Chesapeake Energy Corporation Reports Financial and Operational Results for the 2012 Fourth Quarter and Full Year

  Chesapeake Energy Corporation Reports Financial and Operational Results for
  the 2012 Fourth Quarter and Full Year

      Company Reports 2012 Fourth Quarter Net Income Available to Common
    Stockholders of $257 Million, or $0.39 per Share, Adjusted Net Income
  Available to Common Stockholders of $153 Million, or $0.26 per Share, and
           Adjusted Ebitda and Operating Cash Flow of $1.1 Billion

2012 Fourth Quarter Production Totals 362 Bcfe for an Average of 3.9 Bcfe per
Day, an Increase of 9% Year over Year; 2012 Fourth Quarter Liquids Production
        Totals 147,500 Bbls per Day, an Increase of 39% Year over Year

   Company Reports 2012 Year-End Proved Reserves of 15.7 Tcfe; Adds Proved
                         Reserves of 5.0 Tcfe in 2012

Business Wire

OKLAHOMA CITY -- February 21, 2013

Chesapeake Energy Corporation (NYSE:CHK) today announced financial and
operational results for the 2012 fourth quarter and full year. For the 2012
fourth quarter, Chesapeake reported net income available to common
stockholders of $257 million ($0.39 per fully diluted common share), ebitda of
$1.299 billion (defined as net income (loss) before income taxes, interest
expense and depreciation, depletion and amortization), operating cash flow of
$1.146 billion (defined as cash flow from operating activities before changes
in assets and liabilities) and production of 362 billion cubic feet of natural
gas equivalent (bcfe). For the 2012 full year, Chesapeake reported a net loss
available to common stockholders of $940 million, or a loss of $1.46 per fully
diluted common share, ebitda of $1.914 billion, operating cash flow of $4.069
billion and production of 1.422 trillion cubic feet of natural gas equivalent
(tcfe).

The company’s 2012 fourth quarter and full year results include various items
that are generally not included in published estimates of the company’s
financial results by securities analysts. Excluding such items, Chesapeake
reported adjusted net income available to common stockholders of $153 million,
or $0.26 per fully diluted common share, and adjusted ebitda of $1.089 billion
for the 2012 fourth quarter and adjusted net income available to common
stockholders of $285 million, or $0.61 per fully diluted common share, and
adjusted ebitda of $3.754 billion for the 2012 full year. The primary excluded
items from the 2012 fourth quarter and full year reported results are the
following:

  *a noncash after-tax impairment charge of $2.022 billion for the full year
    related to the carrying value of natural gas and oil properties;
  *an after-tax charge of $122 million related to the full repayment of the
    company’s May 2012 term loans for the fourth quarter and full year;
  *net unrealized noncash after-tax mark-to-market gains of $78 million for
    the fourth quarter and $347 million for the full year resulting from the
    company’s natural gas, oil and natural gas liquids (NGL) and interest rate
    hedging programs;
  *net after-tax gains of $166 million for the fourth quarter and $163
    million for the full year related to gains and losses on sales, including
    a $176 million after-tax gain on the sale of the company’s midstream
    subsidiary for the fourth quarter and full year;
  *noncash after-tax charges of $36 million for the fourth quarter and $208
    million for the full year related to the impairment of certain fixed
    assets; and
  *net after-tax gains of $19 million for the fourth quarter and $622 million
    for the full year related to certain investments, including a $629 million
    gain for the full year related to the sale of all of the company’s
    interests in Access Midstream Partners, L.P. (NYSE:ACMP).

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 provided on pages 18 - 21 of this
release.

                             Management Comments

Steven C. Dixon, Chesapeake’s Chief Operating Officer, said, “We continue to
deliver on our liquids growth targets, led by a year-over-year increase of
nearly 40,000 barrels per day in oil production. We achieved this despite the
sale of nearly 18,000 barrels per day of oil production associated with our
exit from the Permian Basin during the 2012 third and fourth quarters. We
believe this performance ranks Chesapeake among the top three organic oil
growth stories in the industry for 2012. I am very proud of what our team has
accomplished thus far and look forward to driving further liquids production
growth and capital efficiencies in 2013.”

Domenic J. Dell’Osso, Jr., Chesapeake’s Chief Financial Officer, added,
“Chesapeake delivered strong results during the 2012 fourth quarter. I am
pleased to reaffirm our 2013 guidance for liquids production growth and
drilling and completion capital expenditures, while at the same time reducing
our cost guidance for many significant categories. Additionally, we are
reaffirming the commitment of management and the Board of Directors to
reducing financial leverage of the company through asset sales. I would also
like to note we have protected a substantial portion of our projected
operating cash flows in 2013 through downside hedge protection on
approximately 85% of our projected oil production at an average price of
$95.45 per barrel and approximately 50% of our projected natural gas
production at an average price of $3.62 per mcf. This equates to approximately
72% of our projected 2013 natural gas, oil and NGL revenue, after
differentials.”

             Key Operational and Financial Statistics Summarized

The table below summarizes Chesapeake’s key results during the 2012 fourth
quarter and compares them to results during the 2012 third quarter and the
2011 fourth quarter and also compares the 2012 full year to the 2011 full
year.

                                                         
                       Three Months Ended                    Full Year Ended
                       12/31/12    9/30/12    12/31/11     12/31/12  12/31/11
    Average daily
    production (in     3,931        4,142       3,596        3,886      3,272
    mmcfe)
    Natural gas
    equivalent         362          381         331          1,422      1,194
    production (in
    bcfe)
    Natural gas
    equivalent         4.23         4.04        5.08         4.02       5.70
    realized price
    ($/mcfe)^(a)
    Oil production     8,936        8,996       5,291        31,265     16,964
    (in mbbls)
    Average
    realized oil       92.23        90.79       88.02        91.74      86.25
    price
    ($/bbl)^(a)
    Oil as % of
    total              15           14          10           13         9
    production
    NGL production     4,634        4,130       4,476        17,615     14,712
    (in mbbls)
    Average
    realized NGL       27.12        31.22       35.87        29.37      38.12
    price
    ($/bbl)^(a)
    NGL as % of
    total              8            7           8            7          7
    production
    Liquids as %
    of total           62           61          37           59         30
    realized
    revenue^(b)
    Liquids as %
    of unhedged        59           63          47           63         40
    revenue^(b)
    Natural gas
    production (in     280          302         272          1,129      1,004
    bcf)
    Average
    realized
    natural gas        2.07         1.97        3.87         2.07       4.77
    price
    ($/mcf)^(a)
    Natural gas as
    % of total         77           79          82           80         84
    production
    Natural gas as
    % of realized      38           39          63           41         70
    revenue
    Natural gas as
    % of unhedged      41           37          53           37         60
    revenue
    Marketing,
    gathering and
    compression        0.11         0.11        0.07         0.08       0.10
    net margin
    ($/mcfe)^(c)
    Oilfield
    services net
    margin             0.05         0.09        0.09         0.10       0.10
    ($/mcfe) ^
    (c)(d)
    Production
    expenses           (0.83    )   (0.84   )   (0.88    )   (0.92  )   (0.90  )
    ($/mcfe)
    Production         (0.13    )   (0.14   )   (0.15    )   (0.13  )   (0.16  )
    taxes ($/mcfe)
    General and
    administrative     (0.23    )   (0.33   )   (0.35    )   (0.33  )   (0.38  )
    costs
    ($/mcfe)^(e)
    Stock-based
    compensation       (0.04    )   (0.05   )   (0.06    )   (0.05  )   (0.08  )
    ($/mcfe)
    DD&A of
    natural gas
    and liquids        (1.80    )   (2.00   )   (1.46    )   (1.76  )   (1.37  )
    properties
    ($/mcfe)
    D&A of other
    assets             (0.20    )   (0.17   )   (0.26    )   (0.21  )   (0.24  )
    ($/mcfe)^(f)
    Interest
    expense            (0.05    )   (0.10   )   (0.04    )   (0.06  )   (0.03  )
    ($/mcfe)^(a)
    Operating cash
    flow ($ in         1,146        1,118       1,311        4,069      5,309
    millions)^(g)
    Operating cash     3.17         2.93        3.96         2.86       4.45
    flow ($/mcfe)
    Adjusted
    ebitda ($ in       1,089        1,021       1,308        3,754      5,406
    millions)^(h)
    Adjusted
    ebitda             3.01         2.68        3.95         2.64       4.53
    ($/mcfe)
    Net income
    (loss) to
    common             257          (2,055  )   429          (940   )   1,570
    stockholders
    ($ in
    millions)
    Earnings
    (loss) per         0.39         (3.19   )   0.63         (1.46  )   2.32
    share –
    diluted ($)
    Adjusted net
    income to
    common             153          35          394          285        1,936
    stockholders
    ($ in
    millions)^(i)
    Adjusted
    earnings per       0.26         0.10        0.58         0.61       2.80
    share –
    diluted ($)
                                                                               
(a) Includes the effects of realized gains (losses) from hedging, but excludes
    the effects of unrealized gains (losses) from hedging.
(b) “Liquids” includes both oil and NGL.
(c) Includes revenue and operating costs and excludes depreciation and
    amortization of other assets.
(d) 2012 fourth quarter and full year include impact of certain consolidated
    investments along with results from Chesapeake Oilfield Services.
(e) Excludes expenses associated with noncash stock-based compensation.
    The decrease from 2011 to 2012 (year over year and quarter over quarter) is
(f) due to assets being classified as held for sale as of June 30, 2012 and not
    subject to depreciation thereafter. The assets were sold as part of the
    midstream sale to ACMP in December 2012.
(g) Defined as cash flow provided by operating activities before changes in
    assets and liabilities.
    Defined as net income (loss) before income taxes, interest expense, and
(h) depreciation, depletion and amortization expense, as adjusted to remove the
    effects of certain items detailed on page 20.
(i) Defined as net income (loss) available to common stockholders, as adjusted
    to remove the effects of certain items detailed on page 21.
    

                          Hedging Positions Detailed

The following table summarizes Chesapeake’s downside hedge position through
swaps and collars on its 2013 natural gas and oil production as of February
20, 2013. The company does not currently have hedges in place for its NGL
production. 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
       % of Forecasted   NYMEX         % of Forecasted   NYMEX
Year                                                  
       Production        Natural Gas   Production        Oil WTI
2013   50%              $3.62         85%              $95.45
                                                         

Details of the company’s year-end hedging positions will be provided in the
company’s Form 10-K filing with the Securities and Exchange Commission (SEC),
and current positions are disclosed in summary format in management’s Outlook
dated February 21, 2013, which is attached to this release as Schedule “A,”
beginning on page 22. The Outlook has been updated from the Outlook dated
November 1, 2012, attached as Schedule “B,” which begins on page 25, to
reflect various updated information.

 2012 Fourth Quarter Average Daily Liquids Production Increases 39% Year over
                                     Year
  and 3% Sequentially to 147,500 Bbls; 2012 Fourth Quarter Average Daily Oil
      Production Increases 69% Year over Year and Was Flat Sequentially
             at 97,100 Bbls, Primarily as a Result of Asset Sales

Chesapeake’s daily production for the 2012 fourth quarter averaged 3.931 bcfe,
an increase of 9% from the average 3.596 bcfe produced per day in the 2011
fourth quarter and a decrease of 5% from the average 4.142 bcfe produced per
day in the 2012 third quarter. The decrease was primarily the result of
selling approximately 0.220 bcfe per day of production associated with the
company’s Permian Basin producing assets in September and October of 2012.
Chesapeake’s average daily production of 3.931 bcfe for the 2012 fourth
quarter consisted of approximately 3.046 billion cubic feet (bcf) of natural
gas (77% on a natural gas equivalent basis) and approximately 147,500 barrels
(bbls) of liquids, consisting of approximately 97,100 bbls of oil (15% on a
natural gas equivalent basis) and approximately 50,400 bbls of NGL (8% on a
natural gas equivalent basis) (oil and NGL collectively referred to as
“liquids”).

For the 2012 fourth quarter, the company’s year-over-year growth rate of
natural gas production was 3%, or approximately 87 million cubic feet (mmcf)
per day, and its year-over-year growth rate of liquids production was 39%, or
approximately 41,300 bbls per day. Chesapeake’s year-over-year liquids
production growth consisted of oil production growth of 69%, or approximately
39,600 bbls per day, and NGL production growth of 4%, or approximately 1,700
bbls per day.

Chesapeake’s daily production for the 2012 full year averaged 3.886 bcfe, a
19% increase from the average 3.272 bcfe produced per day for the 2011 full
year. The company’s average daily production of 3.886 bcfe for the 2012 full
year consisted of approximately 3.084 bcf of natural gas (80% on a natural gas
equivalent basis) and approximately 133,550 bbls of liquids, consisting of
approximately 85,420 bbls of oil (13% on a natural gas equivalent basis) and
approximately 48,130 bbls of NGL (7% on a natural gas equivalent basis).

For the 2012 full year, the company’s year-over-year growth rate of natural
gas production was 12%, or approximately 333 bcf per day, and its
year-over-year growth rate of liquids production was 54%, or approximately
46,770 bbls per day. Chesapeake’s year-over-year liquids production growth
consisted of oil production growth of 84%, or approximately 38,950 bbls per
day, and NGL production growth of 19%, or approximately 7,820 bbls per day.

As a result of completed and planned asset sales and the continued shift in
focus in 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
27% in 2013.

 During 2012, Company Adds New Net Proved Reserves of 5.0 Tcfe, or 840 Mmboe,
through the Drillbit; Total Proved Reserves Decrease 17% to 15.7 Tcfe, or 2.6
 Bboe, Primarily Due to Downward Price-Related Revisions and Net Divestitures

The company's December 31, 2012 estimated proved reserves were 15.690 tcfe, or
2.6 billion barrels of oil equivalent (bboe), a 17% decrease from year-end
2011. Chesapeake added 5.042 tcfe, or 840 million barrels of oil equivalent
(mmboe), of new proved reserves (net of 1.349 tcfe, or 225 mmboe of
nonprice-related revisions) through the drillbit at a drilling and completion
cost of $1.82 per thousand cubic feet of natural gas equivalent (mcfe), or
$10.92 per barrel of oil equivalent (boe), during 2012.

Primarily as a result of lower natural gas prices, the company recorded
downward price-related revisions of 5.414 tcfe, or 902 mmboe, during 2012.
These price revisions were seen primarily with the removal of proved
undeveloped reserves (PUDs) in the company’s Barnett and Haynesville shale
plays. The majority of the downward nonprice-related revisions of 1.349 tcfe
resulted from the continued execution of the company’s strategy to shift its
drilling focus from natural gas to liquids-rich areas and to drill in the
“core of the core” of its acreage positions. As rigs were reallocated, PUDs
were removed from various non-core areas resulting in downward revisions.
Additionally, during 2012, Chesapeake recorded net divestitures of 1.305 tcfe,
or 218 mmboe.

The following table presents Chesapeake’s December 31, 2012 estimated 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
December 31, 2012. Additional information regarding the SEC case can be found
on page 14.

                                                           
                Natural                Proved                    Proved
                Gas                                 PV-10
Pricing        Price       Oil       Reserves                Developed
Method                       Price                  (billions)
                ($/mcf)                 (tcfe)                    Percentage
                             ($/bbl)
Trailing
12-month        $2.76        $94.84     15.7        $17.8         57%
avg
(SEC)^(a)
12/31/12
avg NYMEX       $4.85        $87.90     19.6        $27.9         55%
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 December 31, 2012. This pricing assumption
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.


             Operational Update; Eagle Ford Production Grows 266%
                     Year Over Year and 20% 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
are the nearly exclusive focus of the company’s planned 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
prices and relatively weak U.S. natural gas prices. During 2012, the company
invested approximately 84% of its operated drilling and completion capital
expenditures in liquids-rich plays and projects approximately 86% of such
expenditures will be invested in liquids-rich plays in 2013.

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

Eagle Ford Shale (South Texas):  Chesapeake continues to generate impressive
liquids production growth rates from its 485,000 net acres of leasehold in the
Eagle Ford Shale in South Texas. Net production during the 2012 fourth quarter
averaged 62,500 boe per day (143,200 gross operated boe per day). This
represents an increase of 266% year over year and 20% sequentially.
Approximately 66% of total Eagle Ford production during the 2012 fourth
quarter was oil, 15% was NGL and 19% was natural gas.

As of December 31, 2012, Chesapeake had 534 gross operated producing wells in
the Eagle Ford, of which 405 reached first production in 2012, including 98 in
the fourth quarter. The company is currently operating 17 rigs in the play,
down from a peak of 34 rigs in April 2012, and plans to operate an average of
16 rigs in 2013. Spud-to-spud cycle times have declined dramatically in the
Eagle Ford, from 26 days in the 2011 fourth quarter to only 18 days in the
2012 fourth quarter. Chesapeake plans to drill fewer Eagle Ford wells in 2013
than in 2012; however, the planned number of wells turned-to-sales will be
roughly equal in both years. The company remains on pace to have substantially
all of its core and Tier 1 Eagle Ford acreage held by production by the end of
2013.

Of the 98 wells that commenced first production in the 2012 fourth quarter, 90
wells (or 92%) had peak production rates of more than 500 boe per day,
including 27 wells (or 28%) with peak rates of more than 1,000 boe per day.

Three notable wells completed by Chesapeake in the Eagle Ford during the 2012
fourth quarter are as follows:

  *The Hahn Dew 1H in DeWitt County, TX achieved a peak rate of approximately
    1,985 boe per day, which included 550 bbls of oil, 360 bbls of NGL and 6.4
    mmcf of natural gas per day;
  *The Flat Creek Unit A Dim 2H in Dimmit County, TX achieved a peak rate of
    approximately 1,470 boe per day, which included 1,210 bbls of oil, 160
    bbls of NGL and 0.6 mmcf of natural gas per day; and
  *The JJ Henry IX M 1H in McMullen County, TX achieved a peak rate of
    approximately 1,275 boe per day, which included 1,160 bbls of oil, 55 bbls
    of NGL and 0.4 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 northern Eagle Ford Shale leasehold and
producing assets which are outside its core development area.

Utica Shale (eastern Ohio, Pennsylvania, West Virginia):  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 the industry’s largest position,
approximately 1.0 million net acres of leasehold. As of December 31, 2012,
Chesapeake has drilled a total of 184 wells in the Utica, which includes 45
producing wells, 47 additional wells waiting on pipeline connection and 92
wells in various stages of completion. Chesapeake is currently operating 14
rigs in the Utica and plans to average 14 operated rigs during 2013.
Production growth from the Utica is expected to accelerate during 2013 when
two new third-party natural gas processing complexes will enable the company
to turn a large portion of its well inventory to sales.

Three notable wells completed by Chesapeake in the Utica during the 2012
fourth quarter are as follows:

  *The Houyouse 15-13-5 1H in Carroll County, OH achieved a peak rate of
    approximately 1,730 boe per day, which included 525 bbls of oil, 305 bbls
    of NGL and 5.4 mmcf of natural gas per day;
  *The Cain South 16-12-4 8H in Jefferson County, OH achieved a peak rate of
    approximately 1,540 boe per day, which included 425 bbls of NGL and 6.7
    mmcf of natural gas per day; and
  *The Walters 30-12-5 8H in Carroll County, OH achieved a peak rate of
    approximately 1,140 boe per day, which included 315 bbls of oil, 220 bbls
    of NGL and 3.6 mmcf of natural gas per day.

As of December 31, 2012, the company’s remaining drilling and completion carry
from Total E&P USA, Inc. was approximately $1.15 billion. Chesapeake
anticipates using 100% of the remaining carry by year-end 2014, and the carry
will pay for 60% of Chesapeake’s drilling and completion 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, which spans from northern West Virginia across much of
Pennsylvania into southern New York.

During the 2012 fourth quarter, Chesapeake’s average daily net production in
the northern dry gas portion of the Marcellus was 645 million cubic feet of
natural gas equivalent (mmcfe) per day (1,485 gross operated mmcfe per day),
an increase of 135% year over year and 19% 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 2013.

Three notable wells completed by Chesapeake in the northern dry gas portion of
the Marcellus during the 2012 fourth quarter are as follows:

  *The Holtan 5H in Susquehanna County, PA achieved a peak rate of 12.6 mmcf
    of natural gas per day;
  *The Lopatofsky 2H in Wyoming County, PA achieved a peak rate of 11.4 mmcf
    of natural gas per day; and
  *The Messersmith S Bra 1H in Bradford County, PA achieved a peak rate of
    10.5 mmcf of natural gas per day.

During the 2012 fourth quarter, Chesapeake’s average daily net production in
the southern wet gas portion of the play was approximately 155 mmcfe per day
(260 gross operated mmcfe per day). Management expects production from the
southern Marcellus will remain relatively flat until the ATEX pipeline, which
will carry processed ethane to the Gulf Coast, comes online in late 2013.
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 2013.

Three notable wells completed by Chesapeake in the southern wet gas portion of
the Marcellus during the 2012 fourth quarter are as follows:

  *The Mark Hickman 5H in Ohio County, WV achieved an initial test rate of
    approximately 1,195 boe per day, which included 290 bbls of oil, 305 bbls
    of NGL and 3.6 mmcf of natural gas per day;
  *The Esther Weeks 1H in Ohio County, WV achieved an initial test rate of
    approximately 1,000 boe per day, which included 195 bbls of oil, 265 bbls
    of NGL and 3.3 mmcf of natural gas per day; and
  *The Michael Southworth 8H in Marshall County, WV achieved an initial test
    rate of approximately 955 boe per day, which included 305 bbls of oil, 215
    bbls of NGL and 2.6 mmcf of natural gas per day.

The company is in the process of selling various non-core Marcellus acreage.

Mississippi Lime (northern Oklahoma, southern Kansas): Chesapeake’s
approximate 2.1 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 fourth quarter averaged approximately 32,500
boe per day (41,600 gross operated boe per day), up 208% year over year and
30% sequentially. Approximately 45% of total Mississippi Lime production
during the 2012 fourth quarter was oil, 9% was NGL and 46% was natural gas. As
of December 31, 2012, Chesapeake had 273 producing wells in the Mississippi
Lime play, which included 55 wells that reached first production in the 2012
fourth quarter, compared to 73 in the 2012 third quarter and 49 in the 2012
second quarter. Also, as of December 31, 2012, Chesapeake had approximately 46
wells drilled, but not yet producing, that were in various stages of
completion and/or waiting on pipeline connection. Chesapeake is currently
operating eight rigs in the Mississippi Lime and anticipates maintaining that
level of activity for the remainder of 2013.

Three notable wells completed by Chesapeake in the Mississippi Lime during the
2012 fourth quarter are as follows:

  *The Mike 2-28-15 1H in Woods County, OK achieved a peak rate of
    approximately 2,820 boe per day, which included 2,345 bbls of oil, 100
    bbls of NGL and 2.3 mmcf of natural gas per day;
  *The Roper 1-28-15 1H in Woods County, OK achieved a peak rate of
    approximately 1,985 boe per day, which included 1,645 bbls of oil, 70 bbls
    of NGL and 1.6 mmcf of natural gas per day; and
  *The Thorp 4-24-10 1H in Alfalfa County, OK achieved a peak rate of
    approximately 1,365 boe per day, which included 465 bbls of oil, 215 bbls
    of NGL and 4.1 mmcf of natural gas per day.

     2012 Fourth Quarter and Full Year Financial and Operational Results
                         Conference Call Information

A conference call to discuss this release has been scheduled for Thursday,
February 21, 2013 at 9:00 am EST. The telephone number to access the
conference call is 913-981-5550 or toll-free 800-289-0508. The passcode for
the call is 8878841. We encourage those who would like to participate in the
call to place calls between 8:50 and 9:00 am EST. For those unable to
participate in the conference call, a replay will be available for audio
playback at 1:00 pm EST on Thursday, February 21, 2013 and will run through
midnight Thursday, March 7, 2013. The number to access the conference call
replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay
is 8878841. 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 liquids reserves, projected production, estimates of
operating costs, planned development drilling and use of joint venture
drilling carries, 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 and regulatory investigations. We do not
have binding agreements for all of our planned 2013 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 and reduce our
indebtedness as planned 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 11 producer of oil and natural gas liquids and the most
active driller of new wells in the U.S. Headquartered in Oklahoma City, the
company's operations are focused on discovering and developing unconventional
natural gas and oil fields onshore in the U.S. Chesapeake owns leading
positions in the Eagle Ford, Utica, Granite Wash, Cleveland, Tonkawa,
Mississippi Lime and Niobrara unconventional liquids plays and in the
Marcellus, Haynesville/Bossier and Barnett unconventional natural gas shale
plays. The company has also vertically integrated its operations and owns
substantial marketing and oilfield services businesses through its
subsidiaries Chesapeake Energy Marketing, Inc. and Chesapeake Oilfield
Operating, 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)
                                                                             
                                                    
                                 December 31,            December 31,
THREE MONTHS ENDED:             2012                  2011
                                 $          $/mcfe      $          $/mcfe
REVENUES:                                                           
Natural gas, oil and NGL           1,657       4.58        1,336       4.03
Marketing, gathering and           1,721       4.76        1,246       3.77
compression
Oilfield services                 161        0.45       145        0.44
Total Revenues                    3,539      9.79       2,727      8.24
                                                                             
OPERATING EXPENSES:
Natural gas, oil and NGL           299         0.83        292         0.88
production
Production taxes                   47          0.13        51          0.15
Marketing, gathering and           1,681       4.65        1,223       3.70
compression
Oilfield services                  145         0.40        115         0.35
General and administrative         99          0.27        138         0.42
Employee retirement expense        3           0.01        —           —
and other termination benefits
Natural gas, oil and NGL
depreciation, depletion and        651         1.80        484         1.46

amortization
Depreciation and amortization      71          0.20        85          0.26
of other assets
Net gains on sales of fixed        (272  )     (0.75 )     (439  )     (1.33 )
assets
Impairments of fixed assets       59         0.16       42         0.13
and other
Total Operating Expenses          2,783      7.70       1,991      6.02
                                                                             
INCOME (LOSS) FROM OPERATIONS     756        2.09       736        2.22
                                                                             
OTHER INCOME (EXPENSE):
Interest expense                   (14   )     (0.04 )     (7    )     (0.02 )
Earnings (losses) on               (16   )     (0.04 )     56          0.17
investments
Gain on sale of investment         31          0.09        —           —
Losses on purchases of debt        (200  )     (0.55 )     —           —
Other income                      6          0.01       14         0.04
Total Other Income (Expense)      (193  )    (0.53 )    63         0.19
                                                                             
INCOME (LOSS) BEFORE INCOME        563         1.56        799         2.41
TAXES
                                                                             
INCOME TAX EXPENSE (BENEFIT):
Current income taxes               23          0.06        2           —
Deferred income taxes             196        0.55       310        0.94
Total Income Tax Expense          219        0.61       312        0.94
(Benefit)
                                                                             
NET INCOME (LOSS)                  344         0.95        487         1.47
                                                                             
Net income attributable to        (44   )    (0.12 )    (15   )    (0.04 )
noncontrolling interests
                                                                             
NET INCOME (LOSS) ATTRIBUTABLE    300        0.83       472        1.43
TO CHESAPEAKE
                                                                             
Preferred stock dividends         (43   )    (0.12 )    (43   )    (0.13 )
                                                                             
NET INCOME (LOSS) AVAILABLE TO    257        0.71       429        1.30
COMMON STOCKHOLDERS
                                                                             
EARNINGS (LOSS) PER COMMON
SHARE:
Basic                            $ 0.39                  $ 0.67
                                                                             
Diluted                          $ 0.39                  $ 0.63
                                                                             
WEIGHTED AVERAGE COMMON AND
COMMON

EQUIVALENT SHARES OUTSTANDING
(in millions):
Basic                             644                    640
                                                                             
Diluted                           648                    750

                                                     
CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)
                                                                             
                                                   
                               December 31,             December 31,
TWELVE MONTHS ENDED:          2012                   2011
                               $           $/mcfe      $           $/mcfe
REVENUES:                                                           
Natural gas, oil and NGL         6,278        4.42        6,024        5.04
Marketing, gathering and         5,431        3.81        5,090        4.26
compression
Oilfield services               607         0.43       521         0.44
Total Revenues                  12,316      8.66       11,635      9.74
                                                                             
OPERATING EXPENSES:
Natural gas, oil and NGL         1,304        0.92        1,073        0.90
production
Production taxes                 188          0.13        192          0.16
Marketing, gathering and         5,312        3.73        4,967        4.16
compression
Oilfield services                465          0.33        402          0.34
General and administrative       535          0.38        548          0.46
Employee retirement expense
and other termination            7            0.01        —            —
benefits
Natural gas, oil and NGL
depreciation, depletion and      2,507        1.76        1,632        1.37
amortization
Depreciation and                 304          0.21        291          0.24
amortization of other assets
Impairment of natural gas        3,315        2.33        —            —
and oil properties
Net gains on sales of fixed      (267   )     (0.18 )     (437   )     (0.37 )
assets
Impairments of fixed assets     340         0.24       46          0.03
and other
Total Operating Expenses        14,010      9.86       8,714       7.29
                                                                             
INCOME (LOSS) FROM              (1,694 )    (1.20 )    2,921       2.45
OPERATIONS
                                                                             
OTHER INCOME (EXPENSE):
Interest expense                 (77    )     (0.05 )     (44    )     (0.04 )
Earnings (losses) on             (103   )     (0.08 )     156          0.13
investments
Gain on sales of investments     1,092        0.77        —            —
Losses on purchases of debt      (200   )     (0.14 )     (176   )     (0.15 )
Other income                    8           0.01       23          0.02
Total Other Income (Expense)    720         0.51       (41    )    (0.04 )
                                                                             
INCOME (LOSS) BEFORE INCOME      (974   )     (0.69 )     2,880        2.41
TAXES
                                                                             
INCOME TAX EXPENSE
(BENEFIT):
Current income taxes             47           0.03        13           0.01
Deferred income taxes           (427   )    (0.30 )    1,110       0.93
Total Income Tax Expense        (380   )    (0.27 )    1,123       0.94
(Benefit)
                                                                             
NET INCOME (LOSS)                (594   )     (0.42 )     1,757        1.47
                                                                             
Net income attributable to      (175   )    (0.12 )    (15    )    (0.01 )
noncontrolling interests
                                                                             
NET INCOME (LOSS)               (769   )    (0.54 )    1,742       1.46
ATTRIBUTABLE TO CHESAPEAKE
                                                                             
Preferred stock dividends       (171   )    (0.12 )    (172   )    (0.15 )
                                                                             
NET INCOME (LOSS) AVAILABLE     (940   )    (0.66 )    1,570       1.31
TO COMMON STOCKHOLDERS
                                                                             
EARNINGS (LOSS) PER COMMON
SHARE:
Basic                          $ (1.46  )               $ 2.47
                                                                             
Diluted                        $ (1.46  )               $ 2.32
                                                                             
WEIGHTED AVERAGE COMMON AND
COMMON EQUIVALENT SHARES
OUTSTANDING (in millions):
Basic                           643                     637
                                                                             
Diluted                         643                     752

                                                       
CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)
                                                           
                                                      
                                          December 31,     December 31,
                                        2012           2011
                                                               
Cash and cash equivalents                 $   287          $   351
Other current assets                         2,661           2,826
Total Current Assets                         2,948           3,177
                                                               
Property and equipment (net)                  37,167           36,739
Other assets                                 1,496           1,919
Total Assets                              $   41,611       $   41,835
                                                               
Current liabilities                       $   6,266        $   7,082
Long-term debt, net of discounts              12,157           10,626
Other long-term liabilities                   2,485            2,682
Deferred income tax liabilities              2,807           3,484
Total Liabilities                            23,715          23,874
                                                               
Chesapeake stockholders' equity               15,569           16,624
Noncontrolling interests                     2,327           1,337
Total Equity                                 17,896          17,961
                                                               
Total Liabilities and Equity              $   41,611       $   41,835
                                                               
Common Shares Outstanding (in millions)      664             659

                                                             
CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

($ in millions)

(unaudited)
                                                            
                                                 December 31,   December 31,
                                               2012          2011
                                                                
Total debt, net of unrestricted cash               $ 12,333      $  10,275
Chesapeake stockholders' equity                       15,569          16,624
Noncontrolling interests^(a)                         2,327          1,337
Total                                               $ 30,229       $  28,236
                                                                      
Debt to capitalization ratio                          41%             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                         356             380
Other                                                6              7
Total                                               $ 2,327        $  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 DECEMBER 31,
2012

($ in millions, except per-unit data)

(unaudited)
                                         
                                         Proved Reserves
                                           Cost        Bcfe^(a)       $/Mcfe
PROVED PROPERTIES:                                                     
Well costs on proved properties^(b)(c)     $ 9,168        5,042  ^(d)     1.82
Acquisition of proved properties^(e)         332          42              7.91
Sale of proved properties                   (2,462 )    (1,347 )        1.83
Total net proved properties                 7,038       3,737           1.88
                                                                          
Revisions – price                            —            (5,414 )        —
                                                                          
UNPROVED PROPERTIES:
Well costs on unproved properties^(f)        (337   )     —               —
Acquisition of unproved properties,          1,718        —               —
net^(g)
Acquisition of minerals                      68           —               —
Sale of unproved properties                 (3,146 )    —               —
Total net unproved properties               (1,697 )    —               —
                                                                          
OTHER:
Capitalized interest on unproved             976          —               —
properties
Geological and geophysical costs             170          —               —
Asset retirement obligations                32          —               —
Total other                                 1,178       —               —
                                                                          
Total                                      $ 6,519       (1,677 )        —

                                      
CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

TWELVE MONTHS ENDED DECEMBER 31, 2012

BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AS OF DECEMBER 31,
2012

(unaudited)
                                                                   
                                              Bcfe^(a)              
                                                                      
Beginning balance, January 1, 2012              18,789
Production                                      (1,422                )
Acquisitions                                    42
Divestitures                                    (1,347                )
Revisions – changes to previous                 (1,349                )
estimates
Revisions – price                               (5,414                )
Extensions and discoveries                      6,391
Ending balance, December 31, 2012               15,690
                                                                      
Proved reserves decline rate before             10                    %
acquisitions and divestitures
Proved reserves decline rate after              17                    %
acquisitions and divestitures
                                                                      
Proved developed reserves                       8,944
Proved developed reserves percentage            57                    %
                                                                      
PV-10 ($ in billions)^(a)                       $         17.8
                                                                      
(a) Reserve volumes and PV-10 value estimated using SEC reserve recognition
standards and pricing assumptions based on the trailing 12-month average
first-day-of-the-month prices as of December 31, 2012 of $2.76 per mcf of
natural gas and $94.84 per bbl of oil, before field differential adjustments.

(b) Net of well cost carries of $784 million associated with the
Statoil-Marcellus, CNOOC-Eagle Ford, CNOOC-Niobrara and Total-Utica joint
ventures.

(c) Includes $1.389 billion of well costs incurred in prior quarters
(previously classified as well costs on unproved properties) related to wells
that were evaluated for the existence of proved reserves in the current
quarter.

(d) Includes 1.349 tcfe of downward revisions resulting from changes to
previous estimates and excludes downward revisions of 5.414 tcfe primarily
resulting from lower natural gas prices using the average
first-day-of-the-month price for the twelve months ended December 31, 2012,
compared to the twelve months ended December 31, 2011.

(e) Includes 28 bcfe of proved reserves associated with the company’s Permian
Basin volumetric production payment repurchased by the company for $313
million and subsequently resold to multiple parties in September and October
2012.

(f) Includes $1.052 million of well costs on unproved properties incurred in
the current year, offset by the transfer of $1.389 billion previously
classified as well costs on unproved properties that were evaluated for the
existence of proved reserves in the current quarter. See footnote (c).

(g) Net of joint venture partner reimbursements.

                                                              
CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF PV-10

($ in millions)

(unaudited)
                                                             
                                                 December 31,     December 31,
                                               2012           2011
                                                                  
Standardized measure of discounted future net    $   14,666       $   15,630
cash flows
                                                                      
Discounted future cash flows for income taxes       3,107           4,247
                                                                      
Discounted future net cash flows before income   $   17,773       $   19,877
taxes (PV-10)
                                                                      

PV-10 is discounted (at 10% per year) future net cash flows before income
taxes. The standardized measure of discounted future net cash flows includes
the effects of estimated future income tax expenses and is calculated in
accordance with Accounting Standards Topic 932. Management uses PV-10 as one
measure of the value of the company's current proved reserves and to compare
relative values among peer companies without regard to income taxes. The
company also understands that securities analysts and rating agencies use this
measure in similar ways. While PV-10 is based on prices, costs and discount
factors which are consistent from company to company, the standardized measure
is dependent on the unique tax situation of each individual company.

The company’s PV-10 and standardized measure were calculated using trailing
12-month average first-day-of-the-month prices. As of December 31, 2012 and
2011, the prices used were $2.76 per mcf and $94.84 per bbl and $4.12 per mcf
and $95.97 per bbl, respectively, before field differential adjustments.

                                                      
CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA – NATURAL GAS, OIL AND NGL SALES AND INTEREST EXPENSE

(unaudited)
                                                                             
                                                    
                                 Three Months Ended      Twelve Months Ended
                                 December 31,            December 31,
                                 2012       2011        2012       2011
Natural Gas, Oil and NGL Sales
($ in millions):
Natural gas sales                $ 645       $ 720       $ 2,004     $ 3,133
Natural gas derivatives –          (63   )     335         328         1,656
realized gains (losses)
Natural gas derivatives –         70         24         (331  )    (669  )
unrealized gains (losses)
                                                                             
Total Natural Gas Sales           652        1,079      2,001      4,120
                                                                             
Oil sales                          790         475         2,829       1,523
Oil derivatives – realized         34          (10   )     39          (60   )
gains (losses)
Oil derivatives – unrealized      54         (375  )    857        (128  )
gains (losses)
                                                                             
Total Oil Sales                   878        90         3,725      1,335
                                                                             
NGL sales                          126         171         526         603
NGL derivatives – realized         —           (10   )     (9    )     (42   )
gains (losses)
NGL derivatives – unrealized      1          6          35         8
gains (losses)
                                                                             
Total NGL Sales                   127        167        552        569
                                                                             
Total Natural Gas, Oil and NGL   $ 1,657     $ 1,336     $ 6,278     $ 6,024
Sales
                                                                             
Average Sales Price –

excluding gains (losses) on
derivatives:
Natural gas ($ per mcf)          $ 2.30      $ 2.64      $ 1.77      $ 3.12
Oil ($ per bbl)                  $ 88.44     $ 89.85     $ 90.49     $ 89.80
NGL ($ per bbl)                  $ 27.20     $ 38.19     $ 29.89     $ 40.96
Natural gas equivalent ($ per    $ 4.32      $ 4.13      $ 3.77      $ 4.40
mcfe)
                                                                             
Average Sales Price –

excluding unrealized gains
(losses) on derivatives:
Natural gas ($ per mcf)          $ 2.07      $ 3.87      $ 2.07      $ 4.77
Oil ($ per bbl)                  $ 92.23     $ 88.02     $ 91.74     $ 86.25
NGL ($ per bbl)                  $ 27.12     $ 35.87     $ 29.37     $ 38.12
Natural gas equivalent ($ per    $ 4.23      $ 5.08      $ 4.02      $ 5.70
mcfe)
                                                                             
Interest Expense (Income) ($
in millions):
Interest^(a)                     $ 17        $ 11        $ 84        $ 30
Derivatives – realized (gains)     —           1           (1    )     7
losses
Derivatives – unrealized          (3    )    (5    )    (6    )    7
(gains) losses
Total Interest Expense           $ 14        $ 7         $ 77        $ 44
                                                                             
(a) Net of amounts capitalized.

                                                          
CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

($ in millions)

(unaudited)
                                                                      
THREE MONTHS ENDED:                      December 31,         December 31,
                                        2012                 2011
                                                                            
Beginning cash                           $     142            $    111
                                                                            
Cash provided by operating                    864                2,179
activities
                                                                            
Cash flows from investing
activities:
Well costs on proved and unproved              (1,377   )          (2,080   )
properties
Acquisition of proved and unproved             (295     )          (1,163   )
properties^(a)
Sale of proved and unproved                    3,386               1,257
properties
Geological and geophysical costs               (28      )          (42      )
Additions to other property and                (719     )          (593     )
equipment
Proceeds from sales of other assets            2,273               630
Additions to investments                       (145     )          (25      )
Other                                         79                 (81      )
Total cash provided by (used in)              3,174              (2,097   )
investing activities
                                                                            
Cash provided by (used in) financing          (3,907   )         158
activities
                                                                            
Change in cash and cash equivalents
classified in current assets held             14                 —
for sale
                                                                            
Ending cash                              $     287            $    351
                                                                            
                                                                    
TWELVE MONTHS ENDED:                     December 31,         December 31,
                                        2012                 2011
                                                                            
Beginning cash                           $     351            $    102
                                                                            
Cash provided by operating                    2,841              5,903
activities
                                                                            
Cash flows from investing
activities:
Well costs on proved and unproved              (8,737   )          (7,257   )
properties
Acquisition of proved and unproved             (2,890   )          (4,463   )
properties^(b)
Sale of proved and unproved                    5,613               7,140
properties
Geological and geophysical costs               (193     )          (210     )
Additions to other property and                (2,635   )          (2,009   )
equipment
Proceeds from sales of other assets            2,492               1,312
Acquisition of drilling company                —                   (339     )
Proceeds from (additions to)                   (406     )          101
investments
Proceeds from sale of midstream                2,000               —
investment
Other                                         (224     )         (87      )
Total cash used in investing                  (4,980   )         (5,812   )
activities
                                                                            
Cash provided by financing                    2,075              158
activities
                                                                            
                                                                            
Ending cash                              $     287            $    351
                                                                            
(a) Includes capitalized interest of $153 million and $152 million for the
current quarter and the prior quarter, respectively.

(b) Includes capitalized interest of $776 million and $630 million for the
current period and the prior period, respectively.

                                                             
CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)
                                                                            
                      December 31,           September 30,        December
                                                                  31,
THREE MONTHS         2012                 2012               2011
ENDED:
                                                                            
CASH PROVIDED BY
OPERATING             $     864              $     949            $  2,179
ACTIVITIES
                                                                            
Changes in assets          282                   169              (868   )
and liabilities
                                                                            
OPERATING CASH        $     1,146            $     1,118          $  1,311
FLOW^(a)
                                                                            
                                                          
                      December 31,           September 30,        December
                                                                  31,
THREE MONTHS         2012                 2012               2011
ENDED:
                                                                            
NET INCOME (LOSS)     $     344              $     (1,971   )     $  487
                                                                            
Income tax                  219                    (1,260   )        312
expense (benefit)
Interest expense            14                     36                7
Depreciation and
amortization of             71                     66                85
other assets
Natural gas, oil
and NGL
depreciation,              651                   762              484
depletion and
amortization
                                                                            
EBITDA^(b)            $     1,299            $     (2,367   )     $  1,375
                                                                            
                                                                            
                                                          
                      December 31,           September 30,        December
                                                                  31,
THREE MONTHS         2012                 2012               2011
ENDED:
                                                                            
CASH PROVIDED BY
OPERATING             $     864              $     949            $  2,179
ACTIVITIES
                                                                            
Changes in assets           282                    169               (868   )
and liabilities
Interest expense            14                     36                7
Unrealized gains
(losses) on
natural gas, oil            125                    (104     )        (345   )
and NGL
derivatives
Impairment of
natural gas and             —                      (3,315   )        —
oil properties
Net gains
(losses) on sales           272                    (7       )        439
of fixed assets
Impairments of
fixed assets and            (59      )             (14      )        (42    )
other
Gains (losses) on           (2       )             4                 22
investments
Stock-based                 (27      )             (30      )        (34    )
compensation
Losses on                   (200     )             —                 —
purchases of debt
Other items                30                    (55      )       17
                                                                            
EBITDA^(b)            $     1,299            $     (2,367   )     $  1,375
                                                                            
(a) Operating cash flow represents net cash provided by operating activities
before changes in assets and liabilities. Operating cash flow is presented
because management believes it is a useful adjunct to net cash provided by
operating activities under accounting principles generally accepted in the
United States (GAAP). Operating cash flow is widely accepted as a financial
indicator of a natural gas and oil company's ability to generate cash which is
used to internally fund exploration and development activities and to service
debt. This measure is widely used by investors and rating agencies in the
valuation, comparison, rating and investment recommendations of companies
within the natural gas and oil exploration and production industry. Operating
cash flow is not a measure of financial performance under GAAP and should not
be considered as an alternative to cash flows from operating, investing or
financing activities as an indicator of cash flows, or as a measure of
liquidity.

(b) Ebitda represents net income (loss) before income tax expense, interest
expense and depreciation, depletion and amortization expense. Ebitda is
presented as a supplemental financial measurement in the evaluation of our
business. We believe that it provides additional information regarding our
ability to meet our future debt service, capital expenditures and working
capital requirements. This measure is widely used by investors and rating
agencies in the valuation, comparison, rating and investment recommendations
of companies. Ebitda is also a financial measurement that, with certain
negotiated adjustments, is reported to our lenders pursuant to our bank credit
agreements and is used in the financial covenants in our bank credit
agreements. 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)
                                                                          
                                                    
                              December 31,              December 31,
TWELVE MONTHS ENDED:         2012                     2011
                                                                          
CASH PROVIDED BY              $       2,841             $      5,903
OPERATING ACTIVITIES
                                                                          
Changes in assets and                1,228                   (594       )
liabilities
                                                                          
OPERATING CASH FLOW^(a)       $       4,069             $      5,309
                                                                          
                                                         
                              December 31,              December 31,
TWELVE MONTHS ENDED:         2012                     2011
                                                                          
NET INCOME (LOSS)             $       (594        )     $      1,757
                                                                          
Income tax expense                    (380        )            1,123
(benefit)
Interest expense                      77                       44
Depreciation and
amortization of other                 304                      291
assets
Natural gas, oil and
NGL depreciation,                    2,507                   1,632
depletion and
amortization
                                                                          
EBITDA^(b)                    $       1,914             $      4,847
                                                                          
                                                         
                              December 31,              December 31,
TWELVE MONTHS ENDED:         2012                     2011
                                                                          
CASH PROVIDED BY              $       2,841             $      5,903
OPERATING ACTIVITIES
                                                                          
Changes in assets and                 1,228                    (594       )
liabilities
Interest expense                      77                       44
Unrealized gains
(losses) on natural                   561                      (789       )
gas, oil and NGL
derivatives
Impairment of natural                 (3,315      )            —
gas and oil properties
Net gains on sales of                 267                      437
fixed assets
Impairments of fixed                  (316        )            (46)
assets and other
Gains (losses) on                     (180        )            41
investments
Stock-based                           (120        )            (153       )
compensation
Gains on sales of                     1,092                    —
investments
Losses on purchases of                (200        )            (5)
debt
Other items                          (21         )           9
                                                                          
EBITDA^(b)                    $       1,914             $      4,847
                                                                          
(a)Operating cash flow represents net cash provided by operating activities
before changes in assets and liabilities. Operating cash flow is presented
because management believes it is a useful adjunct to net cash provided by
operating activities under accounting principles generally accepted in the
United States (GAAP). Operating cash flow is widely accepted as a financial
indicator of a natural gas and oil company's ability to generate cash which is
used to internally fund exploration and development activities and to service
debt. This measure is widely used by investors and rating agencies in the
valuation, comparison, rating and investment recommendations of companies
within the natural gas and oil exploration and production industry. Operating
cash flow is not a measure of financial performance under GAAP and should not
be considered as an alternative to cash flows from operating, investing or
financing activities as an indicator of cash flows, or as a measure of
liquidity.

(b)Ebitda represents net income (loss) before income tax expense, interest
expense and depreciation, depletion and amortization expense. Ebitda is
presented as a supplemental financial measurement in the evaluation of our
business. We believe that it provides additional information regarding our
ability to meet our future debt service, capital expenditures and working
capital requirements. This measure is widely used by investors and rating
agencies in the valuation, comparison, rating and investment recommendations
of companies. Ebitda is also a financial measurement that, with certain
negotiated adjustments, is reported to our lenders pursuant to our bank credit
agreements and is used in the financial covenants in our bank credit
agreements. 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)
                                                                            
                                                         
                       December 31,         September 30,        December
                                                                 31,
THREE MONTHS          2012               2012               2011
ENDED:
                                                                            
EBITDA                 $    1,299           $   (2,367     )     $   1,375
                                                                            
Adjustments:
Unrealized (gains)
losses on natural           (125      )         104                  345
gas, oil and NGL
derivatives
Impairment of
natural gas and             —                   3,315                —
oil properties
Net (gains) losses
on sales of fixed           (272      )         7                    (439   )
assets
Impairments of
fixed assets and            59                  38                   42
other
Net income
attributable to             (44       )         (41        )         (15    )
noncontrolling
interests
Gains on sales of           (31       )         (31        )         —
investments
Losses on                   200                 —                    —
purchases of debt
Other                      3                  (4         )        —
                                                                            
Adjusted               $    1,089           $   1,021            $   1,308
EBITDA^(a)
                                                                            
                                                          
                                  December 31,        December 31,
TWELVE MONTHS ENDED:              2012               2011
                                                                            
EBITDA                             $  1,914             $  4,847
                                                                            
Adjustments:
Unrealized (gains) losses on
natural gas, oil and NGL              (561        )        789
derivatives
Impairment of natural gas and         3,315                —
oil properties
Net gains on sales of fixed           (267        )        (437             )
assets
Impairments of fixed assets and       340                  46
other
Net income attributable to            (175        )        (15              )
noncontrolling interests
Losses on purchases of debt           200                  176
(Gains) on investments                (1,019      )        —
Other                                7                   —
                                                                            
Adjusted EBITDA^(a)                $  3,754             $  5,406
                                                                            
(a) Adjusted ebitda excludes certain items that management believes affect the
comparability of operating results. The company believes these non-GAAP
financial measures are a useful adjunct to ebitda because:

(i) Management uses adjusted ebitda to evaluate the company's operational
trends and performance relative to other natural gas and oil producing
companies.

(ii) Adjusted ebitda is more comparable to estimates provided by securities
analysts.

(iii) Items excluded generally are one-time items or items whose timing or
amount cannot be reasonably estimated. Accordingly, any guidance provided by
the company generally excludes information regarding these types of items.

                                                            
CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS

($ in millions, except per-share data)

(unaudited)

                                                         
                        December 31,        September 30,        December
                                                                 31,
THREE MONTHS ENDED:    2012              2012               2011
                                                                            
Net income (loss)
available to common     $    257            $   (2,055     )     $   429
stockholders
                                                                            
Adjustments, net of
tax:
Unrealized (gains)
losses on                    (78      )         63                   207
derivatives
Impairment of
natural gas and oil          —                  2,022                —
properties
Net (gains) losses
on sales of fixed            (166     )         4                    (268   )
assets
Impairments of
fixed assets and             36                 23                   26
other
Gains on sales of            (19      )         (19        )         —
investments
Losses on purchases
or exchanges of              122                —                    —
debt
Other                       1                 (3         )        —
                                                                            
Adjusted net income
available to common          153                35                   394

stockholders^(a)
Preferred stock             43                43                  43
dividends
Total adjusted net      $    196            $   78               $   437
income
                                                                            
Weighted average
fully diluted                754                754                  750
shares
outstanding^(b)
                                                                            
Adjusted earnings
per share assuming      $    0.26           $   0.10             $   0.58
dilution^(a)
                                                                            
                                                          
                                  December 31,        December 31,
TWELVE MONTHS ENDED:              2012               2011
                                                                            
Net income (loss) available to     $  (940        )     $  1,570
common stockholders
                                                                            
Adjustments, net of tax:
Unrealized (gains) losses on          (347        )        486
derivatives
Impairment of natural gas and         2,022                —
oil properties
Net gains on sales of fixed           (163        )        (266             )
assets
Impairments of fixed assets and       208                  28
other
Losses on purchases or                122                  107
exchanges of debt
Loss on foreign currency              —                    11
derivatives
Gains on investments                  (622        )        —
Other                                5                   —
                                                                            
Adjusted net income available         285                  1,936
to common stockholders^(a)
Preferred stock dividends            171                 172
Total adjusted net income          $  456               $  2,108
                                                                            
Weighted average fully diluted        755                  752
shares outstanding^(b)
                                                                            
Adjusted earnings per share        $  0.61              $  2.80
assuming dilution^(a)
                                                                            
(a) Adjusted net income available to common stockholders and adjusted earnings
per share assuming dilution exclude certain items that management believes
affect the comparability of operating results. The company believes these
non-GAAP financial measures are a useful adjunct to GAAP earnings because:

(i) Management uses adjusted net income available to common stockholders to
evaluate the company's operational trends and performance relative to other
natural gas and oil producing companies.

(ii) Adjusted net income available to common stockholders is more comparable
to earnings estimates provided by securities analysts.

(iii) Items excluded generally are one-time items or items whose timing or
amount cannot be reasonably estimated. Accordingly, any guidance provided by
the company generally excludes information regarding these types of items.

(b) Weighted average fully diluted shares outstanding include shares that were
considered antidilutive for calculating earnings per share in accordance with
GAAP.

                                                          
SCHEDULE “A”
MANAGEMENT’S OUTLOOK AS OF FEBRUARY 21, 2013

Chesapeake periodically provides management guidance on certain factors that
affect its future financial performance. The primary changes from the
company’s November 1, 2012 Outlook are in italicized bold and reflect
estimated future production decreases of approximately 35 bcfe in 2013
associated with the company’s planned asset sales.

Chesapeake Energy Corporation Consolidated Projections
                                                                 
                                                                 Year Ending

                                                                 12/31/13
Estimated Production:
Natural gas – bcf                                                1,030 – 1,070
Oil – mbbls                                                      36,000 –
                                                                 38,000
NGL – mbbls^(a)                                                  24,000 –
                                                                 26,000
Natural gas equivalent – bcfe                                    1,390 – 1,454
                                                                 
Daily natural gas equivalent midpoint – mmcfe                    3,895
                                                                 
YOY estimated production increase (adjusted                      0%
for planned asset sales)
                                                                 
NYMEX Price^(b) (for calculation of realized
hedging effects only):
Natural gas - $/mcf                                              $3.67
Oil - $/bbl                                                      $95.00
                                                                 
Estimated Realized Hedging Effects (based on
assumed NYMEX prices above):
Natural gas - $/mcf                                              ($0.05)
Oil - $/bbl                                                      $0.30
                                                                 
Estimated Gathering/Marketing/Transportation
Differentials to NYMEX Prices:
Natural gas - $/mcf                                              $1.15 – 1.25
Oil - $/bbl                                                      $0.00 – 2.00
NGL - $/bbl                                                      $66.00 –
                                                                 70.00
                                                                 
Operating Costs per Mcfe of Projected
Production:
Production expense                                               $0.90 – 0.95
Production taxes                                                 $0.20 – 0.25
General and administrative^(c)                                   $0.34 – 0.39
Stock-based compensation (noncash)                               $0.04 – 0.06
DD&A of natural gas and liquids assets                           $1.65 – 1.85
Depreciation of other assets                                     $0.25 – 0.30
Interest expense^(d)                                             $0.05 – 0.10
                                                                 
Other ($ millions):
Marketing, gathering and compression net                         $90 – 100
margin^(e)
Oilfield services net margin^(e)                                 $175 – 225
Net income attributable to noncontrolling                        ($180) –
interests and other^(f)                                          (220)
                                                                 
Book Tax Rate                                                    39%

Weighted average shares outstanding (in
millions):
Basic                                                            645 – 650
Diluted                                                          758 – 763
                                                                 
Operating cash flow before changes in assets                     $4,850 –
and liabilities^(g)(h)                                           5,150
Well costs on proved and unproved properties                     ($5,750 –
                                                                 6,250)
Acquisition of unproved properties, net                          ($400)
                                                                 
a) Assumes no ethane rejection.
b) NYMEX natural gas and oil prices have been updated for actual contract
prices through February and January, respectively.
c) Excludes expenses associated with noncash stock-based compensation.
d) Does not include unrealized gains or losses on interest rate derivatives.
e) Includes revenue and operating costs and excludes depreciation and
amortization of other assets.
f) Net income attributable to noncontrolling interests of Chesapeake Granite
Wash Trust, CHK Utica, L.L.C. and CHK Cleveland Tonkawa, L.L.C.
g) 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.
h) Assumes NYMEX prices on open contracts of $3.50 to $4.00 per mcf and $95.00
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 February 21, 2013, 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
                                                                                     Gains
                                                                       Total
                                                                       Gains         (Losses)
                                                      Open Swap                      from
                                                                       (Losses)
                                                      Positions        from          Closed
                          Avg.         Forecasted     as                             Trades
            Open          NYMEX                                        Closed
                                       Natural        a % of           Trades        and
        Swaps     Price     Gas                                    Premiums
                          of                          Forecasted       and
            (bcf)                      Production                      Premiums      for Call
                          Open                        Natural                        Options
                          Swaps        (bcf)          Gas              for Call
                                                                       Options       per mcf of
                                                      Production
                                                                       ($ in         Forecasted
                                                                       millions)     Natural
                                                                                     Gas

                                                                                     Production
                                                                                     
Q1          53          $ 3.72                                       $ (9    )
2013
Q2          137           3.66                                         11
2013
Q3          141           3.59                                         7
2013
Q4       141      3.59                             (3    )    
2013
Total    472     $ 3.63     1,050        45%         $ 6        $ 0.00
2013
Total    0        -                               $ (74   )    
2014
Total    0        -                               $ (131  )    
2015
Total
2016     0        -                               $ (187  )    
–
2022
                                                                                     

The company currently has the following purchased natural gas three-way
collars in place:

                                                               
                                                                            Open
                                                                            Collars as
                                   Avg.                      Forecasted
          Open        Avg.         NYMEX        Avg.                        a % of
                      NYMEX                     NYMEX        Natural
       Collars              Bought                Gas          Forecasted
                      Sold Put     Put          Ceiling
          (bcf)       Price        Price        Price        Production     Natural
                                                             (bcf)          Gas

                                                                            Production
                                                                            
Q1        0           $ -          $ -          $ -
2013
Q2        18            3.03         3.55         4.03
2013
Q3        18            3.03         3.55         4.03
2013
Q4      18        3.03     3.55     4.03                    
2013
Total   54       $ 3.03    $ 3.55    $ 4.03    1,050            5%
2013
                                                                                 

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
                                                         
                                                                  
Q1 2013         0                $   -
Q2 2013         0                    -
Q3 2013         0                    -
Q4 2013       0                -                      
Total 2013    0             $   -         1,050         0%
Total 2014    0             $   -                      
Total 2015    0             $   -                      
Total 2016    193           $   9.92                   
– 2020
                                                                  

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

                 
                    
                 Volume (bcf)   Avg. NYMEX less
                                  
Q1 2013             11               $      0.21
Q2 2013             11                      0.21
Q3 2013             11                      0.21
Q4 2013           11                  0.21
Total 2013        44            $      0.21
Total 2014        28            $      0.32
Total 2015        31            $      0.34
Total 2016-2022   8             $      1.02
                                            

As of February 21, 2013, 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:

                                                                    
                                                                                 Total
                                                                   Total         Gains
                                                                   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
          (mbbls)      Open                         Forecasted     Premiums      for Call
                       Swaps         (mbbls)                                     Options
                                                    Oil            for Call
                                                                   Options       per bbl of
                                                    Production
                                                                   ($ in         Forecasted
                                                                   millions)     Oil

                                                                                 Production
                                                                                     
Q1        6,401        $ 95.52                                     $  1
2013
Q2        7,935          95.56                                        1
2013
Q3        8,451          95.42                                        2
2013
Q4      8,796      95.33                            2          
2013
Total   31,583    $ 95.45    37,000      85    %      $  6       $   0.17
2013
Total   18,073    $ 93.67                          $  (151 )      
2014
Total   500       $ 88.75                          $  265        
2015
Total
2016    0         $ -                              $  117        
–
2022
                                                                                     

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
                                                                        
Q1 2013        2,125            $  98.09
Q2 2013        1,954               97.90
Q3 2013        1,975               97.90
Q4 2013      1,975           97.90                        
Total 2013   8,029         $  97.95      37,000      22      %
Total 2014   17,612        $  98.79                        
Total 2015   27,048        $  100.99                       
Total 2016   24,220        $  100.07                       
– 2017
                                                                        

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

                             
            Volume (mbbls)   Avg. NYMEX plus
                               
Q1 2013        2,340              $     15.09
Q2 2013        2,457                    12.34
Q3 2013        736                      10.07
Q4 2013      0                    -
Total 2013   5,533           $     13.20
                                        

                                                
SCHEDULE “B”
MANAGEMENT’S OUTLOOK AS OF NOVEMBER 1, 2012
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF FEBRUARY 21, 2013


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 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.

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