CHESAPEAKE ENERGY CORP - FORM 8-K - EX-99.1 - PRESS RELEASE - NOVEMBER 1, 2012 - November 2, 2012

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Exhibit 99.1

News Release
FOR IMMEDIATE RELEASE
  
NOVEMBER 1, 2012
  

 CHESAPEAKE ENERGY CORPORATION REPORTS FINANCIAL AND
OPERATIONAL RESULTS FOR THE 2012 THIRD QUARTER
 
Company Reports 2012 Third Quarter Net Loss to Common Stockholders of
$2.1 Billion, or $3.19 per Fully Diluted Common Share, on Revenue of $3.0 Billion;
Company Reports Adjusted Net Income Available to Common Stockholders of
$33 Million, or $0.10 per Fully Diluted Common Share, Adjusted Ebitda of
$1.0 Billion and Operating Cash Flow of $1.1 Billion; Adjusted Ebitda Increases
27% Sequentially and Operating Cash Flow Increases 25% Sequentially
 
2012 Third Quarter Average Daily Production Increases 24% Year over Year
and 9% Sequentially to 4.142 Bcfe; Average Daily Liquids Production Increases
51% Year over Year and 10% Sequentially to 143,000 Bbls, or 21% of
Total Production; Average Daily Oil Production Increases
96% Year over Year and 21% Sequentially to 97,800 Bbls
 
OKLAHOMA CITY, OKLAHOMA, NOVEMBER 1, 2012 – Chesapeake Energy Corporation (NYSE:CHK) today announced financial and operational results for the 2012 third quarter.  For the 2012 third quarter, Chesapeake reported a net loss to common stockholders of $2.055 billion ($3.19 per fully diluted common share), ebitda of negative $2.367 billion (defined as net income (loss) before income taxes, interest expense and depreciation, depletion and amortization) and operating cash flow of $1.118 billion (defined as cash flow from operating activities before changes in assets and liabilities) on revenue of $2.970 billion and production of 381 billion cubic feet of natural gas equivalent (bcfe).
 
The company’s 2012 third quarter results include various items that are typically not included in published estimates of the company’s financial results by certain securities analysts.  Excluding such items for the 2012 third quarter, Chesapeake reported adjusted net income to common stockholders of $33 million ($0.10 per fully diluted common share) and adjusted ebitda of $1.021 billion.  The primary excluded items from the 2012 third quarter reported results are the following:

·  
a noncash after-tax impairment charge of $2.022 billion related to the carrying value of natural gas and oil properties (primarily resulting from a 10% decrease in trailing 12-month average first-day-of-the-month natural gas prices as of September 30, 2012, compared to June 30, 2012, and the impairment of certain undeveloped leasehold, primarily in the Williston and DJ Basins);
·  
an unrealized noncash after-tax mark-to-market loss of $63 million resulting from the company’s natural gas, oil and natural gas liquids (NGL) and interest rate hedging programs;
·  
an after-tax charge of $28 million related to losses on sales and impairments of certain fixed assets and other; and
·  
a net after-tax gain of $19 million related to the sale of an investment.
 
CHESAPEAKE CONTACTS:
  
MEDIA CONTACTS: 
  
CHESAPEAKE ENERGY CORPORATION
Jeffrey L. Mobley, CFA
  
John J. Kilgallon
  
Michael Kehs
  
Jim Gipson
  
 6100 North Western Avenue
(405) 767-4763
  
(405) 935-4441
  
(405) 935-2560
  
(405) 935-1310
  
 P.O. Box 18496
jeff.mobley@chk.com
  
john.kilgallon@chk.com
  
michael.kehs@chk.com
  
jim.gipson@chk.com
  
 Oklahoma City, OK 73154
 
 
 
 
A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 19 – 22 of this release.
 
Key Operational and Financial Statistics Summarized
 
The table below summarizes Chesapeake’s key results during the 2012 third quarter and compares them to results during the 2012 second quarter and the 2011 third quarter.
 
Three Months Ended
  
 
9/30/12
  
6/30/12
  
9/30/11
  
Average daily production (in mmcfe)(a)
4,142
  
3,808
  
3,329
  
Natural gas equivalent production (in bcfe)
381
  
347
  
306
  
Natural gas equivalent realized price ($/mcfe)(b)
4.04
  
3.77
  
5.78
  
Oil production (in mbbls)
8,996
  
7,325
  
4,589
  
Average realized oil price ($/bbl)(b)
90.79
  
91.58
  
82.47
  
Oil as % of total production
14
  
13
  
9
  
NGL production (in mbbls)
4,130
  
4,525
  
4,080
  
Average realized NGL price ($/bbl)(b)
31.22
  
25.94
  
41.16
  
NGL as % of total production
7
  
8
  
8
  
Liquids as % of realized revenue(c)
61
  
60
  
31
  
Liquids as % of unhedged revenue(c)
63
  
70
  
40
  
Natural gas production (in bcf)
302
  
275
  
254
  
Average realized natural gas price ($/mcf)(b)
1.97
  
1.88
  
4.82
  
Natural gas as % of total production
79
  
79
  
83
  
Natural gas as % of realized revenue
39
  
40
  
69
  
Natural gas as % of unhedged revenue
37
  
30
  
60
  
Marketing, gathering and compression net margin ($/mcfe)(d)
0.11
  
0.05
  
0.10
  
Oilfield services net margin ($/mcfe)(d)
0.09
  
0.14
  
0.11
  
Production expenses ($/mcfe)
(0.84)
  
(0.97)
  
(0.92)
 
Production taxes ($/mcfe)
(0.14)
  
(0.12)
  
(0.16)
 
General and administrative costs ($/mcfe)(e)
(0.34)
  
(0.39)
  
(0.41)
 
Stock-based compensation ($/mcfe)
(0.05)
  
(0.06)
  
(0.08)
 
DD&A of natural gas and liquids properties ($/mcfe)(f)
(2.00)
  
(1.70)
  
(1.38)
 
D&A of other assets ($/mcfe)(g)
(0.17)
  
(0.24)
  
(0.24)
 
Interest expense ($/mcfe)(b)
(0.10)
  
(0.06)
  
(0.01)
 
Operating cash flow ($ in millions)(h)
1,118
  
895
  
1,409
  
Operating cash flow ($/mcfe)
2.93
  
2.58
  
4.60
  
Adjusted ebitda ($ in millions)(i)
1,021
  
803
  
1,385
  
Adjusted ebitda ($/mcfe)
2.68
  
2.32
  
4.52
  
Net income (loss) to common stockholders ($ in millions)
(2,055)
  
929
  
879
  
Earnings (loss) per share – diluted ($)
(3.19)
  
1.29
  
1.23
  
Adjusted net income to common stockholders ($ in millions)(j)
33
  
3
  
496
  
Adjusted earnings per share – diluted ($)
0.10
  
0.06
  
0.72
  
             
See footnotes on the following page
 
 
 
 
(a)  
Includes the effect of VPP #10 sale in March 2012 (which had an average production loss impact of approximately 100 mmcfe and 115 mmcfe per day in the 2012 third and second quarters, respectively).  Also includes the effect of net natural gas production curtailments of approximately 30 bcf in the 2012 second quarter, or an average of approximately 330 mmcf per day.
(b)  
Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging.
(c)  
“Liquids” includes both oil and NGL.
(d)  
Includes revenue and operating costs and excludes depreciation and amortization of other assets.
(e)  
Excludes expenses associated with noncash stock-based compensation.
(f)  
Increase from 2012 second quarter due to an increase in the amortizable base resulting from leasehold impairments and expirations in addition to a further decrease in estimated proved reserves resulting from lower natural gas prices.
(g)  
Decrease from 2012 second quarter due to approximately $2.4 billion of fixed assets held for sale throughout the 2012 third quarter. Assets classified as held for sale are not subject to depreciation.
(h)  
Defined as cash flow provided by operating activities before changes in assets and liabilities.
(i)  
Defined as net income (loss) before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 21.
(j)  
Defined as net income (loss) available to common stockholders, as adjusted to remove the effects of certain items detailed on page 22.

2012 Third Quarter Average Daily Production Increases 24% Year over Year
and 9% Sequentially to 4.142 Bcfe; Average Daily Liquids Production Increases
51% Year over Year and 10% Sequentially to 143,000 Bbls, or 21% of
Total Production; Average Daily Oil Production Increases
96% Year over Year and 21% Sequentially to 97,800 Bbls
 
Chesapeake’s daily production for the 2012 third quarter averaged 4.142 bcfe, an increase of 24% from the average 3.329 bcfe produced per day in the 2011 third quarter and an increase of 9% from the average 3.808 bcfe produced per day in the 2012 second quarter.  Chesapeake’s average daily production of 4.142 bcfe for the 2012 third quarter consisted of approximately 3.286 billion cubic feet (bcf) of natural gas (79% on a natural gas equivalent basis) and approximately 142,675 barrels (bbls) of liquids, consisting of approximately 97,785 bbls of oil (14% on a natural gas equivalent basis) and approximately 44,890 bbls of NGL (7% on a natural gas equivalent basis) (oil and NGL collectively referred to as “liquids”).
 
For the 2012 third quarter, the company’s year-over-year growth rate of natural gas production was 19%, or approximately 523 million cubic feet (mmcf) per day, and its year-over-year growth rate of liquids production was 51%, or approximately 48,450 bbls per day.  Chesapeake’s year-over-year liquids production growth consisted of oil production growth of 96%, or approximately 47,900 bbls per day, and NGL production growth of 1%, or approximately 550 bbls per day. NGL production for the 2012 third quarter was reduced by approximately 467,000 bbls, or 5,075 bbls per day, due to the company’s election in certain basins to reject rather than process ethane, which was additive to natural gas production.
 
As a result of redirecting its drilling program from dry gas plays to liquids-rich plays, Chesapeake is projecting its natural gas production to decline approximately 7% in 2013 and is projecting its liquids production to increase approximately 29% in 2013.  Management and the board of directors continue to review operational plans for 2013 and beyond, which could result in changes to the company’s drilling activity and projected production levels in 2013.
 
Average Realized Prices and Hedging Results and Positions Detailed
 
Average prices realized during the 2012 third quarter (including realized gains or losses from natural gas, oil and NGL derivatives and excluding unrealized gains or losses on such derivatives) were $1.97 per thousand cubic feet (mcf) of natural gas, $90.79 per bbl of oil and
 
 
 
 
$31.22 per bbl of NGL, for a realized natural gas equivalent price of $4.04 per thousand cubic feet of natural gas equivalent (mcfe).  Realized gains from natural gas, oil and NGL hedging activities during the 2012 third quarter generated a $0.17 gain per mcf of natural gas, a $2.72 gain per bbl of oil and a negligible loss per bbl of NGL for a 2012 third quarter realized hedging gain of $77 million, or $0.20 per mcfe.
 
By comparison, average prices realized during the 2011 third quarter (including realized gains or losses from natural gas, oil and NGL derivatives and excluding unrealized gains or losses on such derivatives) were $4.82 per mcf of natural gas, $82.47 per bbl of oil and $41.16 per bbl of NGL, for a realized natural gas equivalent price of $5.78 per mcfe.  Realized gains from natural gas, oil and NGL hedging activities during the 2011 third quarter generated a $1.43 gain per mcf of natural gas, a $1.71 loss per bbl of oil and a $2.88 loss per bbl of NGL for a 2011 third quarter realized hedging gain of $344 million, or $1.12 per mcfe.  The company’s realized cash hedging gains since January 1, 2006, have been $8.8 billion, or $1.39 per mcfe.
 
The following table summarizes Chesapeake’s 2012 and 2013 open natural gas and oil swap positions as of November 1, 2012.  Depending on changes in natural gas and oil futures markets and management’s view of underlying supply and demand trends, Chesapeake may increase or decrease some or all of its hedging positions at any time in the future without notice.
 
   
Natural Gas
  
Oil
Year
  
% of Forecasted
Production
  
NYMEX
Natural Gas
  
% of Forecasted
Production
  
NYMEX
Oil WTI
4Q 2012
  
76%
  
$3.06
  
76%
  
$99.14
2013
  
—
  
—
  
69%
  
$96.01
 
Details of the company’s quarter-end hedging positions will be provided in the company’s Form 10-Q filing with the Securities and Exchange Commission (SEC), and current positions are disclosed in summary format in management’s Outlook dated November 1, 2012, which is attached to this release as Schedule “A,” beginning on page 24.  The Outlook has been updated from the Outlook dated August 6, 2012, attached as Schedule “B,” which begins on page 27, to reflect various updated information.  Management and the board of directors are currently reviewing operational plans for 2013 and beyond, which could result in changes to the Outlook attached as Schedule “A.”
 
During 2012 First Three Quarters, Company Adds New Net Proved Reserves of 3.9 Tcfe
through the Drillbit; Total Proved Reserves Decrease 14% to 16.2 Tcfe,
or 2.7 Bboe, Due to Downward Price-Related Revisions and Net Divestitures
 
The company's September 30, 2012, proved reserves were 16.2 trillion cubic feet of natural gas equivalent (tcfe), or 2.7 billion barrels of oil equivalent (bboe), a 14% decrease from year-end 2011.  Chesapeake added 3.9 tcfe, or 650 million barrels of oil equivalent (mmboe), of new proved reserves (net of 596 bcfe of non-price related revisions) through the drillbit at a drilling and completion cost of $1.92 per mcfe, or $11.52 per barrel of oil equivalent (boe) during the first three quarters of 2012. Primarily as a result of lower U.S. natural gas prices, the company also recorded downward revisions of 4.9 tcfe, or 810 mmboe, during the first three quarters of
 
 
 
 
2012, largely associated with the removal of proved undeveloped reserves (PUDs) in the company’s Barnett and Haynesville Shale plays.  Additionally, during this period, Chesapeake recorded net divestitures of 507 bcfe, or 85 mmboe.
 
The following table presents Chesapeake’s September 30, 2012 proved reserves, estimated future net cash flows from proved reserves (discounted at an annual rate of 10% before income taxes (PV-10)) and proved developed percentage, each calculated based on the trailing 12-month average price required under SEC rules and the 10-year average NYMEX strip prices as of September 30, 2012.  Additional information regarding the SEC case can be found on page 16.

Pricing Method
 
Natural Gas
Price
($/mcf)
 
 
Oil Price
($/bbl)
Proved
Reserves
(tcfe)
 
PV-10
(billions)
Proved
Developed
Percentage
Trailing 12-month avg (SEC)(a)
$2.83
$95.05
16.2
$18.5
59%
9/30/12 10-year avg NYMEX strip(b)
$4.80
$88.58
22.2
$29.5
52%
 
a)  
Reserve volumes estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of September 30, 2012.  This pricing yields estimated proved reserves for SEC reporting purposes.
b)  
Natural gas and oil volumes estimated under the 10-year average NYMEX strip reflect an alternative pricing scenario that illustrates the sensitivity of proved reserves to a different pricing assumption.  Futures prices represent an unbiased consensus estimate by market participants about the likely prices to be received for future production.  Management believes that 10-year average NYMEX strip prices provide a better indicator of the likely economic producibility of the company’s proved reserves than the historical 12-month average price.

Company Achieves Strong Operational Results in its Liquids-Rich Plays with Daily
Liquids Production Increasing 51% Year over Year and 10% Sequentially, Led by
410% Year-over-Year and 43% Sequential Liquids Production Growth in its Eagle Ford
Shale Play; Oil Production Comprised 69% of Total Liquids Production in the
2012 Third Quarter and Increased 96% Year over Year and 21% Sequentially
 
Since 2000, Chesapeake has built a leading position in 10 of what it believes are the Top 15 unconventional plays in the U.S. – the Eagle Ford Shale in South Texas; the Marcellus Shale in Pennsylvania and West Virginia; the Utica Shale in Ohio, West Virginia and Pennsylvania; the Granite Wash, Cleveland, Tonkawa and Mississippi Lime plays in the Anadarko Basin in Oklahoma and the Texas Panhandle; the Haynesville/Bossier shales in western Louisiana and East Texas; the Barnett Shale in North Texas; and the Niobrara Shale in the Powder River Basin in Wyoming.  These 10 plays represent Chesapeake’s core assets and will be the nearly exclusive focus of the company’s future drilling efforts.
 
During the past four years, Chesapeake has substantially shifted its drilling and completion activity to liquids-rich plays in response to strong U.S. oil and NGL prices and relatively weak U.S. natural gas prices.  During 2012 and 2013, the company projects that approximately 85% and 88%, respectively, of its total drilling and completion capital expenditures will be invested in liquids-rich plays.
 
The company continues to achieve strong operational results in its liquids-rich plays, as highlighted below:
 
 
 
 
Eagle Ford Shale (South Texas):  Chesapeake’s activities on its approximately 490,000 net acres of leasehold in the Eagle Ford Shale in South Texas continue to drive strong results, yielding net production of 52,200 boe per day (120,500 gross operated boe per day) for the 2012 third quarter.  This represents an increase of 371% year over year and 44% sequentially, which included an increase in oil production of 462% year over year and 48% sequentially.  Approximately 68% of total Eagle Ford production during the 2012 third quarter was oil, 14% was NGL and 18% was natural gas.
 
As of September 30, 2012, Chesapeake had 441 gross company operated producing wells in the Eagle Ford play, which included 124 wells that reached first production in the 2012 third quarter, compared to 121 in the 2012 second quarter and 40 in the 2011 third quarter.  Also, as of September 30, 2012, Chesapeake had approximately 233 Eagle Ford wells drilled, but not yet producing, that were in various stages of completion and/or waiting on pipeline connection.  Recent efficiency gains in drilling cycle times will allow the company to achieve its targeted well count goal utilizing fewer rigs than would have been required in 2010-12.  The company is currently operating 23 rigs in the play, down from a peak of 34 rigs in April 2012 and plans to exit the year at 22 rigs.  The company is currently on pace to have essentially all of its core and Tier 1 Eagle Ford acreage held by production by the 2013 fourth quarter.
 
Of the 124 wells which commenced first production in the 2012 third quarter, 115 wells (or 93%) had peak production rates of more than 500 boe per day, including 43 wells (or 35%) with peak rates of more than 1,000 boe per day, continuing a trend of steady operational improvement during the past year.  Three notable recent wells completed by Chesapeake in the Eagle Ford during the quarter are as follows:

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

As part of its “core of the core” strategy, Chesapeake is currently pursuing the sale of a portion of its existing leasehold and producing assets outside its current core development area in the Eagle Ford play.
 
Utica Shale (eastern Ohio): Chesapeake continues to focus on developing the core wet gas window of the Utica Shale in eastern Ohio, a play in which the company holds approximately 1.3 million net acres of leasehold, the industry’s largest position.  As of September 30, 2012, Chesapeake has drilled a total of 134 wells in the Utica play, which include 32 producing wells and 37 additional wells waiting on pipeline connection, with the other 65 wells in various stages
 
 
 
 
of completion.  Chesapeake is currently operating 13 rigs in the Utica play.  Production from the Utica play is growing only moderately at this time because of the time and capital needed to build out gas processing and pipeline takeaway infrastructure.  The company expects a much larger contribution to production growth from the Utica in 2013 and beyond as midstream constraints are reduced.
 
Three notable recent wells completed by Chesapeake in the Utica during the quarter are as follows:

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

In December 2011, Chesapeake entered into a joint venture with Total to develop a portion of the Utica play.  As of September 30, 2012, the company’s remaining drilling carry from Total was approximately $1.25 billion.  Chesapeake anticipates using 100% of the remaining carry by year-end 2014, and the carry will pay for 60% of Chesapeake’s drilling costs during that time.
 
Marcellus Shale (Pennsylvania, West Virginia):  With approximately 1.8 million net acres, Chesapeake is the industry’s largest leasehold owner in the Marcellus Shale play, which spans from northern West Virginia across much of Pennsylvania into southern New York.
 
During the 2012 third quarter, Chesapeake’s average daily net production in the northern dry gas portion of the Marcellus play was 540 mmcfe per day (1,229 gross operated mmcfe per day), an increase of 159% year over year and 9% sequentially.  Chesapeake has reduced its operated rig count to five rigs in the northern dry gas portion of the Marcellus and anticipates maintaining that level of activity for the remainder of 2012.
 
Three notable recent wells completed by Chesapeake in the northern dry gas portion of the Marcellus during the quarter are as follows:

·  
The Linski S Bra 4H in Bradford County, PA achieved a peak rate of 8.4 mmcf of natural gas per day;
·  
The Folta N Bra 2H in Bradford County, PA achieved a peak rate of 8.4 mmcf of natural gas per day; and
·  
The Champluvier 2H in Bradford County, PA achieved a peak rate of 8.3 mmcf of natural gas per day.
 
 
 
 
During the 2012 third quarter, Chesapeake’s average daily net production in the southern wet gas portion of the play was approximately 125 mmcfe per day (206 gross operated mmcfe per day).  Chesapeake is currently drilling with three operated rigs in the southern wet gas portion of the Marcellus and anticipates maintaining that level of activity for the remainder of 2012.
 
Three notable recent wells completed by Chesapeake in the southern wet gas portion of the Marcellus during the quarter are as follows:

·  
The Roy Ferrell 8H in Ohio County, WV achieved an initial test rate of approximately 1,525 boe per day, consisting of 5.3 mmcf of natural gas, 220 bbls of oil and 430 bbls of NGL per day;
·  
The Deborah Craig 3H in Ohio County, WV achieved an initial test rate of approximately 830 boe per day, consisting of 2.6 mmcf of natural gas, 200 bbls of oil and 205 bbls of NGL per day; and
·  
The George Gantzer 8H in Ohio County, WV achieved an initial test rate of approximately 800 boe per day, consisting of 2.7 mmcf of natural gas, 130 bbls of oil and 220 bbls of NGL per day.
 
Mississippi Lime (northern Oklahoma, southern Kansas):  Chesapeake’s approximate 2.0 million net acres of leasehold is the industry’s largest position in the Mississippi Lime play in northern Oklahoma and southern Kansas.  Production for the 2012 third quarter averaged approximately 25,000 boe per day (30,100 gross operated boe per day), up 211% year over year and 25% sequentially.  Approximately 41% of total Mississippi Lime production during the 2012 third quarter was oil, 10% was NGL and 49% was natural gas.  As of September 30, 2012, Chesapeake had 227 producing wells in the Mississippi Lime play, which included 73 wells that reached first production in the 2012 third quarter, compared to 49 in the 2012 second quarter and 11 in the 2011 third quarter.  Also, as of September 30, 2012, Chesapeake had approximately 55 wells drilled, but not yet producing, that were in various stages of completion and/or waiting on pipeline connection.  Chesapeake is currently operating nine rigs in the Mississippi Lime play.
 
Three notable recent wells completed by Chesapeake in the Mississippi Lime during the quarter are as follows:

·  
The Herold 3-28-15 1H in Woods County, OK achieved a peak rate of approximately 2,025 boe per day, which included 1,740 bbls of oil, 100 bbls of NGL and 1.1 mmcf of natural gas per day;
·  
The Rauh 3-26-12 1H in Alfalfa County, OK achieved a peak rate of approximately 2,020 boe per day, which included 1,210 bbls of oil, 225 bbls of NGL and 3.5 mmcf of natural gas per day; and
·  
The Hada Land & Cattle 3-28-15 1H in Woods County, OK achieved a peak rate of approximately 1,405 boe per day, which included 1,150 bbls of oil, 90 bbls of NGL and 1.0 mmcf of natural gas per day.
 
 
 
 
Chesapeake continues to pursue a joint venture and/or sale of a portion of its Mississippi Lime leasehold and expects to announce a transaction by year-end 2012.
 
Cleveland and Tonkawa Tight Sand (western Oklahoma, Texas Panhandle): Chesapeake owns approximately 520,000 net acres of leasehold in the Cleveland play and 285,000 net acres in the Tonkawa play in western Oklahoma and the Texas Panhandle, which it believes is the industry’s largest position in the combined plays.  Production from both plays for the 2012 third quarter averaged 24,100 boe per day (31,700 gross operated boe per day), up 75% year over year and 13% sequentially.  Approximately 45% of total Cleveland and Tonkawa production during the quarter was oil, 17% was NGL and 38% was natural gas.  The company is currently operating 12 rigs in the two plays.
 
Three notable wells completed by Chesapeake in the Cleveland Sand during the quarter are as follows:

·  
The Sloan HMH 1H in Hemphill County, TX achieved a peak rate of approximately 1,345 boe per day, which included 360 bbls of oil, 400 bbls of NGL and 3.5 mmcf of natural gas per day;
·  
The Larry Imke 9-19-25 1H in Ellis County, OK achieved a peak rate of approximately 1,035 boe per day, which included 640 bbls of oil, 145 bbls of NGL and 1.5 mmcf of natural gas per day; and
·  
The Mathers 131 HMH 1H in Hemphill County, TX achieved a peak rate of approximately 920 boe per day, which included 745 bbls of oil, 75 bbls of NGL and 0.6 mmcf of natural gas per day.
 
Three notable wells completed by Chesapeake in the Tonkawa Sand during the quarter are as follows:

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

Granite Wash and Hogshooter Tight Sand (western Oklahoma, Texas Panhandle): Chesapeake owns approximately 190,000 net acres of leasehold in the Granite Wash play and 30,000 net acres in the Hogshooter play in western Oklahoma and the Texas Panhandle, which it believes is the industry’s largest position in the combined plays.  Production for the 2012 third quarter averaged 47,750 boe per day (95,800 gross operated boe per day), up 2% sequentially.  Approximately 28% of total Granite Wash and Hogshooter production during the quarter was oil,
 
 
 
 
22% was NGL and 50% was natural gas.  The company is currently operating 10 rigs in the two plays.

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

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

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

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

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

·  
The Wallis 23-33-71 A 3H in Converse County, WY achieved a peak rate of approximately 1,990 boe per day, which included 1,105 bbls of oil, 385 bbls of NGL and 3.0 mmcf of natural gas per day;
·  
The York Ranch 26-33-70 A 1H in Converse County, WY achieved a peak rate of approximately 1,750 boe per day, which included 745 bbls of oil, 440 bbls of NGL and 3.4 mmcf of natural gas per day; and
·  
The Clausen Ranch 25-34-71 ST A 1H in Converse County, WY achieved a peak rate of approximately 1,720 boe per day, which included 1,075 bbls of oil, 280 bbls of NGL and 2.2 mmcf of natural gas per day.
 
In February 2011, Chesapeake entered into a joint venture with CNOOC to develop the Niobrara play.  As of September 30, 2012, the company’s remaining drilling carry from CNOOC was approximately $480 million.  Chesapeake anticipates using 100% of the remaining carry by year-end 2014, and the carry will pay for 67% of Chesapeake’s drilling costs during that time.
 
Management Comments
 
Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, said, “We are pleased to report our liquids production continues its impressive growth, led by a 96% year-over-year and 21% sequential increase in our oil production.  Three years ago when Chesapeake was producing only 33,000 bbls per day of liquids, we embarked on a strategy to transform our asset base from one focused almost exclusively on natural gas to one that would provide more balance between liquids and natural gas production and that would likely also lead to higher returns on capital.  Our current liquids production now exceeds 140,000 bbls per day, even after excluding 21,000 bbls per day recently sold in the Permian transactions.  We believe the company remains on target to reach our goal of 250,000 bbls per day of net liquids production in 2015.
 
“I am also pleased to see our 2012 third quarter adjusted ebitda and operating cash flow increase 27% and 25% sequentially, respectively.  Improving natural gas market fundamentals, combined with our increasing liquids production, the completion of our 2012-13 asset sales program and our long-term debt reduction to below $9.5 billion, should enable Chesapeake to continue making significant financial progress in the 2012 fourth quarter and in 2013 as well.”
 
2012 Third Quarter Financial and Operational Results Conference Call Information
 
A conference call to discuss this release has been scheduled for Friday, November 2, 2012 at 9:00 am EDT.  The telephone number to access the conference call is 913-312-0381 or toll-free 888-778-8907.  The passcode for the call is 8299445.  We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EDT. For those unable to participate in the conference call, a replay will be available for audio playback at 1:00 pm EDT on Friday, November 2, 2012 and will run through midnight Friday, November 16, 2012.  The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112.  The passcode for the replay is 8299445.  The conference call will also be webcast live on Chesapeake’s website at www.chk.com in the “Events” subsection of the “Investors” section of the company’s website.  The webcast of the conference will be available on the company’s website for one year.

 
 
 
 
This news release and the accompanying Outlooks include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  Forward-looking statements are statements other than statements of historical fact that give our current expectations or forecasts of future events.  They include estimates of natural gas and oil reserves, projected production, estimates of operating costs, planned development drilling and use of joint venture drilling carries,  effects of anticipated asset sales, projected cash flow and liquidity, business strategy and other plans and objectives for future operations.  Disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date.  These market prices are subject to significant volatility.  We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this news release, and we undertake no obligation to update this information.
 
Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in Item 1A of our 2011 annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on February 29, 2012.  These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; the availability of capital on an economic basis, including through planned asset sales, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the amount and timing of development expenditures; inability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas and oil sales; the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; general economic conditions negatively impacting us and our business counterparties; oilfield services shortages and transportation capacity constraints and interruptions that could adversely affect our cash flow; and losses possible from pending or future litigation.  We do not have binding agreements for all of our planned 2012 asset sales. Our ability to consummate each of these transactions is subject to changes in market conditions and other factors. If one or more of the transactions is not completed in the anticipated time frame or at all or for less proceeds than anticipated, our ability to fund budgeted capital expenditures, reduce our indebtedness as planned and maintain our compliance with bank revolving credit agreement covenants could be adversely affected.
 
Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity.  Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct.  They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.
 
Chesapeake Energy Corporation (NYSE:CHK) is the second-largest producer of natural gas, a Top 15 producer of oil and natural gas liquids and the most active driller of new wells in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S. Chesapeake owns leading positions in the Eagle Ford, Utica, Granite Wash, Cleveland, Tonkawa, Mississippi Lime and Niobrara unconventional liquids plays and in the Marcellus, Haynesville/Bossier and Barnett natural gas shale plays. The company has also vertically integrated its operations and owns substantial marketing, midstream and oilfield services businesses directly and indirectly through its subsidiaries Chesapeake Energy Marketing, Inc., Chesapeake Midstream Development, L.P. and COS Holdings, L.L.C.  Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.
 
 
 
 
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per-share and unit data)
(unaudited)

 
September 30,
2012
  
September 30,
2011
  
THREE MONTHS ENDED:
    
 
$
  
$/mcfe
  
$
  
$/mcfe
  
REVENUES:
                        
Natural gas, oil and NGL
  
1,437
    
3.77
    
2,402
    
7.84
  
Marketing, gathering and compression
  
1,381
    
3.62
    
1,422
    
4.64
  
Oilfield services
  
152
    
0.40
    
153
    
0.50
  
Total Revenues
  
2,970
    
7.79
    
3,977
    
12.98
  
                         
OPERATING EXPENSES:
                        
Natural gas, oil and NGL production
  
320
    
0.84
    
282
    
0.92
  
Production taxes
  
53
    
0.14
    
50
    
0.16
  
Marketing, gathering and compression
  
1,339
    
3.51
    
1,392
    
4.55
  
Oilfield services
  
116
    
0.30
    
118
    
0.39
  
General and administrative
  
148
    
0.39
    
151
    
0.49
  
Natural gas, oil and NGL depreciation, depletion and amortization
  
762
    
2.00
    
423
    
1.38
  
Depreciation and amortization of other assets
  
66
    
0.17
    
75
    
0.24
  
Impairment of natural gas and oil properties
  
3,315
    
8.70
    
—
    
—
  
Losses on sales and impairments of fixed assets and other
  
45
    
0.12
    
3
    
0.01
  
Total Operating Expenses
  
6,164
    
16.17
    
2,494
    
8.14
  
                         
INCOME (LOSS) FROM OPERATIONS
  
(3,194)
 
  
(8.38)
 
  
1,483
    
4.84
  
                         
OTHER INCOME (EXPENSE):
                        
Interest expense
  
(36)
 
  
(0.10)
 
  
(4)
 
  
(0.01)
 
Earnings (losses) on investments
  
(23)
 
  
(0.06)
 
  
28
    
0.09
  
Gain on sale of investment
  
31
    
0.08
    
—
    
—
  
Other income
  
(9)
 
  
(0.02)
 
  
4
    
0.01
  
Total Other Income (Expense)
  
(37)
 
  
(0.10)
 
  
28
    
0.09
  
                         
INCOME (LOSS) BEFORE INCOME TAXES
  
(3,231)
 
  
(8.48)
 
  
1,511
    
4.93
  
                         
INCOME TAX EXPENSE (BENEFIT):
                        
Current income taxes
  
22
    
0.05
    
(1)
 
  
—
  
Deferred income taxes
  
(1,282)
 
  
(3.36)
 
  
590
    
1.92
  
Total Income Tax Expense (Benefit)
  
(1,260)
 
  
(3.31)
 
  
589
    
1.92
  
                         
NET INCOME (LOSS)
  
(1,971)
 
  
(5.17)
 
  
922
    
3.01
  
                         
Net income attributable to noncontrolling interests
  
(41)
 
  
(0.11)
 
  
—
    
—
  
                         
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
  
(2,012)
 
  
(5.28)
 
  
922
    
3.01
  
                         
Preferred stock dividends
  
(43)
 
  
(0.11)
 
  
(43)
 
  
(0.14)
 
                         
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS
 
(2,055)
 
  
(5.39)
 
  
879
    
2.87
  
                         
EARNINGS (LOSS) PER COMMON SHARE:
                        
Basic
$
(3.19)
 
      
$
1.38
        
                         
Diluted
$
(3.19)
 
      
$
1.23
        
                         
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
                        
Basic
  
644
          
638
        
                         
Diluted
  
644
          
753
        
 
 
 
 
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per-share and unit data)
(unaudited)

 
September 30,
2012
  
September 30,
2011
  
NINE MONTHS ENDED:
    
 
$
  
$/mcfe
  
$
  
$/mcfe
  
REVENUES:
                        
Natural gas, oil and NGL
  
4,622
    
4.36
    
4,688
    
5.43
  
Marketing, gathering and compression
  
3,710
    
3.50
    
3,844
    
4.45
  
Oilfield services
  
446
    
0.42
    
376
    
0.44
  
Total Revenues
  
8,778
    
8.28
    
8,908
    
10.32
  
                         
OPERATING EXPENSES:
                        
Natural gas, oil and NGL production
  
1,005
    
0.95
    
782
    
0.91
  
Production taxes
  
141
    
0.13
    
140
    
0.16
  
Marketing, gathering and compression
  
3,631
    
3.43
    
3,744
    
4.34
  
Oilfield services
  
321
    
0.30
    
287
    
0.33
  
General and administrative
  
440
    
0.41
    
410
    
0.47
  
Natural gas, oil and NGL depreciation, depletion and amortization
  
1,856
    
1.75
    
1,147
    
1.33
  
Depreciation and amortization of other assets
  
233
    
0.22
    
206
    
0.24
  
Impairment of natural gas and oil properties
  
3,315
    
3.13
    
—
    
—
  
Losses on sales and impairments of fixed assets and other
  
286
    
0.27
    
7
    
0.01
  
Total Operating Expenses
  
11,228
    
10.59
    
6,723
    
7.79
  
                         
INCOME (LOSS) FROM OPERATIONS
  
(2,450)
 
  
(2.31)
 
  
2,185
    
2.53
  
                         
OTHER INCOME (EXPENSE):
                        
Interest expense
  
(63)
 
  
(0.06)
 
  
(37)
 
  
(0.04)
 
Earnings (losses) on investments
  
(87)
 
  
(0.08)
 
  
100
    
0.11
  
Gain on sales of investments
  
1,061
    
1.00
    
—
    
—
  
Losses on purchases or exchanges of debt
  
—
    
—
    
(176)
 
  
(0.20)
 
Other income
  
2
    
—
    
9
    
0.01
  
Total Other Income (Expense)
  
913
    
0.86
    
(104)
 
  
(0.12)
 
                         
INCOME (LOSS) BEFORE INCOME TAXES
  
(1,537)
 
  
(1.45)
 
  
2,081
    
2.41
  
                         
INCOME TAX EXPENSE (BENEFIT):
                        
Current income taxes
  
24
    
0.02
    
11
    
0.01
  
Deferred income taxes
  
(623)
 
  
(0.59)
 
  
801
    
0.93
  
Total Income Tax Expense (Benefit)
  
(599)
 
  
(0.57)
 
  
812
    
0.94
  
                         
NET INCOME (LOSS)
  
(938)
 
  
(0.88)
 
  
1,269
    
1.47
  
                         
Net income attributable to noncontrolling interests
  
(131)
 
  
(0.13)
 
  
—
    
—
  
                         
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
  
(1,069
)
  
(1.01)
 
  
1,269
    
1.47
  
                         
Preferred stock dividends
  
(128)
 
  
(0.12)
 
  
(128)
 
  
(0.15)
 
                         
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS
  
(1,197)
 
  
(1.13)
 
  
1,141
    
1.32
  
                         
EARNINGS (LOSS) PER COMMON SHARE:
                        
Basic
$
(1.86)
 
      
$
1.79
        
                         
Diluted
$
(1.86)
 
      
$
1.69
        
                         
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
                        
Basic
  
643
          
636
        
                         
Diluted
  
643
          
752
        
 
 
 
 
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)

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

 
September 30,
December 31,
 
2012
2011
     
Total debt, net of unrestricted cash
$
16,076
  
$
10,275
  
Chesapeake stockholders' equity
  
15,327
    
16,624
  
Noncontrolling interests(a)
  
2,364
    
1,337
  
Total
$
33,767
  
$
28,236
  
             
Debt to capitalization ratio
  
48
%
  
36
%
 
(a)  
Includes third-party ownership as follows:
        CHK Cleveland Tonkawa, L.L.C.
$
1,015
  
$
—
  
        CHK Utica, L.L.C.
  
950
    
950
  
        Chesapeake Granite Wash Trust
  
365
    
380
  
        Cardinal Gas Services, L.L.C.
  
34
    
7
  
             Total
$
2,364
  
$
1,337
  
 
 
 
 
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF 2012 CHANGES TO NATURAL GAS AND OIL PROPERTIES
BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AS OF SEPTEMBER 30, 2012
($ in millions, except per-unit data)
(unaudited)
 
   
Proved Reserves
  
   
Cost
    
Bcfe(a)
    
$/Mcfe
  
PROVED PROPERTIES:
                        
Well costs on proved properties (b) (c)
  
$
7,430
      
3,878
(d)
  
1.92
  
Acquisition of proved properties(e)
    
319
      
37
      
8.67
  
Sale of proved properties
    
(1,322)
 
    
(544)
 
    
2.43
  
Total net proved properties
    
6,427
      
3,371
      
1.91
  
                         
Revisions – price
    
—
      
(4,878)
 
    
—
  
                         
UNPROVED PROPERTIES:
                        
   Well costs on unproved properties(f)
    
(195)
 
    
—
      
—
  
Acquisition of unproved properties, net(g)
    
1,628
      
—
      
—
  
Sale of unproved properties
    
(930)
 
    
—
      
—
  
Total net unproved properties
    
503
      
—
      
—
  
                         
OTHER:
                        
Capitalized interest on unproved properties
    
766
      
—
      
—
  
Geological and geophysical costs
    
148
      
—
      
—
  
Asset retirement obligations
    
16
      
—
      
—
  
Total other
    
930
      
—
      
—
  
                         
Total
  
$
7,860
      
(1,507)
 
    
—
  
 
CHESAPEAKE ENERGY CORPORATION
ROLL-FORWARD OF PROVED RESERVES
NINE MONTHS ENDED SEPTEMBER 30, 2012
BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AS OF SEPTEMBER 30, 2012
 (unaudited)
   
Bcfe(a)
  
       
Beginning balance, January 1, 2012
  
18,789
  
Production
  
(1,060)
 
Acquisitions
  
37
  
Divestitures
  
(544)
 
Revisions – changes to previous estimates
  
(596)
 
Revisions – price
  
(4,878)
 
Extensions and discoveries
  
4,474
  
Ending balance, September 30, 2012
  
16,222
  
       
Proved reserves decline rate before acquisitions and divestitures
  
(11)
%
Proved reserves decline rate after acquisitions and divestitures
  
(14)
%
       
Proved developed reserves
  
9,608
  
Proved developed reserves percentage
  
59
%
       
PV-10 ($ in billions)(a)
  
$
18,451
  
(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, 2012 of $2.83 per mcf of natural gas and $95.05 per bbl of oil, before field differential adjustments.
(b)
Net of well cost carries of $655 million associated with the Statoil-Marcellus, CNOOC-Eagle Ford, CNOOC-Niobrara and Total-Utica joint ventures.
(c)
Includes $1.055 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 596 bcfe of downward revisions resulting from changes to previous estimates and excludes downward revisions of 4.9 tcfe primarily resulting from lower natural gas prices using the average first-day-of-the-month price for the twelve months ended September 30, 2012, compared to the twelve months ended December 31, 2011.
(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 $860 million of well costs on unproved properties incurred in the current quarter, offset by the transfer of $1.055 billion previously classified as well costs on unproved properties that were evaluated for the existence of proved reserves in the current quarter.  See footnote (e).
(g)
Net of joint venture partner reimbursements.
 
 
 
 
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA – NATURAL GAS, OIL AND NGL SALES AND INTEREST EXPENSE
(unaudited)

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

(a)
Net of amounts capitalized.
 
 
 
 
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
 
THREE MONTHS ENDED:
September 30,
  
September 30,
  
2012
  
2011
  
             
Beginning cash
$
1,024
  
$
109
  
             
Cash provided by operating activities
  
949
    
1,631
  
             
Cash flows from investing activities:
            
Well costs on proved and unproved properties
  
(2,353)
 
  
(1,895)
 
Acquisition of proved and unproved properties(a)
  
(936)
 
  
(1,116)
 
Sale of proved and unproved properties
  
808
    
55
  
Geological and geophysical costs
  
(52)
 
  
(55)
 
Additions to other property and equipment
  
(605)
 
  
(554)
 
Proceeds from sales of other assets
  
140
    
157
  
Additions to investments
  
(133)
 
  
(86)
 
Other
  
(102)
 
  
19
  
Total cash used in investing activities
  
(3,233)
 
  
(3,475)
 
             
Cash provided by financing activities
  
1,409
    
1,846
  
             
Cash and cash equivalents classified in current assets
held for sale
  
(7)
 
  
—
  
             
Ending cash
$
142
  
$
111
  
 
(a)
Includes capitalized interest of $327 million and $151 million for the current quarter and the prior quarter, respectively.
 
NINE MONTHS ENDED:
September 30,
  
September 30,
  
2012
  
2011
  
             
Beginning cash
$
351
  
$
102
  
             
Cash provided by operating activities
  
1,978
    
3,724
  
             
Cash flows from investing activities:
            
Well costs on proved and unproved properties
  
(7,360)
 
  
(5,177)
 
Acquisition of proved and unproved properties(b)
  
(2,594)
 
  
(3,300)
 
Sale of proved and unproved properties
  
2,226
    
5,883
  
Geological and geophysical costs
  
(165)
 
  
(168)
 
Additions to other property and equipment
  
(1,916)
 
  
(1,416)
 
Proceeds from sales of other assets
  
219
    
682
  
Acquisition of drilling company
  
—
    
(339)
 
Proceeds from (additions to) investments
  
(261)
 
  
126
  
Proceeds from sale of select midstream investment
  
2,000
    
—
  
Other
  
(303)
 
  
(6)
 
Total cash used in investing activities
  
(8,154)
 
  
(3,715)
 
             
Cash provided by (used in) financing activities
  
5,981
    
—
  
             
Cash and cash equivalents classified in current assets
held for sale
  
(14)
 
  
—
  
             
Ending cash
$
142
  
$
111
  
 
(b)
Includes capitalized interest of $653 million and $478 million for the current period and the prior period, respectively.
 
 
 
 
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)

 
September 30,
  
June 30,
  
September 30,
  
THREE MONTHS ENDED:
2012
  
2012
  
2011
  
                   
CASH PROVIDED BY OPERATING ACTIVITIES
$
949
  
$
755
  
$
1,631
  
                   
Changes in assets and liabilities
  
169
    
140
    
(222)
 
                   
OPERATING CASH FLOW(a)
$
1,118
  
$
895
  
$
1,409
  
 
 
September 30,
  
June 30,
  
September 30,
  
THREE MONTHS ENDED:
2012
  
2012
  
2011
  
                   
NET INCOME (LOSS)
$
(1,971)
 
$
1,037
  
$
922
  
                   
Income tax expense (benefit)
  
(1,260)
 
  
663
    
589
  
Interest expense
  
36
    
14
    
4
  
Depreciation and amortization of other assets
  
66
    
83
    
75
  
Natural gas, oil and NGL depreciation, depletion
and amortization
  
762
    
588
    
423
  
                   
EBITDA(b)
$
(2,367)
 
$
2,385
  
$
2,013
  
 
 
September 30,
  
June 30,
  
September 30,
  
THREE MONTHS ENDED:
2012
  
2012
  
2011
  
                   
CASH PROVIDED BY OPERATING ACTIVITIES
$
949
  
$
755
  
$
1,631
  
                   
Changes in assets and liabilities
  
169
    
140
    
(222)
 
Interest expense
  
36
    
14
    
4
  
Unrealized gains (losses) on natural gas, oil and NGL
Derivatives
  
(104)
 
  
810
    
631
  
Impairment of natural gas and oil properties
  
(3,315)
 
  
—
    
—
  
Losses on sales and impairments of fixed
assets and other
  
(25)
 
  
(243)
 
  
(3)
 
Gains (losses) on investments
  
4
    
943
    
(4)
 
Stock-based compensation
  
(30)
 
  
(31)
 
  
(40)
 
Other items
  
(51)
 
  
(3)
 
  
16
  
                   
EBITDA(b)
$
(2,367)
 
$
2,385
  
$
2,013
  
 
(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)

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

 
September 30,
  
June 30,
  
September 30,
  
THREE MONTHS ENDED:
2012
  
2012
  
2011
  
                   
EBITDA
$
(2,367)
 
$
2,385
  
$
2,013
  
                   
Adjustments:
                  
Unrealized (gains) losses on natural gas, oil and
NGL derivatives
  
104
    
(810)
 
  
(631)
 
Impairment of natural gas and oil properties
  
3,315
    
—
    
—
  
Losses on sales and impairments of
fixed assets and other
  
45
    
243
    
3
  
Net income attributable to noncontrolling interests
  
(41)
 
  
(65)
 
  
—
  
Gains on investments
  
(31)
 
  
(957)
 
  
—
  
Other
  
(4)
 
  
7
    
—
  
                   
Adjusted EBITDA(a)
$
1,021
  
$
803
  
$
1,385
  
 
(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.
 
 
September 30,
  
September 30,
  
NINE MONTHS ENDED:
2012
  
2011
  
             
EBITDA
$
615
  
$
3,471
  
             
Adjustments:
            
Unrealized (gains) losses on natural gas, oil and NGL derivatives
  
(436)
 
  
444
  
Impairment of natural gas and oil properties
  
3,315
    
—
  
Losses on sales and impairments of fixed assets and other
  
286
    
7
  
Net income attributable to noncontrolling interests
  
(131)
 
  
—
  
Losses on purchases or exchanges of debt
  
—
    
176
  
Gains on investments
  
(988)
 
  
—
  
Other
  
1
    
—
  
             
Adjusted EBITDA(a)
$
2,662
  
$
4,098
  
 
(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)

 
September 30,
  
June 30,
  
September 30,
  
THREE MONTHS ENDED:
2012
  
2012
  
2011
  
                   
Net income (loss) available to common stockholders
$
(2,055)
 
$
929
  
$
879
  
                   
Adjustments, net of tax:
                  
Unrealized (gains) losses on derivatives
  
63
    
(498)
 
  
(385)
 
Impairment of natural gas and oil properties
  
2,022
    
—
    
—
  
Losses on sales and impairments of
fixed assets and other
  
28
    
148
    
2
  
Gains on investments
  
(19)
 
  
(584)
 
  
—
  
Other
  
(6)
 
  
8
    
—
  
                   
Adjusted net income available to common
stockholders(a)
  
33
    
3
    
496
  
Preferred stock dividends
  
43
    
43
    
43
  
Total adjusted net income
$
76
  
$
46
  
$
539
  
                   
Weighted average fully diluted shares outstanding(b)
  
754
    
751
    
753
  
                   
Adjusted earnings per share assuming dilution(a)
$
0.10
  
$
0.06
  
$
0.72
  
 
(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.
 
 
 
 
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per-share data)
(unaudited)

 
September 30,
  
September 30,
  
NINE MONTHS ENDED:
2012
  
2011
  
             
Net income (loss) available to common stockholders
$
(1,197)
 
$
1,141
  
             
Adjustments, net of tax:
            
Unrealized (gains) losses on derivatives
  
(268)
 
  
279
  
Impairment of natural gas and oil properties
  
2,022
    
—
  
Losses on sales and impairments of fixed assets and other
  
174
    
4
  
Losses on purchases or exchanges of debt
  
—
    
107
  
Loss on foreign currency derivatives
  
—
    
11
  
Gains on investments
  
(603)
 
  
—
  
Other
  
2
    
—
  
             
Adjusted net income available to common stockholders(a)
  
130
    
1,542
  
Preferred stock dividends
  
128
    
128
  
Total adjusted net income
$
258
  
$
1,670
  
             
Weighted average fully diluted shares outstanding(b)
  
753
    
752
  
             
Adjusted earnings per share assuming dilution(a)
$
0.34
  
$
2.22
  
 
(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 NOVEMBER 1, 2012
 
Chesapeake periodically provides management guidance on certain factors that affect its future financial performance.  The primary changes from the company’s August 6, 2012 Outlook are in italicized bold and reflect estimated natural gas curtailments of approximately 60 bcf in the 2012 first half and also include estimated future production decreases of approximately 45 bcfe in 2012 and 140 bcfe in 2013 associated with the company’s completed and planned asset sales.  Management and the board of directors continue to review operational plans for 2013 and beyond which could result in changes to this Outlook.
 
Chesapeake Energy Corporation Consolidated Projections
For Years Ending December 31, 2012 and 2013
 
Year Ending
12/31/12
  
Year Ending
12/31/13
  
Estimated Production:
        
Natural gas – bcf
   1,120 – 1,140     1,030 – 1,070  
Oil – mbbls
   30,000 – 31,000     36,000 – 38,000  
NGL – mbbls
   17,000 – 18,000     24,000 – 26,000  
Natural gas equivalent – bcfe
   1,402 – 1,434     1,390 – 1,454  
             
Daily natural gas equivalent midpoint – mmcfe
   3,870     3,895  
             
YOY estimated production increase (adjusted for planned asset sales)
   18%     1%  
             
NYMEX Price(a) (for calculation of realized hedging effects only):
        
Natural gas - $/mcf
 $ 2.77   $ 4.00  
Oil - $/bbl
 $ 94.66   $ 90.00  
             
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
            
Natural gas - $/mcf
 $ 0.30   $ 0.00  
Oil - $/bbl
 $ 0.99   $ 4.50  
             
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
            
Natural gas - $/mcf
 $ 1.00 –1.10   $ 1.15 – 1.25  
Oil - $/bbl
 $ 4.50 – 6.50   $ 4.50 – 6.50  
NGL - $/bbl
 $ 67.00 – 70.00   $ 63.00 – 67.00  
             
Operating Costs per Mcfe of Projected Production:
            
Production expense
 $ 0.90 – 1.00   $ 0.90 – 1.00  
      Production taxes (~5% of O&G revenues)
 $ 0.15 – 0.20   $ 0.25 – 0.30  
General and administrative(b)
 $ 0.39 – 0.44   $ 0.39 – 0.44  
Stock-based compensation (noncash)
 $ 0.04 – 0.06   $ 0.04 – 0.06  
DD&A of natural gas and liquids assets
 $ 1.65 – 1.85   $ 1.65 – 1.85  
Depreciation of other assets
 $ 0.22 – 0.27   $ 0.25 – 0.30  
Interest expense(c)
 $ 0.05 – 0.10   $ 0.05 – 0.10  
             
Other ($ millions):
            
Marketing, gathering and compression net margin(d)
 $ 90 – 100   $ 50 – 75  
Oilfield services net margin(d)
 $ 175 – 200   $ 200 – 250  
Other income (including certain equity investments)
 $ 25     –  
 Net income attributable to noncontrolling interest(e)
 $ (180)– (200)   $ (200) – (240)  
             
Book Tax Rate
   39%     39%  
             
Weighted average shares outstanding (in millions):
            
Basic
   640 – 645     645 – 650  
Diluted
   753 – 758     758 – 763  
             
Operating cash flow before changes in assets and liabilities(f)(g)
 $ 3,800   $ 4,250 – 5,250  
Well costs on proved and unproved properties
 $ (8,750)   $ (5,750 – 6,250)  
Acquisition of unproved properties, net
 $ (1,750)   $ (400)  
             
a)  
NYMEX natural gas and oil prices have been updated for actual contract prices through October and September, respectively.
b)  
Excludes expenses associated with noncash stock-based compensation.
c)  
Does not include unrealized gains or losses on interest rate derivatives.
d)  
Includes revenue and operating costs and excludes depreciation and amortization of other assets.
e)  
Net income attributable to noncontrolling interests of Chesapeake Granite Wash Trust, CHK Utica, L.L.C., CHK Cleveland Tonkawa, L.L.C. and Cardinal Gas Services, L.L.C.
f)  
A non-GAAP financial measure.  We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.
g)  
Assumes NYMEX prices on open contracts of $3.50 per mcf and $90.00 per bbl in 2012 and $3.50 to $4.50 per mcf and $90.00 per bbl in 2013.
 
 
 
 
Natural Gas, Oil and NGL Hedging Activities
 
Chesapeake enters into natural gas, oil and NGL derivative transactions in order to mitigate a portion of its exposure to adverse changes in market prices.  Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the SEC for detailed information about derivative instruments the company uses, its quarter-end derivative positions and the accounting for natural gas, oil and NGL derivatives.
 
As of November 1, 2012, the company has the following open natural gas swaps in place and gains (losses) related to closed natural gas trades and premiums for call options for future production periods.
 
 
 
  
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 Premiums
for Call Options
($ in millions)
  
Total Gains from
Closed Trades
and Premiums
for Call Options
per mcf of
Forecasted
Natural Gas
Production
Q4 2012
  
215
    
$
3.06
    
281
  
76
%
  
$
15
    
$
0.05
  
                                         
Q1 2013
  
0
                      
$
(11)
          
Q2 2013
  
0
                        
8
          
Q3 2013
  
0
                        
6
          
Q4 2013
  
0
                        
(3)
          
Total 2013
  
0
    
$
0.00
    
1,050
  
0
%
  
$
0
    
$
0.00
  
Total 2014
  
0
                      
$
(74)
          
Total 2015
  
0
                      
$
(131)
          
Total 2016 – 2022
  
0
                      
$
(161)
          
 
The company currently has the following natural gas written call options in place:
   
Call Options
(bcf)
  
Avg. NYMEX
Strike Price
  
Forecasted
Natural Gas
Production
(bcf)
  
Call Options
as a % of
Forecasted
Natural Gas
Production
Q4 2012
  
40
    
$
3.25
    
281
  
14
%
                         
Total 2013
  
0
    
$
0.00
    
1,050
  
0
%
Total 2014
  
0
    
$
0.00
            
Total 2015
  
0
    
$
0.00
            
Total 2016 – 2020
  
260
    
$
8.90
            
 
The company currently has the following purchased natural gas put swaptions in place:
   
Put Swaptions
(bcf)
  
Avg. NYMEX
Price of Swap
  
Forecasted
Natural Gas
Production
(bcf)
  
Put Swaption
as a % of
Forecasted
Natural Gas
Production
Q1 2013
  
8
    
$
3.66
              
Q2 2013
  
10
    
$
3.64
              
Q3 2013
  
2
    
$
3.50
              
Q4 2013
  
0
    
$
0.00
              
Total 2013
  
20
    
$
3.64
    
1,050
    
2
%
 
 
 
 
The company has the following natural gas basis protection swaps in place:
     
   
Volume (Bcf)
  
Avg. NYMEX less
Q4 2012
  
8
    
$
0.74
             
2013
  
44
    
$
0.21
2014
  
28
    
$
0.32
2015 - 2022
  
40
    
$
0.48
 
As of November 1, 2012, the company has the following open crude oil swaps in place and gains (losses) related to closed crude oil contracts and premiums for call options for future production periods (note: the company also has 5,000 bbl per day of propane call options in Q4 2012.):
   
Open
Swaps
(mbbls)
  
Avg. NYMEX
Price of
Open Swaps
  
Forecasted
Oil
Production
(mbbls)
  
Open Swap
Positions as
a % of
Forecasted
Oil
Production
  
Total Gains
(Losses) from
Closed Trades
and Premiums
for Call Options
($millions)
  
Total Gains
(Losses) from
Closed Trades
and Premiums for
Call Options per
bbl of Forecasted
Oil
Production
Q4 2012
  
6,197
    
$
99.14
    
8,171
    
76
%
  
$
(31)
    
$
(3.83)
 
                                           
Q1 2013
  
5,647
      
95.95
                
$
1
          
Q2 2013
  
6,672
      
96.10
                
$
1
          
Q3 2013
  
6,687
      
96.02
                
$
2
          
Q4 2013
  
6,662
      
95.97
                
$
2
          
Total 2013
  
25,668
    
$
96.01
    
37,000
    
69
%
  
$
6
    
$
0.17
  
Total 2014
  
918
    
$
90.85
                
$
(151)
          
Total 2015
  
500
    
$
88.75
                
$
265
          
Total 2016 – 2021
  
0
                        
$
117
          
 
The company currently has the following crude oil written call options in place:
   
Call Options
(mbbls)
  
Avg. NYMEX
Strike Price
  
Forecasted
Oil
Production
(mbbls)
  
Call Options
as a % of
Forecasted Oil
Production
Q4 2012
  
0
    
$
--
    
8,171
    
0
%
                           
Q1 2013
  
3,390
    
$
99.56
              
Q2 2013
  
3,428
    
$
99.56
              
Q3 2013
  
3,006
    
$
98.62
              
Q4 2013
  
3,006
    
$
98.62
              
Total 2013
  
12,830
    
$
99.12
    
37,000
    
35
%
Total 2014
  
17,612
    
$
98.79
              
Total 2015
  
27,048
    
$
100.99
              
Total 2016 – 2017
  
24,220
    
$
100.07
              
 
The company has the following oil basis protection swaps in place:
     
   
Volume (mbbls)
  
Avg. NYMEX plus
Q4 2012
  
951
    
$
17.70
             
Q1 2013
  
2,070
    
$
14.99
Q2 2013
  
1,365
    
$
12.55
Total 2013
  
3,435
    
$
14.02
 
 
 
 
SCHEDULE “B”
MANAGEMENT’S OUTLOOK AS OF AUGUST 6, 2012
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF NOVEMBER 1, 2012
 
Below is the company’s previous Outlook, as provided on August 6, 2012, which reflected projected voluntary natural gas curtailments of approximately 60 bcf in the 2012 first half and also include estimated future production decreases of approximately 45 bcfe in 2012 and 140 bcfe in 2013 associated with the company’s planned Permian Basin, Mississippi Lime and other asset sales.
 
Chesapeake Energy Corporation Consolidated Projections
For Years Ending December 31, 2012 and 2013

   
Year Ending
12/31/12
  
Year Ending
12/31/13
Estimated Production:
        
Natural gas – bcf
  
1,120 – 1,140
  
1,030 – 1,070
Oil – mbbls
  
29,000 – 30,000
  
36,000 – 38,000
NGL – mbbls
  
17,000 – 18,000
  
24,000 – 26,000
Natural gas equivalent – bcfe
  
1,396 – 1,428
  
1,390 – 1,454
         
Daily natural gas equivalent midpoint – mmcfe
  
3,855
  
3,895
         
YOY estimated production increase including asset sales
  
18%
  
1%
         
NYMEX Price(a) (for calculation of realized hedging effects only):
    
Natural gas - $/mcf
  
$2.79
  
$3.75
Oil - $/bbl
  
$93.93
  
$90.00
         
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
        
Natural gas - $/mcf
  
$0.29
  
$0.01
Oil - $/bbl
  
$0.81
  
$0.48
         
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
        
Natural gas - $/mcf
  
$1.00 –1.10
  
$1.15 – 1.25
Oil - $/bbl
  
$4.50 – 6.50
  
$4.50 – 6.50
NGL - $/bbl
  
$67.00 – 70.00
  
$63.00 – 67.00
         
Operating Costs per Mcfe of Projected Production:
        
Production expense
  
$0.95 – 1.05
  
$0.95 – 1.05
      Production taxes (~5% of O&G revenues)
  
$0.15 – 0.20
  
$0.25 – 0.30
General and administrative(b)
  
$0.39 – 0.44
  
$0.39 – 0.44
Stock-based compensation (noncash)
  
$0.04 – 0.06
  
$0.04 – 0.06
DD&A of natural gas and liquids assets
  
$1.40 – 1.60
  
$1.50 – 1.70
Depreciation of other assets
  
$0.22 – 0.27
  
$0.25 – 0.30
Interest expense(c)
  
$0.05 – 0.10
  
$0.05 – 0.10
         
Other ($ millions):
        
Marketing, gathering and compression net margin(d)
  
$70 – 80
  
$50 – 75
Oilfield services net margin(d)
  
$175 – 200
  
$200 – 250
Other income (including certain equity investments)
  
$25
  
–
 Net income attributable to noncontrolling interest(e)
  
($180) – (200)
  
($200) – (240)
         
Book Tax Rate
  
39%
  
39%
         
Weighted average shares outstanding (in millions):
        
Basic
  
640 – 645
  
645 – 650
Diluted
  
753 – 758
  
758 – 763
 
 
 
 
 
        Year Ending
12/31/12
     Year Ending
12/31/13
     
     
   
($ millions)
Operating cash flow before changes in assets and liabilities(f)(g)
  
$3,200 – 3,250
  
$3,750 – 4,750
         
Well costs on proved and unproved properties
  
($8,000 – 8,500)
  
($5,750 – 6,250)
Acquisition of unproved properties, net
  
($2,000)
  
($400)
Investment in oilfield services, midstream and other
  
($2,800 – 3,100)
  
($850 – 1,100)
    Subtotal of net investment
  
($12,800 – 13,600)
  
($7,000 – 7,750)
         
Asset sales and other transactions
  
$13,000 – 14,000
  
$4,250 – 5,000
         
Interest, dividends and cash taxes
  
($1,100 –1,350)
  
($1,000 – 1,250)
         
Total budgeted cash flow surplus
  
$2,300
  
$0 – 750
         
a)  
NYMEX natural gas prices and NYMEX oil prices have been updated for actual contract prices through August and July, respectively.
b)  
Excludes expenses associated with noncash stock-based compensation.
c)  
Does not include gains or losses on interest rate derivatives.
d)  
Includes revenue and operating costs and excludes depreciation and amortization of other assets.
e)  
Net income attributable to noncontrolling interests of Chesapeake Granite Wash Trust, CHK Utica, L.L.C., CHK Cleveland Tonkawa, L.L.C. and Cardinal Gas Services, L.L.C.
f)  
A non-GAAP financial measure.  We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.
g)  
Assumes NYMEX prices on open contracts of $3.00 to $3.25 per mcf and $90.00 per bbl in 2012 and $3.25 to $4.25 per mcf and $90.00 per bbl in 2013.

 
 
 
 
Oil, NGL and Natural Gas Hedging Activities
 
Chesapeake enters into oil, NGL and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse changes in market prices.  Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the Securities and Exchange Commission for detailed information about derivative instruments the company uses, its quarter-end derivative positions and the accounting for oil, NGL and natural gas derivatives.
 
As of August 6, 2012, the company has the following open natural gas swaps in place through 2012.  The company currently has $212 million of net hedging losses related to closed natural gas contracts and premiums for call options for future production periods.
 
 
 
  
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 Premiums
for Call Options
($ in millions)
  
Total Gains from
Closed Trades
and Premiums
for Call Options
per mcf of
Forecasted
Natural Gas
Production
Q3 2012
  
167
    
$
3.02
                
$
32
          
Q4 2012
  
204
    
$
3.04
                  
15
          
Q2-Q4 2012
  
371
    
$
3.03
    
584
    
64
%
  
$
47
    
$
0.08
  
                                           
Total 2013
  
0
    
$
0.00
    
1,050
    
0
%
  
$
16
    
$
0.01
  
Total 2014
  
0
                        
$
(34)
          
Total 2015
  
0
                        
$
(110)
          
Total 2016 – 2022
  
0
                        
$
(131)
          
 
The company currently has the following natural gas written call options in place for 2012 through 2020:
   
Call Options
(bcf)
  
Avg. NYMEX
Strike Price
  
Forecasted
Natural Gas
Production
(bcf)
  
Call Options
as a % of
Forecasted
Natural Gas
Production
Q3 2012
  
40
    
$
3.25
              
Q4 2012
  
41
      
3.25
              
Q3-Q4 2012
  
81
    
$
3.25
    
584
    
14
%
                           
Total 2013
  
251
    
$
6.31
    
1,050
    
24
%
Total 2014
  
330
    
$
6.43
              
Total 2015
  
116
    
$
6.45
              
Total 2016 – 2020
  
349
    
$
8.18
              
 
The company has the following natural gas basis protection swaps in place for 2012 through 2022:
     
   
Volume (Bcf)
  
Avg. NYMEX less
2012
  
29
    
$
0.78
2013
  
44
    
$
0.21
2014 - 2022
  
67
    
$
0.42
Totals
  
140
    
$
0.43
 
As of August 6, 2012, the company has the following open crude oil swaps in place for 2012 and through 2015.  In addition, the company has $193 million of net hedging gains related to closed crude oil contracts and premiums for 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 Premiums
for Call Options
($millions)
  
Total Gains
(Losses) from
Closed Trades
and Premiums for
Call Options per
bbl of Forecasted
Liquids
Production
Q3 2012
  
3,754
    
$
101.56
              
$
(11
)
        
Q4 2012
  
3,841
      
101.12
                
(33
)
        
Q3-Q4 2012
  
7,595
    
$
101.34
    
24,816
  
31%
    
$
(44
)
  
$
(1.78)
  
                                         
Total 2013
  
3,122
    
$
94.06
    
62,000
  
5%
    
$
6
    
$
0.10
  
Total 2014
  
902
    
$
90.72
              
$
(151
)
        
Total 2015
  
500
    
$
88.75
              
$
265
          
Total 2016 – 2021
                          
$
117
          
 
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 2012
  
0
    
$
--
            
Q4 2012
  
460
      
106.72
            
Q3-Q4 2012
  
460
    
$
106.72
    
24,816
  
2%
  
                         
Total 2013
  
15,633
    
$
100.50
    
62,000
  
25%
  
Total 2014
  
17,612
    
$
98.79
            
Total 2015
  
27,048
    
$
100.99
            
Total 2016 – 2017
  
24,220
    
$
100.07
            
 

CHESAPEAKE ENERGY CORP Reports