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

11/1/2012 11:13 AM

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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.

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.




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


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

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

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

Average Realized Prices and Hedging Results and Positions Detailed


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

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

The following table summarizes Chesapeake’s 2012 and 2013 open natural gas and oil swap positions as of November 1, 2012. Depending on changes in natural gas and oil futures markets and management’s view of underlying supply and demand trends, Chesapeake may increase or decrease some or all of its hedging positions at any time in the future without notice.




Details of the company’s quarter-end hedging positions will be provided in the company’s Form 10-Q filing with the Securities and Exchange Commission (SEC), and current positions are disclosed in summary format in management’s Outlook dated November 1, 2012, which is attached to this release as Schedule “A,” beginning on page 24. The Outlook has been updated from the Outlook dated August 6, 2012, attached as Schedule “B,” which begins on page 27, to reflect various updated information. Management and the board of directors are currently reviewing operational plans for 2013 and beyond, which could result in changes to the Outlook attached as Schedule “A.”

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


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

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




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.














































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.




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




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




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




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):




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




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







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.




The company currently has the following natural gas written call options in place for 2012 through 2020:




The company has the following natural gas basis protection swaps in place for 2012 through 2022:




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.




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




SOURCE: Chesapeake Energy Corporation



Chesapeake Energy Corporation

Investor Contacts:

Jeffrey L. Mobley, CFA, 405-767-4763
jeff.mobley@chk.com

or

John J. Kilgallon, 405-935-4441
john.kilgallon@chk.com



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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