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Chesapeake Energy Corporation Reports Financial and Operational Results for the 2011 Third Quarter

03.11.2011  |  Business Wire

Company Reports 2011 Third Quarter Net Income to Common
Stockholders of $879 Million, or $1.23 per Fully Diluted Common Share,
on Revenue of $4.0 Billion; Company Reports Adjusted Net Income
Available to Common Stockholders of $496 Million, or $0.72 per Fully
Diluted Common Share, Adjusted Ebitda of $1.4 Billion and Operating Cash
Flow of $1.4 Billion

2011 Third Quarter Average Daily Total Production of 3.329 Bcfe
per Day Increases 9% Year over Year and 9% Sequentially; 2011 Third
Quarter Liquids Production Increases 91% Year over Year and 21%
Sequentially; 2011 Third Quarter Liquids Production Delivers 17% of
Total Production and 40% of Unhedged Natural Gas and Liquids Revenue

Company Adds New Net Proved Reserves of 4.2 Tcfe Through the
Drillbit in the First Three Quarters of 2011 at a Cost of $1.08 per
Proved Mcfe; Proved Reserves Total 17.7 Tcfe, or Almost 3 Billion
Barrels of Oil Equivalent


Chesapeake Energy Corporation (NYSE:CHK) today announced its 2011 third
quarter financial and operational results. For the quarter, Chesapeake
reported net income to common stockholders of $879 million ($1.23 per
fully diluted common share), operating cash flow of $1.409 billion
(defined as cash flow from operating activities before changes in assets
and liabilities) and ebitda of $2.013 billion (defined as net income
before income taxes, interest expense, and depreciation, depletion and
amortization) on revenue of $3.977 billion and production of 306 billion
cubic feet of natural gas equivalent (bcfe).


The company′s 2011 third quarter results include various items that are
typically not included in published estimates of the company′s financial
results by certain securities analysts. For the 2011 third quarter,
Chesapeake reported adjusted net income to common stockholders of $496
million ($0.72 per fully diluted common share) and adjusted ebitda of
$1.385 billion. The primary excluded item was a net unrealized after-tax
mark-to-market gain of $385 million resulting from the company′s natural
gas, liquids and interest rate hedging programs.


A reconciliation of operating cash flow, ebitda, adjusted ebitda and
adjusted net income to comparable financial measures calculated in
accordance with generally accepted accounting principles is presented on
pages 16 ? 20 of this release.

Key Operational and Financial Statistics Summarized


The table below summarizes Chesapeake′s key results during the 2011
third quarter and compares them to results during the 2011 second
quarter and the 2010 third quarter.


 ?
Three Months Ended
9/30/11
 ?

 ?
6/30/11
 ?

 ?
9/30/10
 ?

Average daily production (in mmcfe)(a)
3,329

3,049

3,043

Natural gas equivalent production (in bcfe)

306

277

280

Natural gas equivalent realized price ($/mcfe)(b)
5.78

6.07

5.67

Oil and NGL (liquids) production (in mbbls)

8,669

7,192

4,533

Liquids as % of total production

17

16

10

Average realized liquids price ($/bbl)(b)
63.03

65.23

59.81

Liquids as % of realized revenue

31

28

17

Liquids as % of unhedged revenue

40

40

23

Natural gas production (in bcf)

254

234

253

Natural gas as % of total production

83

84

90

Average realized natural gas price ($/mcf)(b)
4.82

5.19

5.20

Natural gas as % of realized revenue

69

72

83

Natural gas as % of unhedged revenue

60

60

77

Marketing, gathering and compression net margin ($/mcfe)(c)
.10

.14

.12

Oilfield services net margin ($/mcfe) (c)
.11

.11

.03

Production expenses ($/mcfe)

(.92

)

(.94

)

(.83

)

Production taxes ($/mcfe)

(.16

)

(.17

)


(.12


)


General and administrative costs ($/mcfe)(d)
(.41

)

(.38

)


(.37


)


Stock-based compensation ($/mcfe)

(.08

)

(.08

)


(.07


)


DD&A of natural gas and liquids properties ($/mcfe)

(1.38

)

(1.32

)


(1.35


)


D&A of other assets ($/mcfe)

(.24

)

(.23

)


(.20


)


Interest expense ($/mcfe)(b)
(.01

)

(.07

)


(.00


)


Operating cash flow ($ in millions)(e)
1,409

1,207

1,234

Operating cash flow ($/mcfe)

4.60

4.35

4.41

Adjusted ebitda ($ in millions)(f)
1,385

1,365

1,282

Adjusted ebitda ($/mcfe)

4.52

4.92

4.58

Net income to common stockholders ($ in millions)

879

467

515

Earnings per share ? diluted ($)

1.23

.68

.75

Adjusted net income to common stockholders ($ in millions)(g)
496

528

478

Adjusted earnings per share ? diluted ($)

.72

.76

.70

 ?


(a) Includes effect of Fayetteville Shale asset sale (which had an
average production loss impact of approximately 400 mmcfe per day in
both the 2011 third and second quarters) to BHP Billiton on March 31,
2011 and VPP #9 sale (which had an average production loss impact of
approximately 75 and 40 mmcfe per day in the 2011 third quarter and 2011
second quarter, respectively) on May 12, 2011.


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


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


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


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


(f) Defined as net income before income taxes, interest expense, and
depreciation, depletion and amortization expense, as adjusted to remove
the effects of certain items detailed on page 18.


(g) Defined as net income available to common stockholders, as adjusted
to remove the effects of certain items detailed on page 19.

2011 Third Quarter Average Daily Total Production of 3.329 Bcfe per
Day Increases 9% Year over Year and 9% Sequentially; 2011 Third Quarter
Liquids Production Increases 91% Year over Year and 21% Sequentially;
2011 Third Quarter Liquids Production Delivers 17% of Total Production
and 40% of Unhedged Natural Gas and Liquids Revenue


Chesapeake′s daily production for the 2011 third quarter averaged 3.329
bcfe, an increase of 286 million cubic feet of natural gas equivalent
(mmcfe), or 9%, over the 3.043 bcfe produced per day in the 2010 third
quarter and an increase of 280 mmcfe, or 9%, from the 3.049 bcfe
produced per day in the 2011 second quarter.


Chesapeake′s average daily production of 3.329 bcfe for the 2011 third
quarter consisted of 2.763 billion cubic feet of natural gas (bcf) and
94,228 barrels (bbls) of oil and natural gas liquids (collectively,
'liquids?). The company′s 2011 third quarter production of 306.2 bcfe
was comprised of 254.2 bcf of natural gas (83% on a natural gas
equivalent basis) and 8.7 million barrels of liquids (mmbbls) (17% on a
natural gas equivalent basis). The company′s year-over-year growth rate
of natural gas production was 1% while its year-over-year growth rate of
liquids production was 91%. The company′s percentage of revenue from
liquids in the 2011 third quarter was 40% of total unhedged natural gas
and liquids revenue compared to 23% in the 2010 third quarter and 40% in
the 2011 second quarter.

2011 Third Quarter Average Realized Prices Benefit from Realized
Hedging Gains of $344 Million, or $1.12 per Mcfe


Average prices realized during the 2011 third quarter (including
realized gains or losses from natural gas and oil derivatives, but
excluding unrealized gains or losses on such derivatives) were $4.82 per
thousand cubic feet (mcf) and $63.03 per bbl, for a realized natural gas
equivalent price of $5.78 per thousand cubic feet of natural gas
equivalent (mcfe). Realized gains from natural gas hedging activities
during the 2011 third quarter generated a $1.43 gain per mcf, while
realized losses from liquids hedging activities generated a $2.26 loss
per bbl, resulting in 2011 third quarter net realized hedging gains of
$344 million, or $1.12 per mcfe.


By comparison, average prices realized during the 2010 third quarter
(including realized gains or losses from natural gas and oil
derivatives, but excluding unrealized gains or losses on such
derivatives) were $5.20 per mcf and $59.81 per bbl, for a realized
natural gas equivalent price of $5.67 per mcfe. Realized gains from
natural gas and liquids hedging activities during the 2010 third quarter
generated a $1.92 gain per mcf and a $5.56 gain per bbl, respectively,
for 2010 third quarter realized hedging gains of $512 million, or $1.83
per mcfe.


The company′s realized cash hedging gains since January 1, 2006 have
been $8.1 billion, or $1.64 on average for every mcfe produced.

Company Provides Update on Hedging Positions


The following table summarizes Chesapeake′s 2011 and 2012 open swap
positions as of November 3, 2011. Depending on changes in natural gas
and oil futures markets and management′s view of underlying natural gas
and liquids 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
 ?
Liquids
Year

% of Forecasted

Production


 ?

$ NYMEX

Natural Gas

% of Forecasted

Production


 ?

$ NYMEX

Oil WTI


4Q 2011

0

%

?

4

%

$

97.17

2012

0

%

?

3

%

$

98.10

2013

0

%

?

1

%

$

87.69

 ?


In addition to the open hedging positions disclosed above, as of
November 3, 2011, the company had an additional $358 million, $294
million and $47 million of net hedging gains on closed contracts and
premiums collected on call options that will be realized in 2011, 2012
and 2013, respectively, as set forth below.


 ?
Natural Gas
 ?
Liquids
Year

Forecasted

Production

(bcf)


 ?

Gains

($ in millions)


 ?

Gains

($/mcf)

Forecasted

Production

(mbbls)


 ?

Gains (Losses)

($ in millions)


 ?

Gains

(Losses)

($/bbl)


4Q 2011

250

$

369

$

1.48

10,000

$

(11

)

$

(1.11

)

2012

1,020

$

400

$

0.39

55,000

$

(106

)

$

(1.92

)

2013

1,040

$

21

$

0.02

74,000

$

26

 ?

$

0.36

 ?

 ?


Details of the company′s quarter-end hedging positions are available in
the company′s Form 10-Q filing with the Securities and Exchange
Commission (SEC) and current positions are disclosed in summary format
in the company′s Outlook. The company′s updated forecasts for 2011, 2012
and 2013 are attached to this release in the Outlook dated November 3,
2011, labeled as Schedule 'A,? which begins on page 21. The Outlook has
been changed from the Outlook dated July 28, 2011, attached as Schedule
'B,? which begins on page 25, to reflect various updated information.

Proved Natural Gas and Liquids Reserves Increased by 581 Bcfe, or 3%,
in the First Three Quarters of 2011 to 17.7 Tcfe Despite the Sale of 2.8
Tcfe of Proved Reserves; Also in the First Three Quarters of 2011,
Company Adds New Net Proved Reserves Before Sales of 4.2 Tcfe Through
the Drillbit at a Cost of $1.08 per Proved Mcfe


The following table compares Chesapeake′s September 30, 2011 proved
reserves, the increase versus its year-end 2010 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 based on the trailing 12-month average price required by the
reserve reporting rules of the SEC and the 10-year average NYMEX strip
prices at September 30, 2011.

Pricing Method
 ?

Natural

Gas

Price

($/mcf)


 ?


 ?


 ?

Oil

Price

($/bbl)


 ?

Proved

Reserves

(tcfe)(a)


 ?

Proved

Reserves

Increase

(bcfe)(b)


 ?

Proved

Reserves

Increase

%(b)


 ?

PV-10

(billions)


 ?

Proved

Developed

%


Trailing 12-month average (SEC)(c)
$

4.16

$

94.32

17.7

581

3

%

$

18.2

56

%

9/30/11 10-year average NYMEX strip(d)
$

5.36

$

85.94

18.5

872

5

%

$

25.0

56

%

 ?


(a) After sales of proved reserves of approximately 2.8 tcfe during the
first three quarters of 2011.


(b) Compares proved reserve increase for the first three quarters of
2011 under comparable pricing methods. At year-end 2010, Chesapeake′s
proved reserves were 17.1 tcfe using trailing 12-month average prices,
which are required by SEC reporting rules, and 17.6 tcfe using 10-year
average NYMEX strip prices at December 31, 2010.


(c) Reserve volumes estimated using SEC reserve recognition standards
and pricing assumptions based on the trailing 12-month average
first-day-of-the-month prices as of September 30, 2011. This pricing
yields estimated 'proved reserves' for SEC reporting purposes. Natural
gas and liquids volumes estimated under any alternative pricing scenario
reflect the sensitivity of proved reserves to a different pricing
assumption.


(d) 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.


The following table summarizes Chesapeake′s proved well costs for the
first three quarters of 2011 using the two pricing methods described
above.


 ?

 ?

Trailing

12-Month Average

(SEC) Pricing

($/mcfe)


 ?

9/30/11

10-year Average

NYMEX Strip

Pricing

($/mcfe)


Proved well costs(a)
 ?

$

1.08

 ?

$

1.04


(a) Includes performance-related revisions and excludes price-related
revisions. Costs are net of $1.868 billion of well cost carries paid by
the company′s joint venture partners.


A complete reconciliation of proved reserves based on these two
alternative pricing methods, along with total costs, is presented on
pages 12 and 13 of this release.


In addition to the PV-10 value of its proved reserves, the company also
has significant value in its unevaluated properties, which had a book
value of $16.4 billion as of September 30, 2011 and a likely value
substantially in excess of book value. Furthermore, the net book value
of the company′s other assets (including gathering systems, compressors,
land and buildings, investments and other non-current assets) was $7.0
billion as of September 30, 2011, an increase of approximately $0.9
billion from December 31, 2010.

Chesapeake′s Leasehold and 3-D Seismic Inventories Total 15.0 Million
Net Acres and 30.1 Million Acres, Respectively; Risked Unproved and
Unrisked Unproved Resources in the Company′s Inventory Total 111 Tcfe
and 338 Tcfe, Respectively


Since 2000, Chesapeake has built the largest combined inventories of
onshore leasehold (15.0 million net acres) and 3-D seismic (30.1 million
acres) in the U.S. The company has also accumulated the largest
inventory of U.S. natural gas shale play leasehold (2.5 million net
acres) and now owns a leading position in 12 of what Chesapeake believes
are the Top 15 unconventional liquids-rich plays in the U.S. ? the
Granite Wash, Cleveland, Tonkawa and Mississippi Lime plays in the
Anadarko Basin; the Avalon, Bone Spring, Wolfcamp and Wolfberry plays in
the Permian Basin; the Eagle Ford Shale in South Texas; the Niobrara
Shale in the Powder River and DJ Basins; the Bakken/Three Forks in the
Williston Basin; and the Utica Shale in the Appalachian Basin.


On its leasehold inventory, Chesapeake has identified an estimated 18.5
trillion cubic feet of natural gas equivalent (tcfe) of proved reserves
(using volume estimates based on the 10-year average NYMEX strip prices
at September 30, 2011), 111 tcfe of risked unproved resources and 338
tcfe of unrisked unproved resources. The company is currently using 171
operated drilling rigs to further develop its inventory of approximately
38,700 net risked drillsites. Of Chesapeake′s 171 operated rigs, 105 are
drilling wells primarily focused on unconventional liquids-rich plays,
63 are drilling wells primarily focused on unconventional natural gas
plays and three are drilling conventional natural gas plays. The company
has reduced its natural gas-directed activity by 18 rigs from July 2011
and by 31 rigs from January 2011. In addition, 165 of Chesapeake′s 171
operated rigs are drilling horizontal wells.


In recognition of the value gap between liquids and natural gas prices,
Chesapeake has directed a significant portion of its technological and
leasehold acquisition expertise during the past three years to identify,
secure and commercialize new unconventional liquids-rich plays. To date,
Chesapeake has built leasehold positions and established production in
multiple liquids-rich plays on approximately 6.2 million net leasehold
acres with 7.0 billion bbls of oil equivalent (bboe) (or 42 tcfe) of
risked unproved resources and 27.0 bboe (or 162 tcfe) of unrisked
unproved resources based on the company′s internal estimates. As a
result of its success to date, Chesapeake expects to increase its
liquids production through its drilling activities to an average of
approximately 150,000 bbls per day in 2012, 200,000 bbls per day in 2013
and 250,000 bbls per day in 2015. Previously, these volume estimates
were for year-end exit rates and have been recently revised to full-year
averages because of the company′s ongoing success in increasing its
liquids production rates.


The following table summarizes Chesapeake′s ownership and activity in
its unconventional natural gas plays, unconventional liquids-rich plays
and other conventional and unconventional plays. Chesapeake uses a
probability-weighted statistical approach to estimate the potential
number of drillsites and unproved resources associated with such
drillsites.


 ?

 ?
Est.
 ?

 ?
Risked
 ?
Total
 ?
Risked
 ?
Unrisked
 ?
Oct 2011
 ?
Oct 2011
CHKDrillingNetProvedUnprovedUnprovedDaily NetOperated
NetDensityRiskUndrilledReservesResourcesResourcesProductionRig
Play Type/Area
 ?
Acreage(1)
 ?
(Acres)
 ?
Factor
 ?
Wells
 ?
(bcfe)(1)(2)
 ?
(bcfe)(1)
 ?
(bcfe)(1)
 ?
(mmcfe)
 ?
Count

Unconventional Natural Gas Plays:


Marcellus

1,780,000

90

60

%

7,850

1,204

37,800

95,300

370

29

Haynesville

460,000

80

30

%

3,710

4,293

15,300

23,100

1,195

19

Bossier(3)
190,000

80

60

%

950

21

3,900

9,800

10

0

Barnett

220,000

60

25

%

1,610

4,169

2,700

3,600

485

15

Pearsall(4)
 ?

350,000

 ?

160

 ?

75

%

 ?

550

 ?

6

 ?

2,500

 ?

9,800

 ?

ND

 ?

0
Subtotal2,460,00014,6709,69362,200141,6002,06063

 ?

Unconventional Liquids Plays:


Anadarko Basin(5)
2,385,000

155

70

%

4,890

2,862

13,300

37,200

540

44

Eagle Ford

460,000

80

50

%

2,830

559

8,000

16,500

85

30

Permian Basin(6)
830,000

160

64

%

1,810

332

2,700

8,800

120

13

Powder River and DJ basins(7)
640,000

ND

ND

ND

ND

ND

ND

ND

11

Utica

1,500,000

ND

ND

ND

ND

ND

ND

ND

5

Other

 ?

400,000

 ?

ND

 ?

ND

 ?

ND

 ?

ND

 ?

ND

 ?

ND

 ?

ND

 ?

2
Subtotal6,215,00014,8803,77941,900162,000780105

 ?
Other Conventional and
Unconventional Plays:
 ?
6,325,000
 ?
Various
 ?
Various
 ?
9,150
 ?
5,005
 ?
6,600
 ?
34,000
 ?
630
 ?
3
Total
 ?
15,000,000
 ?

 ?

 ?

 ?

 ?
38,700
 ?
18,477
 ?
110,700
 ?
337,600
 ?
3,470
 ?
171


Note: ND denotes 'not disclosed?


(1) As of September 30, 2011, pro forma for recent leasehold
transactions.


(2) Based on 10-year average NYMEX strip prices at September 30, 2011.


(3) Bossier Shale acreage overlaps with Haynesville Shale acreage and is
excluded from the sub-totals to avoid double counting of acreage.


(4) Pearsall Shale acreage overlaps with Eagle Ford Shale acreage and is
excluded from the sub-totals to avoid double counting of acreage.


(5) Includes Granite Wash, Cleveland, Tonkawa and Mississippi Lime plays.


(6) Includes various Delaware and Midland basin plays, including
Wolfcamp, Avalon, Bone Spring and Wolfberry.


(7) Includes Niobrara, Frontier, Codell and Greenhorn plays.

Conference Call Information


A conference call to discuss this release has been scheduled for Friday,
November 4, 2011 at 9:00 a.m. EDT. The telephone number to access the
conference call is 913-312-1463 or toll-free 888-778-8861.
The passcode for the call is 5544489. We encourage those who
would like to participate in the call to dial the access number between
8:50 and 9:00 a.m. EDT. For those unable to participate in the
conference call, a replay will be available for audio playback from 1:00
p.m. EDT on Friday, November 4, 2011 through midnight on November 18,
2011. The number to access the conference call replay is 719-457-0820
or toll-free 888-203-1112. The passcode for the replay is 5544489.
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 website.
The webcast of the conference call will be available on Chesapeake′s
website for one year.

Chesapeake Energy Corporation is the second-largest producer of
natural gas, a Top 15 producer of oil and natural gas liquids and the
most active driller of new wells in the U.S.Headquartered
in Oklahoma City, the company's operations are focused on discovering
and developing unconventional natural gas and oil fields onshore in the
U.S.Chesapeake owns leading positions in the Barnett,
Haynesville, Bossier, Marcellus and Pearsall natural gas shale plays and
in the Granite Wash, Cleveland, Tonkawa, Mississippi Lime, Bone Spring,
Avalon, Wolfcamp, Wolfberry, Eagle Ford, Niobrara, Three Forks/Bakken
and Utica unconventional liquids plays.The company has
also vertically integrated its operations and owns substantial
midstream, compression, drilling, trucking, pressure pumping and other
oilfield service assets directly and indirectly through its subsidiaries
Chesapeake Midstream Development, L.P. and Chesapeake Oilfield Services,
L.L.C. and its affiliate Chesapeake Midstream Partners, L.P. (NYSE:CHKM).Chesapeake′s stock is listed on the New York Stock Exchange under
the symbol CHK.Further information is available at www.chk.com
where Chesapeake routinely posts announcements, updates, events,
investor information, presentations and press releases.

This news release and the accompanying Outlooks include
'forward-looking statements? within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934.Forward-looking statements give our current expectations or
forecasts of future events.They include estimates of natural gas
and liquids reserves and resources, expected natural gas and liquids
production and future expenses, assumptions regarding future natural gas
and oil prices, planned drilling activity and well costs, projected cash
flow and liquidity, business strategy and other plans and objectives for
future operations.Disclosures of the estimated realized effects
of our current hedging positions on future natural gas and liquids sales
are based upon market prices that 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 our 2010 Form
10-K filed with the U.S. Securities and Exchange Commission on March 1,
2011.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
liquids properties resulting in ceiling test write-downs; the
availability of capital on an economic basis, including planned asset
monetization transactions, to fund reserve replacement costs; our
ability to replace reserves and sustain production; uncertainties
inherent in estimating quantities of natural gas and liquids 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 liquids sales, the
need to secure hedging liabilities and the inability of hedging
counterparties to satisfy their obligations; a reduced ability to borrow
or raise additional capital as a result oflower natural gas and
oil prices; drilling and operating risks, including potential
environmental liabilities; legislative and regulatory changes adversely
affecting our industry and our business; general economic conditions
negatively impacting us and our business counterparties; transportation
capacity constraints and interruptions that could adversely affect our
revenues and cash flow; and adverse results in pending or future
litigation.

Our production forecasts are dependent upon many assumptions,
including estimates of production decline rates from existing wells and
the outcome of future drilling activity.Although we believe the
expectations and forecasts reflected in these and other forward-looking
statements are reasonable, we can give no assurance they will prove to
have been correct.They can be affected by inaccurate assumptions
or by known or unknown risks and uncertainties.

The SEC requires natural gas and oil companies, in filings made with
the SEC, to disclose proved reserves, which are those quantities of
natural gas and liquids that by analysis of geoscience and engineering
data can be estimated with reasonable certainty to be economically
producible ? from a given date forward, from known reservoirs, and under
existing economic conditions, operating methods, and government
regulations ? prior to the time at which contracts providing the right
to operate expire, unless evidence indicates that renewal is reasonably
certain, regardless of whether deterministic or probabilistic methods
are used for the estimation.In this news release, we use the
terms 'risked and unrisked unproved resources? to describe Chesapeake′s
internal estimates of volumes of natural gas and liquids that are not
classified as proved reserves but are potentially recoverable through
exploratory drilling or additional drilling or recovery techniques.These
are broader descriptions of potentially recoverable volumes than
probable and possible reserves, as defined by SEC regulations.Estimates
of unproved resources are by their nature more speculative than
estimates of proved reserves and accordingly are subject to
substantially greater risk of actually being realized by the company.We believe our estimates of unproved resources are reasonable, but
such estimates have not been reviewed by independent engineers.Estimates
of unproved resources may change significantly as development provides
additional data, and actual quantities that are ultimately recovered may
differ substantially from prior estimates.The company calculates
the standardized measure of future net cash flows of proved reserves
only at year end because applicable income tax information on
properties, including recently acquired natural gas and liquids
interests, is not readily available at other times during the year.As
a result, the company is not able to reconcile interim period-end PV-10
values to the standardized measure at such dates.The only
difference between the two measures is that PV-10 is calculated before
considering the impact of future income tax expenses, while the
standardized measure includes such effects.Year-end standardized
measure calculations are provided in the financial statement notes in
our annual reports on Form 10-K.


 ?

 ?

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)


 ?

 ?

 ?

 ?

 ?
THREE MONTHS ENDED:September 30,September 30,

 ?
2011
 ?

 ?
2010
 ?

 ?
$
 ?

 ?
$/mcfe
 ?
$
 ?

 ?
$/mcfe
REVENUES:
Natural gas and liquids sales
2,402

7.84

1,639

5.86
Marketing, gathering and compression sales
1,422

4.64

883

3.15
Oilfield services revenue
 ?

153

 ?

0.50

 ?

 ?

59

 ?

0.21

 ?
Total Revenues
 ?

3,977

 ?

12.98

 ?

 ?

2,581

 ?

9.22

 ?

 ?
OPERATING COSTS:
Production expenses
282

0.92

231

0.83
Production taxes
50

0.16

34

0.12
General and administrative expenses
151

0.49

125

0.45
Marketing, gathering and compression expenses
1,392

4.55

851

3.04
Oilfield services expense
118

0.39

52

0.18
Natural gas and liquids depreciation, depletion and

Amortization


423

1.38

378

1.35
Depreciation and amortization of other assets
75

0.24

56

0.20
Losses on sales of other property and equipment
3

0.01

17

0.06
Other impairments
 ?

?

 ?

?

 ?

 ?

20

 ?

0.07

 ?
Total Operating Costs
 ?

2,494

 ?

8.14

 ?

 ?

1,764

 ?

6.30

 ?

 ?
INCOME FROM OPERATIONS
 ?

1,483

 ?

4.84

 ?

 ?

817

 ?

2.92

 ?

 ?
OTHER INCOME (EXPENSE):
Interest expense
(4

)

(0.01

)

(3

)

(0.01

)
Earnings on investments
28

0.09

151

0.54
Losses on purchases or exchanges of debt
?

?

(59

)

(0.21

)
Impairment of investments
?

?

(16

)

(0.06

)
Other income
 ?

4

 ?

0.01

 ?

 ?

17

 ?

0.06

 ?
Total Other Income
 ?

28

 ?

0.09

 ?

 ?

90

 ?

0.32

 ?

 ?
INCOME BEFORE INCOME TAXES
1,511

4.93

907

3.24

 ?
INCOME TAX EXPENSE (BENEFIT):
Current income taxes
(1

)

?

(1

)

?
Deferred income taxes
 ?

590

 ?

1.92

 ?

 ?

350

 ?

1.25

 ?
Total Income Tax Expense
 ?

589

 ?

1.92

 ?

 ?

349

 ?

1.25

 ?

 ?
NET INCOME
922

3.01

558

1.99

 ?
Preferred stock dividends
 ?

(43

)

(0.14

)

 ?

(43

)

(0.15

)

 ?
NET INCOME AVAILABLE TO

COMMON STOCKHOLDERS


 ?

879

 ?

2.87

 ?

 ?

515

 ?

1.84

 ?

 ?
EARNINGS PER COMMON SHARE:
Basic
$

1.38

 ?

$

0.81

 ?
Diluted
$

1.23

 ?

$

0.75

 ?

 ?
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)
Basic
 ?

638

 ?

 ?

632

 ?
Diluted
 ?

753

 ?

 ?

744

 ?

 ?

 ?

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)


 ?

 ?

 ?

 ?

 ?
NINE MONTHS ENDED:September 30,September 30,

 ?

2011


 ?
2010

 ?
$
 ?

 ?
$/mcfe
 ?
$
 ?

 ?
$/mcfe
REVENUES:
Natural gas and liquids sales
4,688

5.43

4,698

6.13
Marketing, gathering and compression sales
3,844

4.45

2,520

3.29
Oilfield services revenue
 ?

376

 ?

0.44

 ?

 ?

173

 ?

0.22

 ?
Total Revenues
 ?

8,908

 ?

10.32

 ?

 ?

7,391

 ?

9.64

 ?

 ?
OPERATING COSTS:
Production expenses
782

0.91

652

0.85
Production taxes
140

0.16

119

0.16
General and administrative expenses
410

0.47

340

0.44
Marketing, gathering and compression expenses
3,744

4.34

2,429

3.17
Oilfield services expense
287

0.33

154

0.19
Natural gas and liquids depreciation, depletion and

amortization


1,147

1.33

1,025

1.34
Depreciation and amortization of other assets
206

0.24

159

0.21
Losses on sales of other property and equipment
3

?

17

0.02
Other impairments
 ?

4

 ?

0.01

 ?

 ?

20

 ?

0.03

 ?
Total Operating Costs
 ?

6,723

 ?

7.79

 ?

 ?

4,915

 ?

6.41

 ?

 ?
INCOME FROM OPERATIONS
 ?

2,185

 ?

2.53

 ?

 ?

2,476

 ?

3.23

 ?

 ?
OTHER INCOME (EXPENSE):
Interest expense
(37

)

(0.04

)

(12

)

(0.01

)
Earnings on investments
100

0.11

190

0.25
Losses on purchases or exchanges of debt
(176

)

(0.20

)

(130

)

(0.17

)
Impairment of investments
?

?

(16

)

(0.02

)
Other income
 ?

9

 ?

0.01

 ?

 ?

12

 ?

0.01

 ?
Total Other Income (Expense)
 ?

(104

)

(0.12

)

 ?

44

 ?

0.06

 ?

 ?
INCOME BEFORE INCOME TAXES
2,081

2.41

2,520

3.29

 ?
INCOME TAX EXPENSE:
Current income taxes
11

0.01

4

0.01
Deferred income taxes
 ?

801

 ?

0.93

 ?

 ?

966

 ?

1.26

 ?
Total Income Tax Expense
 ?

812

 ?

0.94

 ?

 ?

970

 ?

1.27

 ?

 ?
NET INCOME
1,269

1.47

1,550

2.02

 ?
Preferred stock dividends
 ?

(128

)

(0.15

)

 ?

(68

)

(0.09

)

 ?
NET INCOME AVAILABLE TO

COMMON STOCKHOLDERS


 ?

1,141

 ?

1.32

 ?

 ?

1,482

 ?

1.93

 ?

 ?
EARNINGS PER COMMON SHARE:
Basic
$

1.79

 ?

$

2.35

 ?
Diluted
$

1.69

 ?

$

2.24

 ?

 ?
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)
Basic
 ?

636

 ?

 ?

631

 ?
Diluted
 ?

752

 ?

 ?

692

 ?

 ?

 ?

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)


 ?

 ?

 ?

 ?

 ?
September 30,December 31,

 ?

 ?
2011
 ?
2010

 ?
Cash and cash equivalents
$

111

$

102
Other current assets
 ?

3,359

 ?

3,164
Total Current Assets
 ?

3,470

 ?

3,266

 ?
Property and equipment (net)
35,138

32,378
Other assets
 ?

1,514

 ?

1,535
Total Assets
$

40,122

$

37,179

 ?
Current liabilities
$

6,195

$

4,490
Long-term debt, net of discounts (a)
11,789

12,640
Asset retirement obligations
313

301
Other long-term liabilities
2,003

2,100
Deferred tax liability
 ?

3,524

 ?

2,384
Total Liabilities
 ?

23,824

 ?

21,915

 ?
Stockholders′ Equity
 ?

16,298

 ?

15,264

 ?
Total Liabilities & Stockholders' Equity
$

40,122

$

37,179

 ?
Common Shares Outstanding (in millions)
 ?

660

 ?

654

 ?

 ?

 ?

 ?

CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

($ in millions)

(unaudited)


 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
September 30,% of Total BookDecember 31,% of Total Book

 ?

 ?
2011
 ?
Capitalization
 ?
2010
 ?
Capitalization

 ?
Total debt, net of cash (a)
$

11,678

42

%

$

12,538

45

%
Stockholders' equity
 ?

16,298

58

%

 ?

15,264

55

%
Total
$

27,976

100

%

$

27,802

100

%

(a)

At September 30, 2011, the company had $3.236 billion of borrowings
under its $4.0 billion corporate revolving bank credit facility and
$327 million of borrowings under its $600 million midstream
revolving bank credit facility.

 ?

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2011 ADDITIONS TO NATURAL GAS AND LIQUIDS
PROPERTIES

BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT
SEPTEMBER 30, 2011

($ in millions, except per-unit data)

(unaudited)


 ?

 ?

 ?

 ?
Proved Reserves

 ?

 ?
Cost
 ?
Bcfe (a)
 ?

 ?
$/Mcfe

Proved Properties:


 ?

 ?
Well costs on proved properties(b)
$

4,537


4,188

(c)


1.08
Acquisition of proved properties
47

29

1.60
Sale of proved properties
 ?

(2,614

)

(2,760

)

0.95
Total net proved properties
 ?

1,970

 ?

1,457

 ?

1.35

 ?
Revisions ? price
?

(13

)

?

 ?

Unproved Properties:

Well costs on unproved properties
875

?

?
Acquisition of unproved properties
3,062

?

?
Sale of unproved properties
 ?

(3,656

)

?

 ?

?
Total net unproved properties
 ?

281

 ?

?

 ?

?

 ?

Other:

Capitalized interest on unproved properties
552

?

?
Geological and geophysical costs
154

?

?
Asset retirement obligations
 ?

(2

)

?

 ?

?
Total other
 ?

704

 ?

?

 ?

?

 ?
Total
$

2,955

 ?

1,444

 ?

2.05

 ?

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

NINE MONTHS ENDED SEPTEMBER 30, 2011

BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT
SEPTEMBER 30, 2011

(unaudited)


 ?

 ?

 ?

 ?

 ?
Bcfe(a)
Beginning balance, 1/1/11
17,096
Production
(863

)
Acquisitions
29
Divestitures
(2,760

)
Revisions ? changes to previous estimates
471
Revisions ? price
(13

)
Extensions and discoveries
3,717

 ?
Ending balance, 9/30/11
17,677

 ?

 ?
Proved reserves growth rate
3

%

 ?
Proved developed reserves
9,852
Proved developed reserves percentage
56

%

 ?
PV-10 ($ in billions) (a)
$

18.2

(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 September 30,
2011, of $4.16 per mcf of natural gas and $94.32 per bbl of oil,
before field differential adjustments.

 ?

(b)

Net of well cost carries of $1.868 billion associated with the
Statoil, Total, CNOOC-Eagle Ford and CNOOC-Niobrara joint venture
agreements.

 ?

(c)

Includes 471 bcfe of positive revisions resulting from changes to
previous estimates and excludes downward revisions of 13 bcfe
resulting from lower natural gas prices using the average
first-day-of-the-month price for the twelve months ended September
30, 2011, compared to the twelve months ended December 31, 2010.

 ?

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2011 ADDITIONS TO NATURAL GAS AND LIQUIDS
PROPERTIES

BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT SEPTEMBER 30,
2011

($ in millions, except per-unit data)

(unaudited)


 ?

 ?

 ?

 ?
Proved Reserves

 ?

 ?
Cost
 ?
Bcfe (a)
 ?

 ?
$/Mcfe

Proved Properties:


 ?

 ?
Well costs on proved properties(b)
$

4,537

4,359


 ?

(c)


1.04
Acquisition of proved properties
47

29

1.60
Sale of proved properties
 ?

(2,614

)

(2,760

)

0.95
Total net proved properties
 ?

1,970

 ?

1,628

 ?

1.21

 ?
Revisions ? price
?

107

?

 ?

Unproved Properties:

Well costs on unproved properties
875

?

?
Acquisition of unproved properties
3,062

?

?
Sale of unproved properties
 ?

(3,656

)

?

 ?

?
Total net unproved properties
 ?

281

 ?

?

 ?

?

 ?

Other:

Capitalized interest on unproved properties
552

?

?
Geological and geophysical costs
154

?

?
Asset retirement obligations
 ?

(2

)

?

 ?

?
Total other
 ?

704

 ?

?

 ?

?

 ?
Total
$

2,955

 ?

1,735

 ?

1.70

 ?

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

NINE MONTHS ENDED SEPTEMBER 30, 2011

BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT SEPTEMBER 30,
2011

(unaudited)


 ?

 ?

 ?

 ?

 ?
Bcfe(a)
Beginning balance, 1/1/11
17,605
Production
(863

)
Acquisitions
29
Divestitures
(2,760

)
Revisions ? changes to previous estimates
471
Revisions ? price
107
Extensions and discoveries
 ?

3,888

 ?
Ending balance, 9/30/11
 ?

18,477

 ?

 ?
Proved reserves growth rate
5

%

 ?
Proved developed reserves
10,282
Proved developed reserves percentage
56

%

 ?
PV-10 ($ in billions) (a)
$

25.0


(a)


Reserve volumes and PV-10 value estimated using SEC reserve
recognition standards and 10-year average NYMEX strip prices as of
September 30, 2011 of $5.36 per mcf of natural gas and $85.94 per
bbl of oil, before field differential adjustments. Futures prices,
such as the 10-year average NYMEX strip prices, represent an
unbiased consensus estimate by market participants about the likely
prices to be received for our future production. Chesapeake uses
such forward-looking market-based data in developing its drilling
plans, assessing its capital expenditure needs and projecting future
cash flows. Chesapeake believes these prices are better indicators
of the likely economic producibility of proved reserves than the
trailing 12-month average price required by the SEC's reporting rule.

 ?

(b)

Net of well cost carries of $1.868 billion associated with the
Statoil, Total, CNOOC-Eagle Ford and CNOOC-Niobrara joint venture
agreements.

 ?

(c)

Includes 471 bcfe of positive revisions resulting from changes to
previous estimates and excludes positive revisions of 107 bcfe
resulting from higher natural gas prices as of September 30, 2011,
compared to December 31, 2010.

 ?

 ?

CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA ? NATURAL GAS AND LIQUIDS SALES AND INTEREST
EXPENSE

(unaudited)


 ?

 ?

 ?

 ?

 ?
THREE MONTHS ENDEDNINE MONTHS ENDED

 ?
SEPTEMBER 30,SEPTEMBER 30,

 ?

 ?
2011
 ?

 ?

 ?
2010
 ?

 ?
2011
 ?

 ?

 ?
2010
 ?

 ?

 ?
Natural Gas and Liquids Sales ($ in millions):

Natural gas sales

$

861

$

828

$

2,412

$

2,504

Natural gas derivatives ? realized gains (losses)

364

487

1,322

1,418

Natural gas derivatives ? unrealized gains (losses)

 ?

(28

)

 ?

315

 ?

 ?

(693

)

 ?

534

 ?

 ?

Total Natural Gas Sales

 ?

1,197

 ?

 ?

1,630

 ?

 ?

3,041

 ?

 ?

4,456

 ?

 ?

Liquids sales

566

246

1,480

739

Oil derivatives ? realized gains (losses)

(20

)

25

(82

)

66

Oil derivatives ? unrealized gains (losses)

 ?

659

 ?

 ?

(262

)

 ?

249

 ?

 ?

(563

)

 ?

Total Liquids Sales

 ?

1,205

 ?

 ?

9

 ?

 ?

1,647

 ?

 ?

242

 ?

 ?

Total Natural Gas and Liquids Sales

$

2,402

 ?

$

1,639

 ?

$

4,688

 ?

$

4,698

 ?

 ?
Average Sales Price ? excluding gains

(losses) on derivatives:


Natural gas ($ per mcf)

$

3.39

$

3.28

$

3.30

$

3.63

Liquids ($ per bbl)

$

65.29

$

54.25

$

67.53

$

57.57

Natural gas equivalent ($ per mcfe)

$

4.66

$

3.84

$

4.51

$

4.23

 ?
Average Sales Price ? excluding unrealized gains

(losses) on derivatives:


Natural gas ($ per mcf)

$

4.82

$

5.20

$

5.10

$

5.69

Liquids ($ per bbl)

$

63.03

$

59.81

$

63.80

$

62.75

Natural gas equivalent ($ per mcfe)

$

5.78

$

5.67

$

5.94

$

6.17

 ?
Interest Expense (Income) ($ in millions):

Interest (a)
$

4

$

3

$

18

$

93

Derivatives ? realized (gains) losses

?

(2

)

6

(6

)

Derivatives ? unrealized (gains) losses

 ?

?

 ?

 ?

2

 ?

 ?

13

 ?

 ?

(75

)

Total Interest Expense

$

4

 ?

$

3

 ?

$

37

 ?

$

12

 ?

(a)

Net of amounts capitalized.

 ?

 ?

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

($ in millions)

(unaudited)


 ?

 ?

 ?

 ?

 ?
THREE MONTHS ENDED:September 30,September 30,

 ?

 ?
2011
 ?

 ?

 ?
2010
 ?

 ?
Beginning cash
$

109

 ?

$

601

 ?

 ?
Cash provided by operating activities
$

1,631

 ?

$

993

 ?

 ?
Cash flows from investing activities:
Well costs on proved properties
(1,149

)

(1,364

)
Well costs on unproved properties
(801

)

(23

)
Acquisitions of proved and unproved properties
(1,244

)

(1,362

)
Divestitures of proved and unproved properties
184

1,174
Investments, net
(86

)

(4

)
Other property and equipment, net
(397

)

(267

)
Other
 ?

18

 ?

 ?

(87

)
Total cash used in investing activities
$

(3,475

)

$

(1,933

)

 ?
Cash provided by financing activities
$

1,846

 ?

$

948

 ?

 ?
Ending cash
$

111

 ?

$

609

 ?

 ?

 ?

 ?

 ?

 ?

 ?
NINE MONTHS ENDED:September 30,September 30,

 ?

 ?
2011
 ?

 ?

 ?
2010
 ?

 ?
Beginning cash
$

102

 ?

$

307

 ?

 ?
Cash provided by operating activities
$

3,724

 ?

$

3,971

 ?

 ?
Cash flows from investing activities:
Well costs on proved properties
(4,470

)

(3,615

)
Well costs on unproved properties
(875

)

(103

)
Acquisitions of proved and unproved properties
(3,773

)

(4,217

)
Divestitures of proved and unproved properties
6,357

3,107
Investments, net
126

(113

)
Other property and equipment, net
(1,073

)

(640

)
Other
 ?

(7

)

 ?

(84

)
Total cash used in investing activities
$

(3,715

)

$

(5,665

)

 ?
Cash provided by financing activities
$

?

 ?

$

1,996

 ?

 ?
Ending cash
$

111

 ?

$

609

 ?

 ?

 ?

 ?

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)


 ?

 ?

 ?

 ?

 ?

 ?

 ?
THREE MONTHS ENDED:September 30,June 30,September 30,

 ?

 ?
2011
 ?

 ?

 ?
2011
 ?

 ?

 ?
2010
 ?

 ?
CASH PROVIDED BY OPERATING ACTIVITIES
$

1,631

$

1,375

$

993

 ?
Changes in assets and liabilities
 ?

(222

)

 ?

(168

)

 ?

241

 ?

 ?
OPERATING CASH FLOW (a)
$

1,409

 ?

$

1,207

 ?

$

1,234

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
THREE MONTHS ENDED:September 30,June 30,September 30,

 ?

 ?
2011
 ?

 ?
2011
 ?

 ?
2010
 ?

 ?
NET INCOME
$

922

$

510

$

558

 ?
Income tax expense
589

325

349
Interest expense
4

25

3
Depreciation and amortization of other assets
75

63

56

Natural gas and liquids depreciation, depletion and Amortization


 ?

423

 ?

 ?

366

 ?

 ?

378

 ?

 ?
EBITDA (b)
$

2,013

 ?

$

1,289

 ?

$

1,344

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
THREE MONTHS ENDED:September 30,June 30,September 30,

 ?

 ?
2011
 ?

 ?

 ?
2011
 ?

 ?

 ?
2010
 ?

 ?
CASH PROVIDED BY OPERATING ACTIVITIES
$

1,631

$

1,375

$

993

 ?
Changes in assets and liabilities
(222

)

(168

)

241
Interest expense
4

25

3
Unrealized gains (losses) on natural gas and oil derivatives
631

106

53
Gains (losses) on investments
(4

)

19

155
Stock-based compensation
(40

)

(39

)

(44

)
Other items
 ?

13

 ?

 ?

(29

)

 ?

(57

)

 ?
EBITDA (b)
$

2,013

 ?

$

1,289

 ?

$

1,344

 ?

(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 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)


 ?
NINE MONTHS ENDED:
 ?
September 30,
 ?
September 30,

 ?

 ?
2011
 ?

 ?

 ?
2010
 ?

 ?
CASH PROVIDED BY OPERATING ACTIVITIES
$

3,724

$

3,971

 ?
Changes in assets and liabilities
 ?

274

 ?

 ?

(173

)

 ?
OPERATING CASH FLOW (a)
$

3,998

 ?

$

3,798

 ?

 ?

 ?

 ?

 ?

 ?
NINE MONTHS ENDED:September 30,September 30,

 ?

 ?
2011
 ?

 ?

 ?
2010
 ?

 ?
NET INCOME
$

1,269

$

1,550

 ?
Income tax expense
812

970
Interest expense
37

12
Depreciation and amortization of other assets
206

159
Natural gas and liquids depreciation, depletion and amortization
 ?

1,147

 ?

 ?

1,025

 ?

 ?
EBITDA (b)
$

3,471

 ?

$

3,716

 ?

 ?

 ?

 ?

 ?

 ?
NINE MONTHS ENDED:September 30,September 30,

 ?

 ?
2011
 ?

 ?

 ?
2010
 ?

 ?
CASH PROVIDED BY OPERATING ACTIVITIES
$

3,724

$

3,971

 ?
Changes in assets and liabilities
274

(173

)
Interest expense
37

12
Unrealized gains (losses) on natural gas and oil derivatives
(444

)

(29

)
Gains on investments
19

120
Stock-based compensation
(119

)

(111

)
Other items
 ?

(20

)

 ?

(74

)

 ?
EBITDA (b)
$

3,471

 ?

$

3,716

 ?

(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 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)


 ?

 ?
September 30,
 ?
June 30,
 ?
September 30,
THREE MONTHS ENDED:
 ?

 ?
2011
 ?

 ?

 ?
2011
 ?

 ?

 ?
2010
 ?

 ?
EBITDA
$

2,013

$

1,289

$

1,344

 ?
Adjustments:
Unrealized (gains) losses on natural gas and oil derivatives
(631

)

(106

)

(53

)
Losses on purchases or exchanges of debt
?

174

59
Gains on investments
?

?

(121

)
Impairment of investments
?

?

16

Losses on sales of other property and equipment


3

4

17
Other impairments
 ?

?

 ?

 ?

4

 ?

 ?

20

 ?

 ?
Adjusted EBITDA (a)
$

1,385

 ?

$

1,365

 ?

$

1,282

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?


 ?

September 30,

September 30,
NINE MONTHS ENDED:
 ?


 ?


 ?

 ?

2011


 ?

 ?

 ?
2010
 ?

 ?
EBITDA


 ?


$


3,471


$

3,716

 ?
Adjustments:
Unrealized (gains) losses on natural gas and oil derivatives


 ?


444


29
Losses on purchases or exchanges of debt


 ?


176


130
Gains on investments


 ?


?


(121

)
Impairment of investments


 ?


?


16
Losses on sales of other property and equipment


 ?


3


17
Other impairments


 ?


 ?


4


 ?

 ?

20

 ?

 ?
Adjusted EBITDA (a)


 ?


$


4,098


 ?

$

3,807

 ?

(a)

Adjusted ebitda excludes certain items that management believes
affect the comparability of operating results. The company discloses
these non-GAAP financial measures as 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)


 ?

 ?
September 30,
 ?
June 30,
 ?
September 30,
THREE MONTHS ENDED:
 ?

 ?
2011
 ?

 ?

 ?
2011
 ?

 ?

 ?
2010
 ?

 ?
Net income available to common stockholders
$

879

$

467

$

515

 ?
Adjustments:
Unrealized (gains) losses on derivatives, net of tax
(385

)

(61

)

(31

)
Losses on purchases or exchanges of debt, net of tax
?

106

36
Gains on investment activity, net of tax
?

?

(74

)
Impairment of investments, net of tax
?

?

9

Losses on sales of other property and equipment, net of tax


2

3

11
Other impairments, net of tax
?

2

12

(Gain) loss on foreign currency derivatives, net of tax


 ?

?

 ?

 ?

11

 ?

 ?

?

 ?

 ?
Adjusted net income available to common stockholders (a)
496

528

478
Preferred stock dividends
 ?

43

 ?

 ?

43

 ?

 ?

43

 ?
Total adjusted net income
$

539

 ?

$

571

 ?

$

521

 ?

 ?
Weighted average fully diluted shares outstanding (b)
753

751

744

 ?
Adjusted earnings per share assuming dilution (a)
$

0.72

 ?

$

0.76

 ?

$

0.70

 ?

(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 discloses these non-GAAP financial measures as 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.

 ?

 ?

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
STOCKHOLDERS

($ in millions, except per-share data)

(unaudited)


 ?

 ?
September 30,
 ?
September 30,
NINE MONTHS ENDED:
 ?
2011
 ?
2010

 ?
Net income available to common stockholders
$

1,141

$

1,482

 ?
Adjustments:
Unrealized (gains) losses on derivatives, net of tax
279

(28

)
Losses on purchases or exchanges of debt, net of tax
107

80
Gains on investment activity, net of tax
?

(74

)
Impairment of investments, net of tax
?

9

Losses on sales of other property and equipment, net of tax


2

11
Other impairments, net of tax
2

12
(Gain) loss on foreign currency derivatives, net of tax
 ?

11

 ?

?

 ?

 ?
Adjusted net income available to common stockholders (a)
1,542

1,492
Preferred stock dividends
 ?

128

 ?

68

 ?
Total adjusted net income
$

1,670

$

1,560

 ?

 ?
Weighted average fully diluted shares outstanding (b)
752

692

 ?
Adjusted earnings per share assuming dilution (a)
$

2.22

$

2.26

 ?

(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 discloses these non-GAAP financial measures as 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?

CHESAPEAKE′S OUTLOOK AS OF NOVEMBER 3, 2011


Our policy is to periodically provide guidance on certain factors that
affect our future financial performance. As of November 3, 2011, we are
using the following key assumptions in our projections for 2011, 2012
and 2013.


The primary changes from our July 28, 2011 Outlook are in italicized
bold and are explained as follows:


1) First projections for full-year 2013 have been provided;


2) Projected effects of changes in our hedging positions have been
updated;


3) Certain cost assumptions have been updated;


4) Cash flow and proved well costs projections have been updated; and


5) Stand-alone Outlooks prior to consolidation eliminations are being
provided for the first time for wholly owned subsidiaries Chesapeake
Oilfield Services, L.L.C. and Chesapeake Midstream Development, L.P.


 ?

Chesapeake Energy Corporation Consolidated Projections

For Years Ending December 31, 2011, 2012 and 2013


 ?

 ?

 ?
Year Ending

12/31/11


 ?

 ?
Year Ending

12/31/12


 ?

 ?
Year Ending

12/31/13


Estimated Production:

Natural gas ? bcf

970 ? 990

1,000 ? 1,040
1,020 ? 1,060

Liquids ? mbbls

31,000 ? 33,000

53,000 ? 57,000
72,000 ? 76,000

Natural gas equivalent ? bcfe

1,156 ? 1,188

1,318 ? 1,382
1,452 ? 1,516

 ?

Daily natural gas equivalent midpoint ? mmcfe

3,200

3,700
4,060

 ?

Year over year (YOY) estimated production increase
13%15%10%

YOY estimated production increase excluding asset sales
24%16%11%

 ?

NYMEX Price(a) (for calculation of realized hedging
effects only):

Natural gas - $/mcf
$4.14$5.00$6.00

Oil - $/bbl
$92.84
$100.00
$100.00

 ?

Estimated Realized Hedging Effects (based on assumed NYMEX prices
above):

Natural gas - $/mcf
$1.68$0.37$0.02

Liquids - $/bbl
$(3.07)$(2.60)$(1.05)

 ?

Estimated Gathering/Marketing/Transportation Differentials to NYMEX
Prices:

Natural gas - $/mcf

$0.90 ? $1.10

$0.90 ? $1.10
$0.90 ? $1.10

Liquids - $/bbl(b)
$30.00 ? $35.00
$25.00 ? $30.00$20.00 ? $25.00

 ?

Operating Costs per Mcfe of Projected Production:

Production expense

$0.90 ? 1.00

$0.90 ? 1.00
$0.90 ? 1.00

Production taxes (~ 5% of O&G revenues)

$0.25 ? 0.30

$0.25 ? 0.30
$0.30 ? 0.35

General and administrative(c)
$0.36 ? 0.41
$0.39 ? 0.44$0.39 ? 0.44

Stock-based compensation (non-cash)

$0.07 ? 0.09
$0.04 ? 0.06$0.04 ? 0.06

DD&A of natural gas and liquids assets

$1.25 ? 1.40
$1.40 ? 1.60$1.40 ? 1.60

Depreciation of other assets

$0.20 ? 0.25
$0.25 ? 0.30$0.25 ? 0.30

Interest expense(d)
$0.05 ? 0.10

$0.05 ? 0.10
$0.05 ? 0.10

 ?

Other ($ millions):

Marketing, gathering and compression net margin(e)		$120 ? 130$130 ? 140$140 ? 150

Oilfield services net margin(e)		$120 ? 140$250 ? 300$350 ? 450

Other income (including equity investments)
$100 ? 150$100 ? 150$100 ? 150

Net income attributable to noncontrolling interest(f)		$(3) ? (5)$(35) ? (40)$(40) ? (45)

 ?

Book Tax Rate

39%

39%
39%


 ?


Weighted average shares outstanding (in millions):

Basic
635 ? 640640 ? 645645 ? 650

Diluted
748 ? 753753 ? 758758 ? 763

 ?


Operating cash flow before changes in assets and liabilities(g)(h)
($ millions)


$5,100 ? 5,200

$6,000 ? 6,800
$8,000 ? 9,000

Proved well costs, net of JV carries ($ millions)

($6,000 ? 6,500)
($6,200 ? 6,800)($7,000 ? 8,000)

 ?

 ?

Chesapeake Oilfield Services, L.L.C. Projections(i)

Prior to Consolidation Eliminations For Years Ending December
31, 2011, 2012 and 2013

($ in millions)


 ?

 ?
Year Ending

12/31/11


 ?
Year Ending

12/31/12


 ?
Year Ending

12/31/13


 ?

Revenue
$1,200 ? 1,300$2,000 ? 2,500$3,100 ? 3,600

Operating expense
$900 ? 1,000$1,400 ? 1,700$2,100 ? 2,500

Depreciation and amortization
$155 ? 165$210 ? 270$330 ? 390

Interest expense
$40 ? 50$60 ? 70$50 ? 60

 ?

Operating cash flow before changes in assets and liabilities(g)		$200 ? 250$600 ? 700$900 ? 1,000

Capital expenditures
($800 ? 900)($800 ? 900)($800 ? 900)

 ?

 ?

Chesapeake Midstream Development, L.P. Projections

Prior to Consolidation Eliminations For Years Ending December
31, 2011, 2012 and 2013

($ in millions)


 ?

 ?
Year Ending

12/31/11


 ?
Year Ending

12/31/12


 ?
Year Ending

12/31/13


 ?

Revenue
$200 ? 220$250 ? 300$350 ? 400

Operating expense
$150 ? 160$140 ? 170$170 ? 200

Depreciation and amortization
$50 ? 60$100 ? 120$150 ? 170

Interest expense
$10 ? 15$10 ? 15$15 ? 25

Earnings from equity investments
$75 ? 100$75 ? 100$75 ? 100

 ?

Operating cash flow before changes in assets and liabilities(g)		$130 ? 150$175 ? 225$225 ? 275

Capital expenditures (net of dropdowns)
($50 ? 100)($800 ? 900)($800 ? 900)


a) NYMEX natural gas prices have been updated for actual contract prices
through November 2011 and NYMEX oil prices have been updated for actual
contract prices through September 2011.


b) Differentials include effects of natural gas liquids.


c) Excludes expenses associated with non-cash stock-based compensation.


d) Does not include 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 interest of Chesapeake
Granite Wash Trust.


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 of $4.00 to $5.00 per mcf and $85.00 per bbl in
2011, $4.50 to $5.50 per mcf and $100.00 per bbl in 2012, and $5.50 to
$6.50 per mcf and $100.00 per bbl in 2013.


i) Excludes investment in FTS International, LLC.

Commodity Hedging Activities


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


At November 3, 2011, the company does not have any open natural gas
swaps in place. The company currently has $616 million of net hedging
gains related to closed natural gas contracts and premiums collected on
call options for future production periods.


 ?


 ?

 ?

Open Swaps

(bcf)

 ?

 ?

Avg. NYMEX


Price of


Open Swaps


 ?

 ?

Forecasted


Natural Gas


Production


(bcf)


 ?

 ?

Open Swap


Positions


as a % of


Forecasted


Natural Gas


Production


 ?

 ?

Total Gains


(Losses) from


Closed Trades


and Collected


Call Premiums


($ in millions)


 ?

 ?

Total Gains from


Closed Trades


and Collected


Call Premiums


per mcf of


Forecasted


Natural Gas


Production


Q4 2011

 ?

 ?
0
 ?

 ?

 ?
$0.00
 ?

 ?

 ?
250
 ?

 ?

 ?
0%
 ?

 ?
$369
 ?

 ?

 ?
$1.48

Q1 2012

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
158
 ?

 ?

Q2 2012
195

Q3 2012
32

Q4 2012

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
15
 ?

 ?

 ?

 ?

 ?

Total 2012

 ?

 ?
0
 ?

 ?

 ?
$0.00
 ?

 ?

 ?

1,020

 ?

 ?

 ?
0%
 ?

 ?

$
400
 ?

 ?

 ?
$0.39

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2013

 ?

 ?
0
 ?

 ?

 ?
$0.00
 ?

 ?

 ?
1,040
 ?

 ?

 ?
0%
 ?

 ?

$

21

 ?

 ?

 ?
$0.02

Total 2014

 ?

 ?
0
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

$

(32

)

 ?

 ?

 ?

 ?

Total 2015

 ?

 ?
0
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

$

(46

)

 ?

 ?

 ?

 ?

Total 2016 ? 2022

 ?

 ?
0
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

$

(96

)

 ?

 ?

 ?

 ?

 ?


The company currently has the following natural gas written call options
in place for 2011 through 2020:


 ?

 ?

 ?

Call Options

(bcf)

 ?

 ?

Avg. NYMEX


Strike Price


 ?

 ?

Forecasted


Natural Gas


Production


(bcf)


 ?

 ?

Call Options


as a % of


Forecasted


Natural Gas


Production


Q4 2011

 ?

 ?
11
 ?

 ?

 ?

 ?
4.13
 ?

 ?

 ?
250
 ?

 ?

 ?
4%

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Q1 2012
406.54

Q2 2012
406.54

Q3 2012
406.54

Q4 2012

 ?

 ?
41
 ?

 ?

 ?

 ?
6.54
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2012

 ?

 ?

161

 ?

 ?

 ?

$

6.54

 ?

 ?

 ?

1,020

 ?

 ?

 ?

16

%

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2013

 ?

 ?

415

 ?

 ?

 ?

$

6.44

 ?

 ?

 ?
1,040
 ?

 ?

 ?
40%

Total 2014

 ?

 ?

330

 ?

 ?

 ?

$

6.43

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2015

 ?

 ?
138
 ?

 ?

 ?
$6.41
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2016 ? 2020

 ?

 ?

393

 ?

 ?

 ?
$
7.93

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?


The company has the following natural gas basis protection swaps in
place for 2011 through 2022:


 ?

 ?

Non-Appalachia

 ?

 ?

Appalachia

Volume (Bcf)

 ?

Avg. NYMEX less

Volume (Bcf)

 ?

Avg. NYMEX plus

2011
7
$

0.82
12
$

0.14

2012

51

$

0.78

?

$

?

2013 - 2022

29

 ?

$

0.69

 ?

?

 ?

$

?

Totals
87
 ?

$

0.75

 ?
12
 ?

$

0.14

 ?


At November 3, 2011, the company has the following open crude oil swaps
in place for 2011 and through 2015. In addition, the company has $93
million of net hedging gains related to closed crude oil contracts and
premiums collected on call options for future production periods.


 ?

 ?

 ?

Open


Swaps


(mbbls)


 ?

 ?

Avg. NYMEX


Price of


Open Swaps


 ?

 ?

Forecasted


Liquids


Production


(mbbls)


 ?

 ?

Open Swap


Positions as


a % of


Forecasted


Liquids


Production


 ?

 ?

Total Gains


(Losses) from


Closed Trades


and Collected


Call Premiums


($millions)


 ?

 ?

Total Gains (Losses) from


Closed Trades


and Collected Call


Premiums per bbl


of Forecasted Liquids


Production


Q4 2011(a)
 ?

 ?
440
 ?

 ?

 ?
$97.17
 ?

 ?

 ?
10,000
 ?

 ?

 ?
4%
 ?

 ?
$(11)
 ?

 ?
$(1.11)

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Q1 2012
34697.89(19)

Q2 2012
34998.12(25)

Q3 2012
36198.19(29)

Q4 2012

 ?

 ?
369
 ?

 ?

 ?

 ?
98.20
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
(33)
 ?

 ?

 ?

 ?

 ?

Total 2012(a)
 ?

 ?
1,425
 ?

 ?

 ?
$98.10
 ?

 ?

 ?

55,000

 ?

 ?

 ?

3

%

 ?

 ?

$

(106
)
 ?

 ?

$

(1.92

)

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2013

 ?

 ?
739
 ?

 ?

 ?
$87.69
 ?

 ?

 ?
74,000
 ?

 ?

 ?
1%
 ?

 ?

$

26

 ?

 ?

 ?
$0.36
 ?

Total 2014

 ?

 ?
713
 ?

 ?

 ?
$88.27
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
$(159)
 ?

 ?

 ?

 ?

 ?

Total 2015

 ?

 ?
500
 ?

 ?

 ?
$88.75
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
$211
 ?

 ?

 ?

 ?

 ?

 ?

Total 2016 ? 2021

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
$132
 ?

 ?

 ?

 ?

 ?

 ?

(a)

Certain hedging contracts include knockout swaps with provisions
limiting the counterparty′s exposure below prices of $60.00 covering
276 mbbls in 2011 and 732 mbbls in 2012.

 ?


The company currently has the following crude oil written call options
in place for 2011 through 2017:


 ?

 ?

 ?

Call Options

(mbbls)

 ?

 ?

Avg. NYMEX


Strike Price


 ?

 ?

Forecasted


Liquids


Production


(mbbls)


 ?

 ?

Call Options


as a % of


Forecasted Liquids


Production


Q4 2011

 ?

 ?

1,840

 ?

 ?

 ?

$

110.00

 ?

 ?

 ?
10,000
 ?

 ?

 ?
18%

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Q1 2012
4,047100.00

Q2 2012
4,047100.00

Q3 2012
4,091100.00

Q4 2012

 ?

 ?
4,092
 ?

 ?

 ?

 ?
100.00
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2012

 ?

 ?
16,277
 ?

 ?

 ?
$100.00
 ?

 ?

 ?

55,000

 ?

 ?

 ?
30%

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2013

 ?

 ?
21,245
 ?

 ?

 ?
$95.19
 ?

 ?

 ?
74,000
 ?

 ?

 ?
29%

Total 2014

 ?

 ?
15,379
 ?

 ?

 ?
$96.61
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2015

 ?

 ?
19,360
 ?

 ?

 ?
$100.57
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2016 ? 2017

 ?

 ?
24,220
 ?

 ?

 ?
$100.07
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

SCHEDULE 'B?

CHESAPEAKE′S OUTLOOK AS OF JULY 28, 2011

(PROVIDED
FOR REFERENCE ONLY)

NOW SUPERSEDED BY OUTLOOK AS OF NOVEMBER
3, 2011

CHESAPEAKE′S OUTLOOK AS OF JULY 28, 2011

Years Ending December 31, 2011 and 2012


Our policy is to periodically provide guidance on certain factors that
affect our future financial performance. As of July 28, 2011, we are
using the following key assumptions in our projections for 2011 and 2012.


The primary changes from our May 2, 2011 Outlook are in italicized
bold and are explained as follows:


1) Our production guidance has been updated;


2) Projected effects of changes in our hedging positions have been
updated;


3) Certain cost assumptions have been updated; and


4) Our cash flow projections have been updated, including increased
drilling and completion costs.


 ?

 ?
Year Ending

12/31/2011

Year Ending

12/31/2012


Estimated Production:

Natural gas ? bcf
970 ? 9901,000 ? 1,040

Liquids ? mbbls
31,000 ? 33,00053,000 ? 57,000

Natural gas equivalent ? bcfe
1,156 ? 1,1881,318 ? 1,382

 ?

Daily natural gas equivalent midpoint ? mmcfe
3,2003,700

 ?

Year over year (YOY) estimated production increase
12 ? 15%12 - 18%

YOY estimated production increase excluding asset sales
23 ? 26%13 - 19%

 ?

NYMEX Price(a) (for calculation of realized hedging
effects only):

Natural gas - $/mcf
$4.34
$5.50

Oil - $/bbl
$99.15
$100.00

 ?

Estimated Realized Hedging Effects (based on assumed NYMEX prices
above):

Natural gas - $/mcf

$1.60
$0.28

Liquids - $/bbl
$(3.65)$(3.93)

 ?

Estimated Gathering/Marketing/Transportation Differentials to NYMEX
Prices:

Natural gas - $/mcf

$0.90 ? $1.10

$0.90 ? $1.10

Liquids - $/bbl(b)
$30.00 ? $35.00

$30.00 ? $35.00

 ?

Operating Costs per Mcfe of Projected Production:

Production expense

$0.90 ? 1.00

$0.90 ? 1.00

Production taxes (~ 5% of O&G revenues)

$0.25 ? 0.30

$0.25 ? 0.30

General and administrative(c)		$0.36 ? 0.41$0.36 ? 0.41

Stock-based compensation (non-cash)

$0.07 ? 0.09

$0.07 ? 0.09

DD&A of natural gas and liquids assets
$1.25 ? 1.40$1.25 ? 1.40

Depreciation of other assets

$0.20 ? 0.25

$0.20 ? 0.25

Interest expense(d)
$0.05 ? 0.10

$0.05 ? 0.10

 ?

Other Income per Mcfe:

Marketing, gathering and compression net margin
$0.12 ? 0.14$0.12 ? 0.14

Service operations net margin
$0.09 ? 0.11$0.15 ? 0.20

Other income (including equity investments)

$0.06 ? 0.08

$0.06 ? 0.08

 ?

Book Tax Rate

39%

39%


 ?


Equivalent Shares Outstanding (in millions):

Basic

640 ? 645

647 ? 652

Diluted

750 ? 755

760 ? 765

 ?

Operating cash flow before changes in assets and liabilities(e)(f)		$5,100 ? 5,200$6,000 ? 6,800

Drilling and completion costs, net of joint venture carries
($6,000 ? 6,500)($6,000 ? 6,500)


Note: please refer to footnotes on following page


a) NYMEX natural gas prices have been updated for actual contract prices
through July 2011 and NYMEX oil prices have been updated for actual
contract prices through June 2011.


b) Differentials include effects of natural gas liquids.


c) Excludes expenses associated with noncash stock compensation.


d) Does not include gains or losses on interest rate derivatives.


e) 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.


f) Assumes NYMEX prices of $4.00 to $5.00 per mcf and $100.00 per bbl in
2011 and $5.00 to $6.00 per mcf and $100.00 per bbl in 2012.

Commodity Hedging Activities


Chesapeake enters into natural gas and oil derivative transactions in
order to mitigate a portion of its exposure to adverse market changes in
natural gas and oil prices. The company utilizes the following types of
natural gas and oil derivative instruments:


1)

Swaps: Chesapeake receives a fixed
price and pays a floating market price to the counterparty for the
hedged commodity.


2)

Call options: Chesapeake sells call
options in exchange for a premium from the counterparty. At the
time of settlement, if the market price exceeds the fixed price of
the call option, Chesapeake pays the counterparty such excess and
if the market price settles below the fixed price of the call
option, no payment is due from either party.


3)

Put options: Chesapeake receives a
premium from the counterparty in exchange for the sale of a put
option. At the time of settlement, if the market prices falls
below the fixed price of the put option, Chesapeake pays the
counterparty such shortfall, and if the market price settles above
the fixed price of the put option, no payment is due from either
party.


4)

Knockout swaps: Chesapeake receives a
fixed price and pays a floating market price. The fixed price
received by Chesapeake includes a premium in exchange for the
possibility to reduce the counterparty′s exposure to zero, in any
given month, if the floating market price is lower than certain
pre-determined knockout price.


5)

Basis protection swaps: These
instruments are arrangements that guarantee a price differential
to NYMEX for natural gas from a specified delivery point. For
non-Appalachian Basin basis protection swaps, which typically have
negative differentials to NYMEX, Chesapeake receives a payment
from the counterparty if the price differential is greater than
the stated terms of the contract and pays the counterparty if the
price differential is less than the stated terms of the contract.
For Appalachian Basin basis protection swaps, which typically have
positive differentials to NYMEX, Chesapeake receives a payment
from the counterparty if the price differential is less than the
stated terms of the contract and pays the counterparty if the
price differential is greater than the stated terms of the
contract.


All of our derivative instruments are net settled based on the
difference between the fixed-price payment and the floating-price
payment, resulting in a net amount due to or from the counterparty.


Commodity markets are volatile, and as a result, Chesapeake′s hedging
activity is dynamic. As market conditions warrant, the company may elect
to settle a hedging transaction prior to its scheduled maturity date and
lock in the gain or loss on the transaction. Since the latter half of
2009 through June 2011, the company has taken advantage of attractive
strip prices in 2012 through 2017 and sold natural gas and oil call
options to its counterparties in exchange for 2010, 2011 and 2012
natural gas swaps with strike prices above the then current market
price. This effectively allowed the company to sell out-year volatility
through call options at terms acceptable to Chesapeake in exchange for
natural gas swaps with fixed prices in excess of the market price at the
time.


Gains or losses from commodity derivative transactions are reflected as
adjustments to natural gas and liquids sales. All realized gains
(losses) from natural gas and oil derivatives are included in natural
gas and liquids sales in the month of related production. In accordance
with generally accepted accounting principles, changes in the fair value
of derivative instruments designated as cash flow hedges, to the extent
they are effective in offsetting cash flows attributable to the hedged
risk, are recorded in accumulated other comprehensive income until the
hedged item is recognized in earnings as the physical transactions being
hedged occur. Any change in fair value resulting from ineffectiveness is
currently recognized in natural gas and liquids sales as unrealized
gains (losses). Realized gains (losses) are comprised of settled trades
related to the production periods being reported. Unrealized gains
(losses) are comprised of both temporary fluctuations in the
mark-to-market values of nonqualifying trades and settled values of
nonqualifying derivatives related to future production periods.


At July 28, 2011, the company has the following open natural gas swaps
in place for 2011 and 2012. In addition, the company currently has $630
million of net hedging gains related to closed natural gas contracts and
premiums collected on call options for future production periods.


 ?


 ?

 ?

Open Swaps

(Bcf)

 ?

 ?

Avg. NYMEX


Price of


Open Swaps


 ?

 ?

Forecasted


Natural Gas


Production


(Bcf)


 ?

 ?

Open Swap


Positions


as a % of


Forecasted


Natural Gas


Production


 ?

 ?

Total Gains


(Losses) from


Closed Trades


and Collected


Call Premiums


($millions)


 ?

 ?

Total Gains from


Closed Trades


and Collected


Call Premiums


per mcf of


Forecasted


Natural Gas


Production


Q3 2011

 ?

 ?
200
 ?

 ?
$4.81
 ?

 ?

 ?

 ?

 ?

 ?
$285
 ?

 ?

Q4 2011

 ?

 ?
197
 ?

 ?

 ?
$4.78
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
$250
 ?

 ?

 ?

 ?

 ?

Total 2011

 ?

 ?
397
 ?

 ?

 ?
$4.79
 ?

 ?

 ?
500
 ?

 ?

 ?
79%
 ?

 ?
$535
 ?

 ?

 ?
$1.07

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2012

 ?

 ?
94
 ?

 ?

 ?
$6.12
 ?

 ?

 ?
1,020
 ?

 ?

 ?
9%
 ?

 ?

$
248
 ?

 ?

 ?
$0.24

Total 2013

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
$21
 ?

 ?

 ?

 ?

 ?

Total 2014

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
$(32)
 ?

 ?

 ?

 ?

 ?

Total 2015

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
$(46)
 ?

 ?

 ?

 ?

 ?

Total 2016 ? 2020

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
$(96)
 ?

 ?

 ?

 ?

 ?

 ?


The company currently has the following natural gas written call options
in place for 2011 through 2020:


 ?

 ?

 ?

Call Options

(Bcf)

 ?

 ?

Avg. NYMEX


Strike Price


 ?

 ?

Forecasted


Natural Gas


Production


(Bcf)


 ?

 ?

Call Options


as a % of


Forecasted


Natural Gas


Production


Total 2012

 ?

 ?

161

 ?

 ?

 ?

$

6.54

 ?

 ?

 ?
1,020
 ?

 ?

 ?

16

%

Total 2013

 ?

 ?
415
 ?

 ?

 ?

$

6.44

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2014

 ?

 ?

330

 ?

 ?

 ?

$

6.43

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2015

 ?

 ?

226

 ?

 ?

 ?

$

6.31

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2016 ? 2020

 ?

 ?
393
 ?

 ?

 ?
$7.93
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?


The company has the following natural gas basis protection swaps in
place for 2011 through 2022:


 ?

 ?

Non-Appalachia

 ?

 ?

Appalachia

Volume (Bcf)

 ?

Avg. NYMEX less

Volume (Bcf)

 ?

Avg. NYMEX plus

2011
26
$

0.82
25
$

0.14

2012

51

$

0.78

?

$

?

2013 - 2022

29

 ?

$

0.69

 ?

?

 ?

$

?

Totals
106
 ?

$

0.77

 ?
25
 ?

$

0.14

 ?


At July 28, 2011, the company has the following open crude oil swaps in
place for 2011 and 2012. In addition, the company has $60 million of net
hedging gains related to closed crude oil contracts and premiums
collected on call options for future production periods.


 ?

 ?

 ?

Open


Swaps


(mbbls)


 ?

 ?

Avg. NYMEX


Price of


Open Swaps


 ?

 ?

Forecasted


Liquids


Production


(mbbls)


 ?

 ?

Open Swap


Positions as


a % of


Forecasted


Liquids


Production


 ?

 ?

Total Gains


(Losses) from


Closed Trades


and Collected


Call Premiums


($millions)


 ?

 ?

Total Gains (Losses) from


Closed Trades


and Collected Call


Premiums per bbl


of Forecasted Liquids


Production


Q3 2011

 ?

 ?
828
 ?

 ?
$100.90
 ?

 ?

?

 ?

 ?

?

 ?

 ?
$(17)
 ?

 ?

Q4 2011

 ?

 ?
828
 ?

 ?

 ?
$100.90
 ?

 ?

 ?

?

 ?

 ?

?

 ?

 ?

 ?
$(17)
 ?

 ?

 ?

 ?

 ?

 ?

Total 2011(a)
 ?

 ?
1,656
 ?

 ?

 ?
$100.90
 ?

 ?

 ?
19,000
 ?

 ?
9%
 ?

 ?
$(34)
 ?

 ?

 ?
$(1.80)

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2012(a)
 ?

 ?
1,830
 ?

 ?

 ?
$105.03
 ?

 ?

 ?
55,000
 ?

 ?
3%
 ?

 ?
$82
 ?

 ?

 ?
$1.48
 ?

Total 2013

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

$

6

 ?

 ?

 ?

 ?

 ?

 ?

Total 2014

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
$(197)
 ?

 ?

 ?

 ?

 ?

 ?

Total 2015

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
$145
 ?

 ?

 ?

 ?

 ?

 ?

Total 2016 ? 2020

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?
$58
 ?

 ?

 ?

 ?

 ?

 ?

(a)

Certain hedging contracts include knockout swaps with provisions
limiting the counterparty′s exposure below prices of $60.00 covering
0.6 mmbbls in 2011 and 0.7 mmbbls in 2012.

 ?


The company currently has the following crude oil written call options
in place for 2011 through 2017:


 ?

 ?

 ?

Call Options

(mbbls)

 ?

 ?

Avg. NYMEX


Strike Price


 ?

 ?

Forecasted


Liquids


Production


(mbbls)


 ?

 ?

Call Options


as a % of


Forecasted Liquids


Production


Q3 2011

 ?

 ?

1,840

 ?

 ?

$
110.00
 ?

 ?

 ?

 ?

Q4 2011

 ?

 ?

1,840

 ?

 ?

 ?

$
110.00
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2011

 ?

 ?
3,680
 ?

 ?

 ?

$
110.00
 ?

 ?

 ?
19,000
 ?

 ?

 ?
19%

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2012

 ?

 ?

22,139

 ?

 ?

 ?

$

87.93

 ?

 ?

 ?
55,000
 ?

 ?

 ?
40%

Total 2013

 ?

 ?

14,564

 ?

 ?

 ?

$

87.20

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2014

 ?

 ?

8,707

 ?

 ?

 ?

$

87.72

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2015

 ?

 ?
11,226
 ?

 ?

 ?
$92.00
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

Total 2016 ? 2017

 ?

 ?
14,424
 ?

 ?

 ?

$
89.75
 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?

 ?


Chesapeake Energy Corporation

Jeffrey L. Mobley, CFA, 405-767-4763

jeff.mobley@chk.com

or

John
J. Kilgallon, 405-935-4441

john.kilgallon@chk.com

or

Media
Contact:

Michael Kehs, 405-935-2560

michael.kehs@chk.com

or

Jim
Gipson, 405-935-1310

jim.gipson@chk.com



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