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

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

  Company Reports 2012 Third Quarter Net Loss to Common Stockholders of $2.1
Billion, or $3.19 per Fully Diluted Common Share, on Revenue of $3.0 Billion;
 Company Reports Adjusted Net Income Available to Common Stockholders of $33
  Million, or $0.10 per Fully Diluted Common Share, Adjusted Ebitda of $1.0
Billion and Operating Cash Flow of $1.1 Billion; Adjusted Ebitda Increases 27%
       Sequentially and Operating Cash Flow Increases 25% Sequentially

 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

Business Wire

OKLAHOMA CITY -- November 01, 2012

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.

                                            Three Months Ended
                                             9/30/12    6/30/12    9/30/11
Average daily production (in mmcfe)^(a)      4,142       3,808       3,329
Natural gas equivalent production (in        381         347         306
bcfe)
Natural gas equivalent realized price        4.04        3.77        5.78
($/mcfe)^(b)
Oil production (in mbbls)                    8,996       7,325       4,589
Average realized oil price ($/bbl)^(b)       90.79       91.58       82.47
Oil as % of total production                 14          13          9
NGL production (in mbbls)                    4,130       4,525       4,080
Average realized NGL price ($/bbl)^(b)       31.22       25.94       41.16
NGL as % of total production                 7           8           8
Liquids as % of realized revenue^(c)         61          60          31
Liquids as % of unhedged revenue^(c)         63          70          40
Natural gas production (in bcf)              302         275         254
Average realized natural gas price           1.97        1.88        4.82
($/mcf)^(b)
Natural gas as % of total production         79          79          83
Natural gas as % of realized revenue         39          40          69
Natural gas as % of unhedged revenue         37          30          60
Marketing, gathering and compression net     0.11        0.05        0.10
margin ($/mcfe)^(d)
Oilfield services net margin ($/mcfe)^(d)    0.09        0.14        0.11
Production expenses ($/mcfe)                 (0.84   )   (0.97   )   (0.92   )
Production taxes ($/mcfe)                    (0.14   )   (0.12   )   (0.16   )
General and administrative costs             (0.34   )   (0.39   )   (0.41   )
($/mcfe)^(e)
Stock-based compensation ($/mcfe)            (0.05   )   (0.06   )   (0.08   )
DD&A of natural gas and liquids properties   (2.00   )   (1.70   )   (1.38   )
($/mcfe)^(f)
D&A of other assets ($/mcfe)^(g)             (0.17   )   (0.24   )   (0.24   )
Interest expense ($/mcfe)^(b)                (0.10   )   (0.06   )   (0.01   )
Operating cash flow ($ in millions)^(h)      1,118       895         1,409
Operating cash flow ($/mcfe)                 2.93        2.58        4.60
Adjusted ebitda ($ in millions)^(i)          1,021       803         1,385
Adjusted ebitda ($/mcfe)                     2.68        2.32        4.52
Net income (loss) to common stockholders     (2,055  )   929         879
($ in millions)
Earnings (loss) per share – diluted ($)      (3.19   )   1.29        1.23
Adjusted net income to common stockholders   33          3           496
($ in millions)^(j)
Adjusted earnings per share – diluted ($)    0.10        0.06        0.72
                                                                             

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.

         Natural Gas                        Oil
Year      % of Forecasted   NYMEX             % of Forecasted   NYMEX
          Production          Natural Gas       Production          Oil WTI
4Q 2012   76%                 $3.06             76%                 $99.14
2013      —                   —                 69%                 $96.01
                                                                    

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.

                Natural                Proved                      Proved
                Gas                                  PV-10
Pricing        Price     Oil       Reserves                Developed
Method                      Price                    (billions)
                ($/mcf)                 (tcfe)                      Percentage
                            ($/bbl)
Trailing
12-month avg   $2.83     $95.05    16.2       $18.5        59%
(SEC)^(a)
9/30/12
10-year avg     $4.80       $88.58      22.2         $29.5          52%
NYMEX
strip^(b)
                                                                    

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 Section27A of the Securities Act of 1933
and Section21E 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
February29, 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.

                                                      
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per-share and unit data)
(unaudited)
                                                    
                                September 30,            September 30,
THREE MONTHS ENDED:                                  
                                2012                     2011
                                $           $/mcfe      $          $/mcfe
REVENUES:                                                           
Natural gas, oil and NGL          1,437        3.77        2,402       7.84
Marketing, gathering and          1,381        3.62        1,422       4.64
compression
Oilfield services                152         0.40       153        0.50
Total Revenues                   2,970       7.79       3,977      12.98
                                                                             
OPERATING EXPENSES:
Natural gas, oil and NGL          320          0.84        282         0.92
production
Production taxes                  53           0.14        50          0.16
Marketing, gathering and          1,339        3.51        1,392       4.55
compression
Oilfield services                 116          0.30        118         0.39
General and administrative        148          0.39        151         0.49
Natural gas, oil and NGL
depreciation, depletion and       762          2.00        423         1.38

amortization
Depreciation and amortization     66           0.17        75          0.24
of other assets
Impairment of natural gas and     3,315        8.70        —           —
oil properties
Losses on sales and
impairments of fixed assets      45          0.12       3          0.01

and other
Total Operating Expenses         6,164       16.17      2,494      8.14
                                                                             
INCOME (LOSS) FROM OPERATIONS    (3,194 )    (8.38 )    1,483      4.84
                                                                             
OTHER INCOME (EXPENSE):
Interest expense                  (36    )     (0.10 )     (4    )     (0.01 )
Earnings (losses) on              (23    )     (0.06 )     28          0.09
investments
Gain on sale of investment        31           0.08        —           —
Other income                     (9     )    (0.02 )    4          0.01
Total Other Income (Expense)     (37    )    (0.10 )    28         0.09
                                                                             
INCOME (LOSS) BEFORE INCOME       (3,231 )     (8.48 )     1,511       4.93
TAXES
                                                                             
INCOME TAX EXPENSE (BENEFIT):
Current income taxes              22           0.05        (1    )     —
Deferred income taxes            (1,282 )    (3.36 )    590        1.92
Total Income Tax Expense         (1,260 )    (3.31 )    589        1.92
(Benefit)
                                                                             
NET INCOME (LOSS)                 (1,971 )     (5.17 )     922         3.01
                                                                             
Net income attributable to       (41    )    (0.11 )    —          —
noncontrolling interests
                                                                             
NET INCOME (LOSS)                (2,012 )    (5.28 )    922        3.01
ATTRIBUTABLE TO CHESAPEAKE
                                                                             
Preferred stock dividends        (43    )    (0.11 )    (43   )    (0.14 )
                                                                             
NET INCOME (LOSS) AVAILABLE      (2,055 )    (5.39 )    879        2.87
TO COMMON STOCKHOLDERS
                                                                             
EARNINGS (LOSS) PER COMMON
SHARE:
Basic                           $ (3.19  )               $ 1.38
Diluted                         $ (3.19  )               $ 1.23
                                                                             
WEIGHTED AVERAGE COMMON AND
COMMON EQUIVALENT SHARES
OUTSTANDING (in millions):
Basic                            644                     638
Diluted                          644                     753
                                                                             

                                                      
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per-share and unit data)
(unaudited)
                                                    
                                September 30,            September 30,
NINE MONTHS ENDED:                                   
                                2012                     2011
                                $           $/mcfe      $          $/mcfe
REVENUES:                                                           
Natural gas, oil and NGL          4,622        4.36        4,688       5.43
Marketing, gathering and          3,710        3.50        3,844       4.45
compression
Oilfield services                446         0.42       376        0.44
Total Revenues                   8,778       8.28       8,908      10.32
                                                                             
OPERATING EXPENSES:
Natural gas, oil and NGL          1,005        0.95        782         0.91
production
Production taxes                  141          0.13        140         0.16
Marketing, gathering and          3,631        3.43        3,744       4.34
compression
Oilfield services                 321          0.30        287         0.33
General and administrative        440          0.41        410         0.47
Natural gas, oil and NGL
depreciation, depletion and       1,856        1.75        1,147       1.33

amortization
Depreciation and amortization     233          0.22        206         0.24
of other assets
Impairment of natural gas and     3,315        3.13        —           —
oil properties
Losses on sales and
impairments of fixed assets      286         0.27       7          0.01

and other
Total Operating Expenses         11,228      10.59      6,723      7.79
                                                                             
INCOME (LOSS) FROM OPERATIONS    (2,450 )    (2.31 )    2,185      2.53
                                                                             
OTHER INCOME (EXPENSE):
Interest expense                  (63    )     (0.06 )     (37   )     (0.04 )
Earnings (losses) on              (87    )     (0.08 )     100         0.11
investments
Gain on sales of investments      1,061        1.00        —           —
Losses on purchases or            —            —           (176  )     (0.20 )
exchanges of debt
Other income                     2           —          9          0.01
Total Other Income (Expense)     913         0.86       (104  )    (0.12 )
                                                                             
INCOME (LOSS) BEFORE INCOME       (1,537 )     (1.45 )     2,081       2.41
TAXES
                                                                             
INCOME TAX EXPENSE (BENEFIT):
Current income taxes              24           0.02        11          0.01
Deferred income taxes            (623   )    (0.59 )    801        0.93
Total Income Tax Expense         (599   )    (0.57 )    812        0.94
(Benefit)
                                                                             
NET INCOME (LOSS)                 (938   )     (0.88 )     1,269       1.47
                                                                             
Net income attributable to       (131   )    (0.13 )    —          —
noncontrolling interests
                                                                             
NET INCOME (LOSS)                (1,069 )    (1.01 )    1,269      1.47
ATTRIBUTABLE TO CHESAPEAKE
                                                                             
Preferred stock dividends        (128   )    (0.12 )    (128  )    (0.15 )
                                                                             
NET INCOME (LOSS) AVAILABLE      (1,197 )    (1.13 )    1,141      1.32
TO COMMON STOCKHOLDERS
                                                                             
EARNINGS (LOSS) PER COMMON
SHARE:
Basic                           $ (1.86  )               $ 1.79
Diluted                         $ (1.86  )               $ 1.69
                                                                             
WEIGHTED AVERAGE COMMON AND
COMMON EQUIVALENT SHARES
OUTSTANDING (in millions):
Basic                            643                     636
Diluted                          643                     752
                                                                             

                                                        
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
                                                       
                                          September 30,     December 31,
                                        2012              2011
                                                            
Cash and cash equivalents                 $    142          $   351
Other current assets                          3,469           2,826
Total Current Assets                          3,611           3,177
                                                            
Property and equipment (net)                   40,603           36,739
Other assets                                  1,457           1,919
Total Assets                              $    45,671       $   41,835
                                                            
Current liabilities                       $    6,456        $   7,082
Long-term debt, net of discounts               15,755           10,626
Other long-term liabilities                    2,351            2,682
Deferred income tax liabilities               3,418           3,484
Total Liabilities                             27,980          23,874
                                                            
Chesapeake stockholders' equity                15,327           16,624
Noncontrolling interests                      2,364           1,337
Total Equity                                  17,691          17,961
                                                            
Total Liabilities and Equity              $    45,671       $   41,835
                                                            
Common Shares Outstanding (in millions)       665             659
                                                                

                                                              
CHESAPEAKE ENERGY CORPORATION
CAPITALIZATION
($ in millions)
(unaudited)
                                                             
                                                September 30,     December 31,
                                              2012            2011
                                                                  
Total debt, net of unrestricted cash            $  16,076         $  10,275
Chesapeake stockholders' equity                    15,327            16,624
Noncontrolling interests^(a)                      2,364           1,337   
Total                                           $  33,767        $  28,236  
                                                                  
Debt to capitalization ratio                       48      %         36      %
                                                                  
(a) Includes third-party ownership as
follows:
CHK Cleveland Tonkawa, L.L.C.                   $  1,015          $  —
CHK Utica, L.L.C.                                  950               950
Chesapeake Granite Wash Trust                      365               380
Cardinal Gas Services, L.L.C.                     34              7       
Total                                           $  2,364         $  1,337   
                                                                             

                                       
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF 2012 CHANGES TO NATURAL GAS AND OIL PROPERTIES
BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AS OF SEPTEMBER 30,
2012
($ in millions, except per-unit data)
(unaudited)
                                                                   
                                       Proved Reserves
                                         Cost         Bcfe^(a)       $/Mcfe
PROVED PROPERTIES:
Well costs on proved properties^(b)      $ 7,430        3,878    ^(d)   1.92
^(c)
Acquisition of proved properties^(e)       319          37              8.67
Sale of proved properties                 (1,322 )     (544     )      2.43
Total net proved properties               6,427       3,371           1.91
                                                                        
Revisions – price                          —            (4,878   )      —
                                                                        
UNPROVED PROPERTIES:
Well costs on unproved properties^(f)      (195   )     —               —
Acquisition of unproved properties,        1,628        —               —
net^(g)
Sale of unproved properties               (930   )     —               —
Total net unproved properties             503         —               —
                                                                        
OTHER:
Capitalized interest on unproved           766          —               —
properties
Geological and geophysical costs           148          —               —
Asset retirement obligations              16          —               —
Total other                               930         —               —
                                                                        
Total                                    $ 7,860       (1,507   )      —
                                                                        

                                                           
CHESAPEAKE ENERGY CORPORATION
ROLL-FORWARD OF PROVED RESERVES
NINE MONTHS ENDED SEPTEMBER 30, 2012
BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AS OF SEPTEMBER 30,
2012
(unaudited)
                                                              
                                                              Bcfe^(a)
                                                                
Beginning balance, January 1, 2012                                 18,789
Production                                                         (1,060  )
Acquisitions                                                       37
Divestitures                                                       (544    )
Revisions – changes to previous estimates                          (596    )
Revisions – price                                                  (4,878  )
Extensions and discoveries                                        4,474   
Ending balance, September 30, 2012                                16,222  
                                                                
Proved reserves decline rate before acquisitions and               (11     )%
divestitures
Proved reserves decline rate after acquisitions and                (14     )%
divestitures
                                                                
Proved developed reserves                                          9,608
Proved developed reserves percentage                               59      %
                                                                
PV-10 ($ in billions)^(a)                                       $  18,451
                                                                           

      Reserve volumes and PV-10 value estimated using SEC reserve recognition
      standards and pricing assumptions based on the trailing 12-month average
(a)  first-day-of-the-month prices as of September 30, 2012 of $2.83 per mcf
      of natural gas and $95.05 per bbl of oil, before field differential
      adjustments.
      
      Net of well cost carries of $655 million associated with the
(b)   Statoil-Marcellus, CNOOC-Eagle Ford, CNOOC-Niobrara and Total-Utica
      joint ventures.
      
      Includes $1.055 billion of well costs incurred in prior quarters
(c)   (previously classified as well costs on unproved properties) related to
      wells that were evaluated for the existence of proved reserves in the
      current quarter.
      
      Includes 596 bcfe of downward revisions resulting from changes to
      previous estimates and excludes downward revisions of 4.9 tcfe primarily
(d)   resulting from lower natural gas prices using the average
      first-day-of-the-month price for the twelve months ended September 30,
      2012, compared to the twelve months ended December 31, 2011.
      
      Includes 28 bcfe of proved reserves associated with the company’s
(e)   Permian Basin volumetric production payment repurchased by the company
      for $313 million and subsequently resold to multiple parties in
      September and October 2012.
      
      Includes $860 million of well costs on unproved properties incurred in
      the current quarter, offset by the transfer of $1.055 billion previously
(f)   classified as well costs on unproved properties that were evaluated for
      the existence of proved reserves in the current quarter. See footnote
      (e).
      
(g)   Net of joint venture partner reimbursements.
      

                                                  
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA – NATURAL GAS, OIL AND NGL SALES AND INTEREST EXPENSE
(unaudited)
                                                 
                         Three Months Ended            Nine Months Ended
                         September 30,                 September 30,
                         2012        2011            2012        2011
Natural Gas, Oil and
NGL Sales ($ in
millions):
Natural gas sales        $ 543         $ 861           $ 1,359       $ 2,412
Natural gas
derivatives – realized     52            364             391           1,322
gains (losses)
Natural gas
derivatives –             (90   )      (28   )        (401  )      (693  )
unrealized gains
(losses)
                                                                     
Total Natural Gas         505         1,197         1,349       3,041 
Sales
                                                                     
Oil sales                  792           386             2,038         1,048
Oil derivatives –
realized gains             25            (8    )         6             (51   )
(losses)
Oil derivatives –
unrealized gains          (14   )      645           803         247   
(losses)
                                                                     
Total Oil Sales           803         1,023         2,847       1,244 
                                                                     
NGL sales                  129           180             401           432
NGL derivatives –
realized gains             —             (12   )         (9    )       (31   )
(losses)
NGL derivatives –
unrealized gains          —           14            34          2     
(losses)
                                                                     
Total NGL Sales           129         182           426         403   
                                                                     
Total Natural Gas, Oil   $ 1,437      $ 2,402        $ 4,622      $ 4,688 
and NGL Sales
                                                                     
Average Sales Price –
excluding gains
(losses) on
derivatives:
Natural gas ($ per       $ 1.80        $ 3.39          $ 1.60        $ 3.30
mcf)
Oil ($ per bbl)          $ 88.07       $ 84.18         $ 91.31       $ 89.78
NGL ($ per bbl)          $ 31.22       $ 44.04         $ 30.86       $ 42.17
Natural gas equivalent   $ 3.84        $ 4.66          $ 3.58        $ 4.51
($ per mcfe)
                                                                     
Average Sales Price –
excluding unrealized
gains (losses) on
derivatives:
Natural gas ($ per       $ 1.97        $ 4.82          $ 2.06        $ 5.10
mcf)
Oil ($ per bbl)          $ 90.79       $ 82.47         $ 91.55       $ 85.45
NGL ($ per bbl)          $ 31.22       $ 41.16         $ 30.17       $ 39.10
Natural gas equivalent   $ 4.04        $ 5.78          $ 3.95        $ 5.94
($ per mcfe)
                                                                     
Interest Expense
(Income) ($ in
millions):
Interest^(a)             $ 38          $ 4             $ 67          $ 18
Derivatives – realized     —             —               —             6
(gains) losses
Derivatives –
unrealized (gains)        (2    )      —             (4    )      13    
losses
Total Interest Expense   $ 36         $ 4            $ 63         $ 37    

(a)  Net of amounts capitalized.
      

                                                             
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
                                                            
THREE MONTHS ENDED:                            September 30,     September 30,
                                              2012              2011
                                                                 
Beginning cash                                 $  1,024         $  109     
                                                                 
Cash provided by operating activities            949             1,631   
                                                                 
Cash flows from investing activities:
Well costs on proved and unproved properties      (2,353  )         (1,895  )
Acquisition of proved and unproved                (936    )         (1,116  )
properties^(a)
Sale of proved and unproved properties            808               55
Geological and geophysical costs                  (52     )         (55     )
Additions to other property and equipment         (605    )         (554    )
Proceeds from sales of other assets               140               157
Additions to investments                          (133    )         (86     )
Other                                            (102    )        19      
Total cash used in investing activities          (3,233  )        (3,475  )
                                                                 
Cash provided by financing activities            1,409           1,846   
                                                                 
Cash and cash equivalents classified in
current assets                                   (7      )        —       

held for sale
                                                                 
Ending cash                                    $  142           $  111     

(a)  Includes capitalized interest of $327 million and $151 million for the
      current quarter and the prior quarter, respectively.
      

                                                            
NINE MONTHS ENDED:                            September 30,   September 30,
                                              2012              2011
                                                                 
Beginning cash                                 $  351           $  102     
                                                                 
Cash provided by operating activities            1,978           3,724   
                                                                 
Cash flows from investing activities:
Well costs on proved and unproved properties      (7,360  )         (5,177  )
Acquisition of proved and unproved                (2,594  )         (3,300  )
properties^(b)
Sale of proved and unproved properties            2,226             5,883
Geological and geophysical costs                  (165    )         (168    )
Additions to other property and equipment         (1,916  )         (1,416  )
Proceeds from sales of other assets               219               682
Acquisition of drilling company                   —                 (339    )
Proceeds from (additions to) investments          (261    )         126
Proceeds from sale of select midstream            2,000             —
investment
Other                                            (303    )        (6      )
Total cash used in investing activities          (8,154  )        (3,715  )
                                                                 
Cash provided by (used in) financing             5,981           —       
activities
                                                                 
Cash and cash equivalents classified in
current assets                                   (14     )        —       

held for sale
                                                                 
Ending cash                                    $  142           $  111     

(b)  Includes capitalized interest of $653 million and $478 million for the
      current period and the prior period, respectively.
      

                                                           
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
                                                         
                                 September 30,     June 30,      September 30,
THREE MONTHS ENDED:             2012            2012        2011
                                                                 
CASH PROVIDED BY OPERATING       $  949            $ 755         $   1,631
ACTIVITIES
                                                                 
Changes in assets and              169            140           (222   )
liabilities
                                                                 
OPERATING CASH FLOW^(a)          $  1,118         $ 895        $   1,409  
                                                         
                                 September 30,     June 30,      September 30,
THREE MONTHS ENDED:             2012            2012        2011
                                                                 
NET INCOME (LOSS)                $  (1,971  )      $ 1,037       $   922
                                                                 
Income tax expense (benefit)        (1,260  )        663             589
Interest expense                    36               14              4
Depreciation and amortization       66               83              75
of other assets
Natural gas, oil and NGL
depreciation, depletion            762            588           423    

and amortization
                                                                 
EBITDA^(b)                       $  (2,367  )      $ 2,385      $   2,013  
                                                         
                                 September 30,     June 30,      September 30,
THREE MONTHS ENDED:             2012            2012        2011
                                                                 
CASH PROVIDED BY OPERATING       $  949            $ 755         $   1,631
ACTIVITIES
                                                                 
Changes in assets and               169              140             (222   )
liabilities
Interest expense                    36               14              4
Unrealized gains (losses) on
natural gas, oil and NGL            (104    )        810             631

Derivatives
Impairment of natural gas and       (3,315  )        —               —
oil properties
Losses on sales and
impairments of fixed                (25     )        (243  )         (3     )

assets and other
Gains (losses) on investments       4                943             (4     )
Stock-based compensation            (30     )        (31   )         (40    )
Other items                        (51     )       (3    )        16     
                                                                 
EBITDA^(b)                       $  (2,367  )      $ 2,385      $   2,013  

      Operating cash flow represents net cash provided by operating activities
      before changes in assets and liabilities. Operating cash flow is
      presented because management believes it is a useful adjunct to net cash
      provided by operating activities under accounting principles generally
      accepted in the United States (GAAP). Operating cash flow is widely
      accepted as a financial indicator of a natural gas and oil company's
      ability to generate cash which is used to internally fund exploration
(a)  and development activities and to service debt. This measure is widely
      used by investors and rating agencies in the valuation, comparison,
      rating and investment recommendations of companies within the natural
      gas and oil exploration and production industry. Operating cash flow is
      not a measure of financial performance under GAAP and should not be
      considered as an alternative to cash flows from operating, investing or
      financing activities as an indicator of cash flows, or as a measure of
      liquidity.
      
      Ebitda represents net income (loss) before income tax expense, interest
      expense and depreciation, depletion and amortization expense, Ebitda is
      presented as a supplemental financial measurement in the evaluation of
      our business. We believe that it provides additional information
      regarding our ability to meet our future debt service, capital
      expenditures and working capital requirements. This measure is widely
      used by investors and rating agencies in the valuation, comparison,
(b)   rating and investment recommendations of companies. Ebitda is also a
      financial measurement that, with certain negotiated adjustments, is
      reported to our lenders pursuant to our bank credit agreements and is
      used in the financial covenants in our bank credit agreements. Ebitda is
      not a measure of financial performance under GAAP. Accordingly, it
      should not be considered as a substitute for net income, income from
      operations, or cash flow provided by operating activities prepared in
      accordance with GAAP.
      

                                                             
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
                                                            
                                               September 30,     September 30,
NINE MONTHS ENDED:                            2012            2011
                                                                 
CASH PROVIDED BY OPERATING ACTIVITIES          $  1,978          $   3,724
                                                                 
Changes in assets and liabilities                946              274    
                                                                 
OPERATING CASH FLOW^(a)                        $  2,924         $   3,998  
                                                            
                                               September 30,     September 30,
NINE MONTHS ENDED:                            2012            2011
                                                                 
NET INCOME (LOSS)                              $  (938    )      $   1,269
                                                                 
Income tax expense (benefit)                      (599    )          812
Interest expense                                  63                 37
Depreciation and amortization of other            233                206
assets
Natural gas, oil and NGL depreciation,           1,856            1,147  
depletion and amortization
                                                                 
EBITDA^(b)                                     $  615           $   3,471  
                                                            
                                               September 30,     September 30,
NINE MONTHS ENDED:                            2012            2011
                                                                 
CASH PROVIDED BY OPERATING ACTIVITIES          $  1,978          $   3,724
                                                                 
Changes in assets and liabilities                 946                274
Interest expense                                  63                 37
Unrealized gains (losses) on natural gas,         436                (444   )
oil and NGL derivatives
Impairment of natural gas and oil properties      (3,315  )          —
Losses on sales and impairments of fixed          (262    )          (7     )
assets and other
Gains on investments                              914                19
Stock-based compensation                          (93     )          (119   )
Other items                                      (52     )         (13    )
                                                                 
EBITDA^(b)                                     $  615           $   3,471  

      Operating cash flow represents net cash provided by operating activities
      before changes in assets and liabilities. Operating cash flow is
      presented because management believes it is a useful adjunct to net cash
      provided by operating activities under accounting principles generally
      accepted in the United States (GAAP). Operating cash flow is widely
      accepted as a financial indicator of a natural gas and oil company's
      ability to generate cash which is used to internally fund exploration
(a)  and development activities and to service debt. This measure is widely
      used by investors and rating agencies in the valuation, comparison,
      rating and investment recommendations of companies within the natural
      gas and oil exploration and production industry. Operating cash flow is
      not a measure of financial performance under GAAP and should not be
      considered as an alternative to cash flows from operating, investing or
      financing activities as an indicator of cash flows, or as a measure of
      liquidity.
      
      Ebitda represents net income (loss) before income tax expense, interest
      expense and depreciation, depletion and amortization expense, Ebitda is
      presented as a supplemental financial measurement in the evaluation of
      our business. We believe that it provides additional information
      regarding our ability to meet our future debt service, capital
      expenditures and working capital requirements. This measure is widely
      used by investors and rating agencies in the valuation, comparison,
(b)   rating and investment recommendations of companies. Ebitda is also a
      financial measurement that, with certain negotiated adjustments, is
      reported to our lenders pursuant to our bank credit agreements and is
      used in the financial covenants in our bank credit agreements. Ebitda is
      not a measure of financial performance under GAAP. Accordingly, it
      should not be considered as a substitute for net income, income from
      operations, or cash flow provided by operating activities prepared in
      accordance with GAAP.
      

                                                           
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
                                                         
                                 September 30,     June 30,      September 30,
THREE MONTHS ENDED:             2012            2012        2011
                                                                 
EBITDA                           $  (2,367  )      $ 2,385       $   2,013
                                                                 
Adjustments:
Unrealized (gains) losses on
natural gas, oil and                104              (810  )         (631   )

NGL derivatives
Impairment of natural gas and       3,315            —               —
oil properties
Losses on sales and
impairments of                      45               243             3

fixed assets and other
Net income attributable to          (41     )        (65   )         —
noncontrolling interests
Gains on investments                (31     )        (957  )         —
Other                              (4      )       7             —      
                                                                 
Adjusted EBITDA^(a)              $  1,021         $ 803        $   1,385  

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

                                                            
                                              September 30,   September 30,
NINE MONTHS ENDED:                            2012            2011
                                                                 
EBITDA                                         $   615           $    3,471
                                                                 
Adjustments:
Unrealized (gains) losses on natural gas,          (436   )           444
oil and NGL derivatives
Impairment of natural gas and oil properties       3,315              —
Losses on sales and impairments of fixed           286                7
assets and other
Net income attributable to noncontrolling          (131   )           —
interests
Losses on purchases or exchanges of debt           —                  176
Gains on investments                               (988   )           —
Other                                             1                —
                                                                 
Adjusted EBITDA^(a)                            $   2,662        $    4,098

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

                                                           
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per-share data)
(unaudited)
                                                         
                                  September 30,     June 30,     September 30,
THREE MONTHS ENDED:              2012            2012       2011
                                                                 
Net income (loss) available to    $  (2,055  )      $ 929        $   879
common stockholders
                                                                 
Adjustments, net of tax:
Unrealized (gains) losses on         63               (498 )         (385   )
derivatives
Impairment of natural gas and        2,022            —              —
oil properties
Losses on sales and impairments
of                                   28               148            2

fixed assets and other
Gains on investments                 (19     )        (584 )         —
Other                               (6      )       8            —      
                                                                 
Adjusted net income available
to common                            33               3              496

stockholders^(a)
Preferred stock dividends           43             43           43     
Total adjusted net income         $  76            $ 46        $   539    
                                                                 
Weighted average fully diluted       754              751            753
shares outstanding^(b)
                                                                 
Adjusted earnings per share       $  0.10           $ 0.06       $   0.72
assuming dilution^(a)

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

                                                             
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per-share data)
(unaudited)
                                                            
                                               September 30,     September 30,
NINE MONTHS ENDED:                            2012             2011
                                                                 
Net income (loss) available to common          $  (1,197  )      $    1,141
stockholders
                                                                 
Adjustments, net of tax:
Unrealized (gains) losses on derivatives          (268    )           279
Impairment of natural gas and oil properties      2,022               —
Losses on sales and impairments of fixed          174                 4
assets and other
Losses on purchases or exchanges of debt          —                   107
Loss on foreign currency derivatives              —                   11
Gains on investments                              (603    )           —
Other                                            2                 —
                                                                 
Adjusted net income available to common           130                 1,542
stockholders^(a)
Preferred stock dividends                        128               128
Total adjusted net income                      $  258           $    1,670
                                                                 
Weighted average fully diluted shares             753                 752
outstanding^(b)
                                                                 
Adjusted earnings per share assuming           $  0.34           $    2.22
dilution^(a)

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

                                 SCHEDULE “A”
                 MANAGEMENT’S OUTLOOK AS OF NOVEMBER 1, 2012

Chesapeake periodically provides management guidance on certain factors that
affect its future financial performance. The primary changes from the
company’s August 6, 2012 Outlook are in italicized bold and reflect estimated
natural gas curtailments of approximately 60 bcf in the 2012 first half and
also include estimated future production decreases of approximately 45 bcfe in
2012 and 140 bcfe in 2013 associated with the company’s completed and planned
asset sales. Management and the board of directors continue to review
operational plans for 2013 and beyond which could result in changes to this
Outlook.

Chesapeake Energy Corporation Consolidated Projections
For Years Ending December 31, 2012 and 2013
                                                             
                                                 Year Ending      Year Ending

                                                 12/31/12         12/31/13
Estimated Production:
Natural gas – bcf                                1,120 –          1,030 –
                                                 1,140            1,070
Oil – mbbls                                      30,000 –         36,000 –
                                                 31,000           38,000
NGL – mbbls                                      17,000 –         24,000 –
                                                 18,000           26,000
Natural gas equivalent – bcfe                    1,402 –          1,390 –
                                                 1,434            1,454
                                                                  
Daily natural gas equivalent midpoint –          3,870            3,895
mmcfe
                                                                  
YOY estimated production increase (adjusted      18%              1%
for planned asset sales)
                                                                  
NYMEX Price^(a) (for calculation of realized
hedging effects only):
Natural gas - $/mcf                              $2.77            $4.00
Oil - $/bbl                                      $94.66           $90.00
                                                                  
Estimated Realized Hedging Effects (based on
assumed NYMEX prices above):
Natural gas - $/mcf                              $0.30            $0.00
Oil - $/bbl                                      $0.99            $4.50
                                                                  
Estimated Gathering/Marketing/Transportation
Differentials to NYMEX Prices:
Natural gas - $/mcf                              $1.00 –1.10      $1.15 – 1.25
Oil - $/bbl                                      $4.50 – 6.50     $4.50 – 6.50
NGL - $/bbl                                      $67.00 –         $63.00 –
                                                 70.00            67.00
                                                                  
Operating Costs per Mcfe of Projected
Production:
Production expense                               $0.90 – 1.00     $0.90 – 1.00
Production taxes (~5% of O&G revenues)           $0.15 – 0.20     $0.25 – 0.30
General and administrative^(b)                   $0.39 – 0.44     $0.39 – 0.44
Stock-based compensation (noncash)               $0.04 – 0.06     $0.04 – 0.06
DD&A of natural gas and liquids assets           $1.65 – 1.85     $1.65 – 1.85
Depreciation of other assets                     $0.22 – 0.27     $0.25 – 0.30
Interest expense^(c)                             $0.05 – 0.10     $0.05 – 0.10
                                                                  
Other ($ millions):
Marketing, gathering and compression net         $90 – 100        $50 – 75
margin^(d)
Oilfield services net margin^(d)                 $175 – 200       $200 – 250
Other income (including certain equity           $25              –
investments)
Net income attributable to noncontrolling        ($180) –         ($200) –
interest^(e)                                     (200)            (240)
                                                                  
Book Tax Rate                                    39%              39%

Weighted average shares outstanding (in
millions):
Basic                                            640 – 645        645 – 650
Diluted                                          753 – 758        758 – 763
                                                                  
Operating cash flow before changes in assets     $3,800           $4,250 –
and liabilities^(f)(g)                                            5,250
Well costs on proved and unproved properties     ($8,750)         ($5,750 –
                                                                  6,250)
Acquisition of unproved properties, net          ($1,750)         ($400)

a) NYMEX natural gas and oil prices have been updated for actual contract
prices through October and September, respectively.
b) Excludes expenses associated with noncash stock-based compensation.
c) Does not include unrealized gains or losses on interest rate derivatives.
d) Includes revenue and operating costs and excludes depreciation and
amortization of other assets.
e) Net income attributable to noncontrolling interests of Chesapeake Granite
Wash Trust, CHK Utica, L.L.C., CHK Cleveland Tonkawa, L.L.C. and Cardinal Gas
Services, L.L.C.
f) A non-GAAP financial measure. We are unable to provide a reconciliation to
projected cash provided by operating activities, the most comparable GAAP
measure, because of uncertainties associated with projecting future changes in
assets and liabilities.
g) Assumes NYMEX prices on open contracts of $3.50 per mcf and $90.00 per bbl
in 2012 and $3.50 to $4.50 per mcf and $90.00 per bbl in 2013.

Natural Gas, Oil and NGL Hedging Activities

Chesapeake enters into natural gas, oil and NGL derivative transactions in
order to mitigate a portion of its exposure to adverse changes in market
prices. Please see the quarterly reports on Form 10-Q and annual reports on
Form 10-K filed by Chesapeake with the SEC for detailed information about
derivative instruments the company uses, its quarter-end derivative positions
and the accounting for natural gas, oil and NGL derivatives.

As of November 1, 2012, the company has the following open natural gas swaps
in place and gains (losses) related to closed natural gas trades and premiums
for call options for future production periods.

                                                                    Total
                                                        Total       Gains from
                                                        Gains
                                                                    Closed
                                           Open Swap    (Losses)    Trades
                                                        from
                   Avg.       Forecasted   Positions                and
                   NYMEX                                Closed      Premiums
         Open                 Natural      as a % of    Trades
       Swaps    Price of  Gas                                for Call
         (bcf)                             Forecasted   and         Options
                   Open       Production                Premiums
                   Swaps                   Natural                  per mcf of
                              (bcf)        Gas          for Call
                                                        Options     Forecasted
                                           Production
                                                        ($ in       Natural
                                                        millions)   Gas

                                                                    Production
Q4      215     $ 3.06   281        76    %     $  15     $   0.05
2012
                                                             
Q1       0                                              $  (11  )
2013
Q2       0                                                 8
2013
Q3       0                                                 6
2013
Q4      0                                    (3   )     
2013
Total   0       $ 0.00   1,050      0     %     $  0      $   0.00
2013
Total   0                                  $  (74  )     
2014
Total   0                                  $  (131 )     
2015
Total
2016 –  0                                  $  (161 )     
2022
                                                                        

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

                                                                Call Options
                                                  Forecasted
                                                                as a % of
                    Call Options   Avg. NYMEX     Natural Gas
                  (bcf)                                    Forecasted
                                   Strike Price   Production
                                                                Natural Gas
                                                  (bcf)
                                                                Production
Q4 2012            40           $   3.25     281         14     %
                                                           
Total 2013         0            $   0.00     1,050       0      %
Total 2014         0            $   0.00                      
Total 2015         0            $   0.00                      
Total 2016 – 2020  260          $   8.90                      
                                                                       

The company currently has the following purchased natural gas put swaptions in
place:

                                                           Put Swaption
                                             Forecasted
                                                           as a % of
             Put Swaptions   Avg. NYMEX      Natural Gas
           (bcf)                                      Forecasted
                             Price of Swap   Production
                                                           Natural Gas
                                             (bcf)
                                                           Production
Q1 2013     8              $   3.66                   
Q2 2013      10              $   3.64
Q3 2013      2               $   3.50
Q4 2013     0             $   0.00                       
Total 2013  20            $   3.64      1,050       2      %
                                                                  

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

             
              Volume (Bcf)  Avg. NYMEX less
Q4 2012      8            $      0.74
                                    
2013         44           $      0.21
2014         28           $      0.32
2015 - 2022  40           $      0.48
                                    

As of November 1, 2012, the company has the following open crude oil swaps in
place and gains (losses) related to closed crude oil contracts and premiums
for call options for future production periods (note: the company also has
5,000 bbls per day of propane call options in Q4 2012):

                                                                       Total
                                                                       Gains

                                                         Total Gains   (Losses)
                                                                       from
                                            Open Swap    (Losses)
                                                         from          Closed
                   Avg.        Forecasted   Positions                  Trades
        Open       NYMEX                    as           Closed
                               Oil                       Trades        and
      Swaps     Price of               a % of                   Premiums
                               Production                and           for
        (mbbls)    Open                     Forecasted   Premiums
                   Swaps       (mbbls)                                 Call
                                            Oil          for Call      Options
                                                         Options       per
                                            Production
                                                         ($millions)   bbl of
                                                                       Forecasted

                                                                       Oil
                                                                       Production
Q4     6,197    $ 99.14   8,171      76    %     $  (31   )   $  (3.83 )
2012
                                                                
Q1      5,647        95.95                               $  1
2013
Q2      6,672        96.10                               $  1
2013
Q3      6,687        96.02                               $  2
2013
Q4     6,662     95.97                       $  2               
2013
Total  25,668   $ 96.01   37,000     69    %     $  6        $  0.17  
2013
Total  918      $ 90.85                       $  (151  )          
2014
Total  500      $ 88.75                       $  265             
2015
Total
2016   0                                    $  117             
–
2021
                                                                                

The company currently has the following crude oil written call options in
place:

                                                  Forecasted   Call Options

                    Call Options   Avg. NYMEX     Oil          as a % of
                  (mbbls)                                
                                   Strike Price   Production   Forecasted Oil

                                                  (mbbls)      Production
Q4 2012            0            $  --        8,171      0       %
                                                          
Q1 2013             3,390          $  99.56
Q2 2013             3,428          $  99.56
Q3 2013             3,006          $  98.62
Q4 2013            3,006        $  98.62                      
Total 2013         12,830       $  99.12     37,000     35      %
Total 2014         17,612       $  98.79                      
Total 2015         27,048       $  100.99                     
Total 2016 – 2017  24,220       $  100.07                     
                                                                       

The company has the following oil basis protection swaps in place:

            
             Volume (mbbls)  Avg. NYMEX plus
Q4 2012     951            $     17.70
                                    
Q1 2013      2,070            $     14.99
Q2 2013     1,365          $     12.55
Total 2013  3,435          $     14.02
                                    

                                 SCHEDULE “B”
                  MANAGEMENT’S OUTLOOK AS OF AUGUST 6, 2012
                        (PROVIDED FOR REFERENCE ONLY)
               NOW SUPERSEDED BY OUTLOOK AS OF NOVEMBER 1, 2012

Below is the company’s previous Outlook, as provided on August 6, 2012, which
reflected projected voluntary natural gas curtailments of approximately 60 bcf
in the 2012 first half and also include estimated future production decreases
of approximately 45 bcfe in 2012 and 140 bcfe in 2013 associated with the
company’s planned Permian Basin, Mississippi Lime and other asset sales.

Chesapeake Energy Corporation Consolidated Projections
For Years Ending December 31, 2012 and 2013
                                                              
                                                Year Ending       Year Ending

                                                12/31/12          12/31/13
Estimated Production:
Natural gas – bcf                               1,120 – 1,140     1,030 –
                                                                  1,070
Oil – mbbls                                     29,000 –          36,000 –
                                                30,000            38,000
NGL – mbbls                                     17,000 –          24,000 –
                                                18,000            26,000
Natural gas equivalent – bcfe                   1,396 – 1,428     1,390 –
                                                                  1,454
                                                                  
Daily natural gas equivalent midpoint – mmcfe   3,855             3,895
                                                                  
YOY estimated production increase including     18%               1%
asset sales
                                                                  
NYMEX Price^(a) (for calculation of realized
hedging effects only):
Natural gas - $/mcf                             $2.79             $3.75
Oil - $/bbl                                     $93.93            $90.00
                                                                  
Estimated Realized Hedging Effects (based on
assumed NYMEX prices above):
Natural gas - $/mcf                             $0.29             $0.01
Oil - $/bbl                                     $0.81             $0.48
                                                                  
Estimated Gathering/Marketing/Transportation
Differentials to NYMEX Prices:
Natural gas - $/mcf                             $1.00 –1.10       $1.15 – 1.25
Oil - $/bbl                                     $4.50 – 6.50      $4.50 – 6.50
NGL - $/bbl                                     $67.00 –          $63.00 –
                                                70.00             67.00
                                                                  
Operating Costs per Mcfe of Projected
Production:
Production expense                              $0.95 – 1.05      $0.95 – 1.05
Production taxes (~5% of O&G revenues)          $0.15 – 0.20      $0.25 – 0.30
General and administrative^(b)                  $0.39 – 0.44      $0.39 – 0.44
Stock-based compensation (noncash)              $0.04 – 0.06      $0.04 – 0.06
DD&A of natural gas and liquids assets          $1.40 – 1.60      $1.50 – 1.70
Depreciation of other assets                    $0.22 – 0.27      $0.25 – 0.30
Interest expense^(c)                            $0.05 – 0.10      $0.05 – 0.10
                                                                  
Other ($ millions):
Marketing, gathering and compression net        $70 – 80          $50 – 75
margin^(d)
Oilfield services net margin^(d)                $175 – 200        $200 – 250
Other income (including certain equity          $25               –
investments)
Net income attributable to noncontrolling       ($180) –          ($200) –
interest^(e)                                    (200)             (240)
                                                                  
Book Tax Rate                                   39%               39%

Weighted average shares outstanding (in
millions):
Basic                                           640 – 645         645 – 650
Diluted                                         753 – 758         758 – 763
                                                                  

                                                Year Ending       Year Ending

                                                12/31/12          12/31/13
                                                
                                                ($ millions)
Operating cash flow before changes in assets    $3,200 –          $3,750 –
and liabilities^(f)(g)                          3,250             4,750
                                                                  
Well costs on proved and unproved properties    ($8,000 –         ($5,750 –
                                                8,500)            6,250)
Acquisition of unproved properties, net         ($2,000)          ($400)
Investment in oilfield services, midstream      ($2,800 –         ($850 –
and other                                       3,100)            1,100)
Subtotal of net investment                      ($12,800 –        ($7,000 –
                                                13,600)           7,750)
                                                                  
Asset sales and other transactions              $13,000 –         $4,250 –
                                                14,000            5,000
                                                                  
Interest, dividends and cash taxes              ($1,100           ($1,000 –
                                                –1,350)           1,250)
                                                                 
Total budgeted cash flow surplus                $2,300            $0 – 750

a) NYMEX natural gas prices and NYMEX oil prices have been updated for actual
contract prices through August and July, respectively.
b) Excludes expenses associated with noncash stock-based compensation.
c) Does not include gains or losses on interest rate derivatives.
d) Includes revenue and operating costs and excludes depreciation and
amortization of other assets.
e) Net income attributable to noncontrolling interests of Chesapeake Granite
Wash Trust, CHK Utica, L.L.C., CHK Cleveland Tonkawa, L.L.C. and Cardinal Gas
Services, L.L.C.
f) A non-GAAP financial measure. We are unable to provide a reconciliation to
projected cash provided by operating activities, the most comparable GAAP
measure, because of uncertainties associated with projecting future changes in
assets and liabilities.
g) Assumes NYMEX prices on open contracts of $3.00 to $3.25 per mcf and $90.00
per bbl in 2012 and $3.25 to $4.25 per mcf and $90.00 per bbl in 2013.

Oil, NGL and Natural Gas Hedging Activities

Chesapeake enters into oil, NGL and natural gas derivative transactions in
order to mitigate a portion of its exposure to adverse changes in market
prices. Please see the quarterly reports on Form 10-Q and annual reports on
Form 10-K filed by Chesapeake with the Securities and Exchange Commission for
detailed information about derivative instruments the company uses, its
quarter-end derivative positions and the accounting for oil, NGL and natural
gas derivatives.

As of August 6, 2012, the company has the following open natural gas swaps in
place through 2012. The company currently has $212 million of net hedging
losses related to closed natural gas contracts and premiums for call options
for future production periods.

<t*Story too large*
                                                                    Total
                                                        Total       Gains from
                                                        Gains
                                                                    Closed
                                           Open Swap    (Losses)    Trades
                                                        from
                   Avg.       Forecasted   Positions                and
                   NYMEX                                Closed      Premiums
         Open                 Natural      as a % of    Trades
       Swaps    Price of  Gas                                for Call
         (bcf)                             Forecasted   and         Options
                   Open       Production                Premiums
                   Swaps                   Natural                  per mcf of
                              (bcf)        Gas          for Call
                                                        Options     Forecasted
                                           Production
                                                        ($ in       Natural
                                                        millions)   Gas

                                                                    Production
Q3      167      $ 3.02                            $  32     
2012
Q4      204     $ 3.04                         15        
2012
Q2-Q4   371     $ 3.03   584        64    %     $  47     $   0.08
2012
                                                    
Total   0       $ 0.00   1,050      0     %     $  16     $   0.01
2013
Total   0                                  $  (34  )     
2014
Total   0                                  $  (110 )     
2015
Total
2016 –  0                             
2022

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