilled 55 horizontal
wells in the play to date, and results continue to improve steadily with
an increasing focus on a recently identified liquids-rich core area that
has much higher pressures and hydrocarbons in place than in other
portions of the play. Chesapeake believes it has the ability to drill
more than 1,000 wells in this core area in the years to come. Chesapeake
is currently operating nine rigs in the play and plans to exit 2012 with
10 operated rigs. Production from the Powder River Basin Niobrara play
is just beginning to ramp up because of the time and capital needed to
build out gas processing and pipeline takeaway infrastructure. The
company expects a much larger contribution to production growth from the
Niobrara in 2013 and beyond as midstream constraints are reduced.

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

• 
  The Wallis 23-33-71 A 3H in Converse County, WY achieved a peak
  rate of approximately 1,990 boe per day, which included 1,105 bbls of
  oil, 385 bbls of NGL and 3.0 mmcf of natural gas per day;
  
• 
  The York Ranch 26-33-70 A 1H in Converse County, WY achieved a
  peak rate of approximately 1,750 boe per day, which included 745 bbls
  of oil, 440 bbls of NGL and 3.4 mmcf of natural gas per day; and
  
• 
  The Clausen Ranch 25-34-71 ST A 1H in Converse County, WY
  achieved a peak rate of approximately 1,720 boe per day, which
  included 1,075 bbls of oil, 280 bbls of NGL and 2.2 mmcf of natural
  gas per day.
  

In February 2011, Chesapeake entered into a joint venture with CNOOC to
develop the Niobrara play. As of September 30, 2012, the company′s
remaining drilling carry from CNOOC was approximately $480 million.
Chesapeake anticipates using 100% of the remaining 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
pleased to report our liquids production continues its impressive
growth, led by a 96% year-over-year and 21% sequential increase in our
oil production. Three years ago when Chesapeake was producing only
33,000 bbls per day of liquids, we embarked on a strategy to transform
our asset base from one focused almost exclusively on natural gas to one
that would provide more balance between liquids and natural gas
production and that would likely also lead to higher returns on capital.
Our current liquids production now exceeds 140,000 bbls per day, even
after excluding 21,000 bbls per day recently sold in the Permian
transactions. We believe the company remains on target to reach our goal
of 250,000 bbls per day of net liquids production in 2015.

'I am also pleased to see our 2012 third quarter adjusted ebitda and
operating cash flow increase 27% and 25% sequentially, respectively.
Improving natural gas market fundamentals, combined with our increasing
liquids production, the completion of our 2012-13 asset sales program
and our long-term debt reduction to below $9.5 billion, should enable
Chesapeake to continue making significant financial progress in the 2012
fourth quarter and in 2013 as well.?

2012 Third Quarter Financial and Operational Results Conference Call
Information

A conference call to discuss this release has been scheduled for Friday,
November 2, 2012 at 9:00 am EDT. The telephone number to access the
conference call is 913-312-0381 or toll-free 888-778-8907.
The passcode for the call is 8299445. 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 Friday,
November 2, 2012 and will run through midnight Friday, November 16,
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 8299445.
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 that give our current expectations or
forecasts of future events.They include estimates of natural gas
and oil reserves, projected production, estimates of operating costs,
planned development drilling and use of joint venture drilling carries,
effects of anticipated asset sales, projected cash flow and liquidity,
business strategy and other plans and objectives for future operations.Disclosures concerning the estimated contribution of derivative
contracts 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 our planned 2012 asset sales. Our
ability to consummate each of these transactions is subject to changes
in market conditions and other factors. If one or more of the
transactions is not completed in the anticipated time frame or at all or
for less proceeds than anticipated, our ability to fund budgeted capital
expenditures, reduce our indebtedness as planned and maintain our
compliance with bank revolving credit agreement covenants could be
adversely affected.

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 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.