8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 16, 2010

CHESAPEAKE ENERGY CORPORATION

(Exact name of Registrant as specified in its Charter)

Oklahoma	1-13726	73-1395733
(State or other jurisdiction of incorporation)	(Commission File No.)	(IRS Employer Identification No.)

6100 North Western Avenue, Oklahoma City, Oklahoma	73118
(Address of principal executive offices)	(Zip Code)

(405) 848-8000

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

*           Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

*           Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

*           Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

*           Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 2 – Financial Information

Item 2.02 – Results of Operations and Financial Condition

On February 16, 2010, Chesapeake Energy Corporation (the “Company”) issued a press release providing an operational update for the 2009 fourth quarter and 2009 full year.  A copy of the press release is attached as Exhibit 99.1 to this Current Report.

On February 17, 2010, the Company issued a press release reporting our financial and operational results for the 2009 fourth quarter and 2009 full year and an updated outlook for 2010 and 2011.  The press release also provided information for accessing a related conference call.  A copy of the press release is attached as Exhibit 99.2 to this Current Report.

Section 9 – Financial Statements and Exhibits

Item 9.01 Financial Statements and Exhibits

 (d)Exhibits.  See "Index to Exhibits" attached to this Current Report on Form 8-K, which is incorporated by reference herein.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

CHESAPEAKE ENERGY CORPORATION
By:	/s/ JENNIFER M. GRIGSBY
	Jennifer M. Grigsby
	Senior Vice President, Treasurer and Corporate Secretary

Date:           February 17, 2010

EXHIBIT INDEX

Exhibit No.	Document Description
99.1	Chesapeake Energy Corporation press release dated February 16, 2010
99.2	Chesapeake Energy Corporation press release dated February 17, 2010

EX-99.1

Exhibit 99.1

  N e w s   R e l e a s e Chesapeake Energy Corporation P. O. Box 18496 Oklahoma City, OK  73154

FOR IMMEDIATE RELEASE

FEBRUARY 16, 2010

INVESTOR CONTACT:	MEDIA CONTACT:
JEFFREY L. MOBLEY, CFA SENIOR VICE PRESIDENT – INVESTOR RELATIONS AND RESEARCH (405) 767-4763 jeff.mobley@chk.com	JIM GIPSON DIRECTOR – MEDIA RELATIONS  (405) 935-1310 jim.gipson@chk.com

CHESAPEAKE ENERGY CORPORATION PROVIDES OPERATIONAL UPDATE

2009 Fourth Quarter Production of 2.6 Bcfe per Day Increases 13%

Over 2008 Fourth Quarter Production

2009 Full Year Production of 2.5 Bcfe per Day Increases 8% Over 2008 Full Year

Production, Setting Record for 20th Consecutive Year

Proved Reserves Reach 14.3 Tcfe Using SEC Pricing and 15.5 Tcfe Using 10-Year Average

NYMEX Strip Pricing, Year-Over-Year Increases of 18% and 29%, Respectively

Company Delivers 2009 Full Year Reserve Replacement Ratio and Drilling and Net  

Acquisition Cost of 343% and $0.74 per Mcfe, Respectively, Using SEC Pricing and

485% and $0.73 per Mcfe, Respectively, Using 10-Year Average NYMEX Strip Pricing

OKLAHOMA CITY, OKLAHOMA, FEBRUARY 16, 2010 – Chesapeake Energy Corporation (NYSE:CHK) today provided an update on its operational activities.  For the 2009 fourth quarter, Chesapeake’s daily production averaged 2.618 billion cubic feet of natural gas equivalent (bcfe), an increase of 135 million cubic feet of natural gas equivalent (mmcfe), or 5%, over the 2.483 bcfe produced per day in the 2009 third quarter and an increase of 302 mmcfe, or 13%, over the 2.316 bcfe produced per day in the 2008 fourth quarter.  Adjusted for the company’s voluntary production curtailments due to low natural gas prices (approximately 26 mmcfe per day during the 2009 fourth quarter), the company’s volumetric production payment transactions (which combined averaged approximately 96 mmcfe per day during the 2009 fourth quarter) and the estimated impact from various divestitures (which would have averaged approximately 49 mmcfe per day during the 2009 fourth quarter), Chesapeake’s sequential and year-over-year production growth rates would have been 5% and 17%, respectively, after making similar adjustments to prior quarters.  Chesapeake’s 2009 fourth quarter average daily production of 2.618 bcfe consisted of 2.440 billion cubic feet of natural gas (bcf) and 29,750 barrels of oil and natural gas liquids (bbls).  The company’s 2009 fourth quarter production of 241 bcfe was comprised of 225 bcf (93% on a natural gas equivalent basis) and 2.7 million barrels of oil and natural gas liquids (mmbbls) (7% on a natural gas equivalent basis).

The company’s daily production for the 2009 full year averaged 2.481 bcfe, an increase of 178 mmcfe, or 8%, over the 2.303 bcfe of daily production for the 2008 full year.  Adjusted for the company’s voluntary production curtailments due to low natural gas prices (approximately 47 mmcfe per day during the 2009 full year), the company’s volumetric production payment transactions (which combined averaged approximately 157 mmcfe per day during the 2009 full year) and the estimated impact from various divestitures (which would have averaged approximately 193 mmcfe per day during the 2009 full year), Chesapeake’s year-over-year daily production growth rate would have been 19%, after making similar adjustments to the 2008 full year.  Chesapeake’s average daily production for the 2009 full year of 2.481 bcfe consisted of 2.287 bcf and 32,301 bbls.  The company’s 2009 full year production of 906 bcfe was comprised of 835 bcf (92% on a natural gas equivalent basis) and 11.8 mmbbls (8% on a natural gas equivalent basis).  The 2009 full year was Chesapeake’s 20th consecutive year of sequential production growth.  Chesapeake anticipates delivering full-year production growth of approximately 8-10% in 2010 and 15-17% in 2011, net of property divestitures.

Proved Reserves Reach Record Levels and Company

Delivers Drilling and Net Acquisition Costs of $0.74 per Mcfe

For year-end 2009 reserve reporting, the Securities and Exchange Commission (SEC) has implemented new rules requiring that proved reserve calculations be based on the unweighted average first-of-the-month prices for the twelve months in 2009, as contrasted with the previous method which utilized period-end prices.  The prices under the new method were $3.87 per mcf and $61.14 per bbl, before field differential adjustments, compared to year-end 2009 spot prices of $5.79 per mcf and $79.34 per bbl, before field differential adjustments.  The modernized rules also contain new reserve recognition definitions that allow for the reporting of proved undeveloped (PUD) reserves that are more than one direct development spacing area away from offsetting producing wells if reasonable certainty can be shown using reliable technology.  Chesapeake has utilized and developed reliable geologic and engineering technology to book PUD reserves more than one location offsetting production in the Barnett Shale and Fayetteville Shale.  At the present time, PUD reserve bookings in all other asset areas have been restricted to directly offsetting development spacing areas away from offsetting producing wells.

The SEC's new pricing rule reflects the low average natural gas prices experienced in 2009.  This affects the volume of reportable proved reserves and substantially lowers the estimated future net cash flows from proved reserves.  Chesapeake believes that using the 10-year average NYMEX strip prices as of December 31, 2009, which were $6.94 per mcf and $92.24 per bbl, before field differential adjustments, yields a better indication of the likely economic producibility of its proved reserves than the 2009 12-month average required by the new rules or spot prices at year end, which were required prior to year-end 2009.

The following table compares Chesapeake’s year-end 2009 proved reserves and percentage increase over its year-end 2008 proved reserves of 12.1 tcfe, estimated future net cash flows from proved reserves, discounted at an annual rate of 10% before income taxes (PV-10), and proved developed percentage based on the 2009 12-month average price required under new SEC rules, spot prices at year-end 2009 and the 10-year average NYMEX strip prices at year-end 2009.

Pricing Assumption	Natural Gas Price ($/mcf)	Oil Price ($/bbl)	Proved Reserves (tcfe)	Proved Reserves Annual Growth Rate	Reserve Replacement Ratio	PV-10 (billions)	Proved Developed Percentage
2009 12-month average (SEC)	$3.87	$61.14	14.3	18%	343%	$9.4(a)	58%
12/31/09 spot	$5.79	$79.34	15.3	27%	460%	$21.4	58%
12/31/09 10-year average NYMEX strip	$6.94	$92.24	15.5	29%	485%	$28.7	58%

(a)   The associated standardized measure of discounted future net cash flows, which includes the effect of future income taxes, was $8.2 billion under SEC pricing.

The following table summarizes Chesapeake’s finding and development costs for the 2009 full year using each of the three pricing assumptions described above.

Finding and Development Cost Category	12-Month Average (SEC) Pricing  ($/mcfe)	12/31/09 Spot Pricing ($/mcfe)	12/31/09 10-year Average NYMEX Strip Pricing ($/mcfe)
Exploration and development costs (a)	$0.80	$0.80	$0.79
Drilling and net acquisition costs (a)	$0.74	$0.74	$0.73
Total costs	$1.50	$1.12	$1.06

(a)   Includes performance-related revisions and the benefit of $1.154 billion in drilling carries and also excludes price-related revisions

A complete reconciliation of proved reserves, reserve replacement ratios and finding and acquisition costs based on these three alternative pricing assumptions is presented on pages 10 - 12 of this release.  Also, a reconciliation of PV-10 to the standardized measure is presented on page 13 of this release.

In addition to the PV-10 value of its proved reserves and the very significant value of its undeveloped leasehold, particularly in the Haynesville, Marcellus, Barnett and Fayetteville Shale plays and the Greater Granite Wash plays, the net book value of the company’s other assets (including gathering systems, compressors, land and buildings, investments and other non-current assets) was $6.7 billion as of December 31, 2009 compared to $5.8 billion as of December 31, 2008.

During 2009, Chesapeake continued the industry’s most active drilling program and drilled 1,148 gross operated wells (831 net wells with an average working interest of 72%) and participated in another 1,126 gross wells operated by other companies (99 net wells with an average working interest of 9%).  The company’s drilling success rate was 99% for company-operated wells and 97% for non-operated wells.  Also during 2009, Chesapeake invested $2.941 billion in operated wells (using an average of 104 operated rigs) and $439 million in non-operated wells (using an average of 60 non-operated rigs) for total drilling, completing and equipping costs of $3.380 billion.

Chesapeake’s Leasehold and 3-D Seismic Inventories Total 13.7 Million Net Acres and 23.6

Million Acres; Risked Unproved Resources in the Company’s Inventory Total 65 Tcfe

and Unrisked Unproved Resources Total 177 Tcfe

Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (13.7 million net acres) and 3-D seismic (23.6 million acres) in the U.S. and the largest inventory of U.S. Big 6 shale play leasehold (2.9 million net acres) and Granite Wash leasehold (190,000 net acres).  On its leasehold, as of December 31, 2009, pro forma for the company’s January 2010 Barnett Shale joint venture transaction, Chesapeake had identified an estimated 14.6 tcfe of proved reserves and 65 tcfe of risked unproved resources (177 tcfe of unrisked unproved resources), based on the year-end 2009 10-year average NYMEX strip prices.  The company is currently using 118 operated drilling rigs to further develop its inventory of approximately 35,750 net drillsites, which represents more than a 10-year inventory of drilling projects.

The following table summarizes Chesapeake’s ownership and activity in its Big 6 shale plays, its two primary Anadarko Basin Granite Wash plays and its other plays.  Chesapeake uses a probability-weighted statistical approach to estimate the potential number of drillsites and unproved resources associated with such drillsites.

Play Type/Area	CHK Net Acreage(1)	Est.  Drilling Density (Acres)	Risk Factor	Risked Net Undrilled Wells(1)	Est. Avg. Resources Per Well (bcfe)	Proved Reserves (bcfe)(1)(2)	Risked Unproved Resources (bcfe)(2)	Unrisked Unproved Resources  (bcfe) (2)	Current Daily Net Production (mmcfe)(1)(3)	Current Operated Rig Count(4)
Big 6 Shale Plays:
Marcellus Shale	1,570,000	80	70%	5,900	4.20	265	20,900	69,900	65	24
Haynesville Shale	535,000	80	40%	3,900	6.50	1,960	17,400	30,100	375	38
Fayetteville Shale	455,000	80	20%	4,200	2.40	2,225	6,900	9,000	340	12
Barnett Shale(1)	220,000	60	15%	1,800	2.65	2,756	2,800	3,800	515	24
Bossier Shale	180,000	80	80%	450	5.50	0	1,900	9,300	ND(6)	0
Eagle Ford Shale(7)	80,000	160	90%	50	4.30	0	200	1,600	ND(6)	1
Big 6 Shale Play Subtotal(5)	2,860,000			16,300		7,206	50,100	123,700	1,295	99
Colony Granite Wash	120,000	160	25%	500	5.70	443	1,900	2,700	110	4
Texas Panhandle Granite Wash	70,000	80	25%	400	4.75	670	1,200	1,700	90	4
Other	10,650,000	Various	Various	18,550	Various	6,303	11,300	48,600	920	11
Total	13,700,000			35,750		14,622	64,500	176,700	2,415	118

 (1)   Pro forma for January 2010 Barnett Shale joint venture transaction

(2)   Based on year-end 2009 10-Year average NYMEX strip pricing

(3)   Estimated February 2010 average

(4)   As of February 12, 2010

(5)   Bossier Shale acreage overlaps with Haynesville Shale acreage and is excluded from the Big 6 acreage subtotal to avoid double counting of acreage

(6)   Not disclosed

(7)   As of February 17, 2010, Chesapeake’s Eagle Ford Shale acreage is currently approximately 150,000 net acres

Marcellus Shale (West Virginia, Pennsylvania and New York): With approximately 1.6 million net acres, Chesapeake is the largest leasehold owner in the Marcellus Shale play that spans from northern West Virginia across much of Pennsylvania into southern New York.  The company’s joint venture partner, Statoil (NYSE:STO, OSE:STL), owns approximately 590,000 additional net acres of Marcellus leasehold.  Chesapeake remains the most active driller in the play.  Since January 1, 2008, Chesapeake has drilled and completed 56 company-operated horizontal wells in the Marcellus.  During the 2009 fourth quarter, Chesapeake’s average daily net production of approximately 45 mmcfe in the Marcellus increased approximately 26% over the 2009 third quarter and approximately 530% over the 2008 fourth quarter. Chesapeake is currently producing a company record monthly average of approximately 65 mmcfe net per day (115 mmcfe gross operated) from the Marcellus and anticipates reaching approximately 270 mmcfe net per day (515 mmcfe gross operated) by year-end 2010 and approximately 450 mmcfe net per day (855 mmcfe gross operated) by year-end 2011.

To further develop its 1.6 million net acres of Marcellus leasehold, Chesapeake is currently drilling with 24 operated rigs and anticipates operating an average of approximately 32 rigs in 2010 to drill approximately 175 net wells.  During 2009, approximately $162 million of Chesapeake’s drilling costs in the Marcellus were paid for by STO.  During 2010 through 2012, 75% of Chesapeake’s drilling costs in the Marcellus will be paid for by STO, or approximately $2.0 billion over the next three years.

Chesapeake’s leasehold investment in the Marcellus has been approximately $1.8 billion, of which $1.3 billion, or 70%, has been recouped by selling a 32.5% interest in the company’s leasehold to STO.  The company’s net investment in its Marcellus leasehold is now approximately $330 per net acre on average.

Three notable recent wells completed by Chesapeake in the Marcellus are as follows:

·   The White 2H in Susquehanna County, PA achieved a peak 24-hour rate of 8.7 mmcf per day;

·   The White 5H in Susquehanna County, PA achieved a peak 24-hour rate of 8.6 mmcf per day; and

·   The Benscoter 3H in Susquehanna County, PA achieved a peak 24-hour rate of 8.4 mmcf per day.

Haynesville Shale (Northwest Louisiana, East Texas):  Chesapeake is the largest leasehold owner and most active driller of new wells in the Haynesville Shale play in Northwest Louisiana and East Texas.  Chesapeake now owns approximately 535,000 net acres of leasehold in the Haynesville Shale play.  Chesapeake and its 20% joint venture partner, Plains Exploration & Production Company (NYSE:PXP) (which owns approximately 110,000 additional net acres), have drilled and completed 150 Chesapeake-operated horizontal wells in the Haynesville play and continue to experience outstanding drilling results.  During the 2009 fourth quarter, Chesapeake’s average daily net production of approximately 365 mmcfe in the Haynesville increased approximately 59% over the 2009 third quarter and approximately 519% over the 2008 fourth quarter.  Chesapeake is currently producing approximately 375 mmcfe net per day (550 mmcfe gross operated) from the Haynesville and anticipates exceeding approximately 640 mmcfe net per day (970 mmcfe gross operated) by year-end 2010 and approximately 810 mmcfe net per day (1,230 mmcfe gross operated) by year-end 2011.

To further develop its 535,000 net acres of Haynesville leasehold, Chesapeake is currently drilling with 38 operated rigs and anticipates operating an average of approximately 41 rigs in 2010 to drill approximately 200 net wells.  During 2009, approximately $390 million of Chesapeake’s drilling costs in the Haynesville were paid for by its joint venture partner PXP.  In August 2009, Chesapeake and PXP amended their joint venture agreement to accelerate the payment of PXP’s remaining joint venture drilling carries as of September 30, 2009 in exchange for an approximate 12% reduction in the total amount of drilling carry obligations due to Chesapeake.  As a result, on September 29, 2009, Chesapeake received $1.1 billion in cash from PXP and beginning in the 2009 fourth quarter Chesapeake and PXP each began paying their proportionate working interest costs on drilling.

Chesapeake’s leasehold investment in the Haynesville has been approximately $5.3 billion, of which approximately $2.8 billion, or 52%, has been recouped by selling a 20% interest in the company’s leasehold to PXP.  The company’s net investment in its Haynesville leasehold is now approximately $4,600 per net acre on average.

Three notable recent wells completed by Chesapeake in the Haynesville are as follows:

·   The Sloan 4-12-13 H-1 in De Soto Parish, LA achieved a peak 24-hour rate of 23.4 mmcf per day;

·   The Johnson 21-13-13 H-1 in De Soto Parish, LA achieved a peak 24-hour rate of 18.5 mmcf per day; and

·   The Caspiana 14-15-12H-1 in Caddo Parish, LA achieved a peak 24-hour rate of 18.4 mmcf per day.

Fayetteville Shale (Arkansas):  The Fayetteville Shale is currently the second most productive shale play in the U.S. and one of the nation’s ten largest natural gas fields of any type.  In the Fayetteville, Chesapeake is the second-largest leasehold owner in the Core area of the play with 455,000 net acres.  During the 2009 fourth quarter, Chesapeake’s average daily net production of approximately 310 mmcfe in the Fayetteville increased approximately 25% over the 2009 third quarter and approximately 85% over the 2008 fourth quarter.  Chesapeake is currently producing approximately 340 mmcfe net per day (490 mmcfe gross operated) from the Fayetteville and anticipates maintaining approximately 320 mmcfe net per day (460 mmcfe gross operated) through year-end 2011.

To further develop its 455,000 net acres of Core Fayetteville leasehold, Chesapeake anticipates operating an average of approximately 12 rigs in 2010 to drill approximately 110 net wells.  During 2009, $601 million of Chesapeake’s drilling costs in the Fayetteville were paid for by its joint venture partner, BP America (NYSE:BP).  During the fourth quarter 2009, BP paid Chesapeake the remaining balance of BP’s drilling carry obligations and Chesapeake and BP each began paying their proportionate working interest costs on drilling.

Chesapeake’s leasehold investment in the Fayetteville to date has been approximately $532 million.  By selling a 25% interest in the company’s leasehold to BP for $883 million, the company has more than recouped its entire leasehold investment in the Fayetteville, resulting in a per net acre cost of less than zero.

Three notable recent wells completed by Chesapeake in the Fayetteville are as follows:

·   The Nicholson 7-8 4-10H9 in White County, AR achieved a peak 24-hour rate of 9.2 mmcf per day;

·   The Stroud 7-9 1-23H14 in White County, AR achieved a peak 24-hour rate of 7.9 mmcf per day; and

·   The Gardner 10-13 2-21H in Van Buren County, AR achieved a peak 24-hour rate of 6.2 mmcf per day.

Barnett Shale (North Texas):  The Barnett Shale is currently the largest natural gas producing field in the U.S. and is producing approximately 50% of all shale gas in the U.S.  In this play, Chesapeake is the second-largest producer, the most active driller and the largest leasehold owner in the Core and Tier 1 sweet spots of Tarrant and Johnson counties.  In January 2010, Chesapeake completed its $2.25 billion Barnett Shale joint venture transaction with Total E&P USA, Inc., a wholly-owned subsidiary of Total S.A. (NYSE:TOT, FP:FP) (Total), whereby Total acquired a 25% interest in Chesapeake’s upstream Barnett Shale assets.  Total paid Chesapeake approximately $800 million in cash at closing and will pay a further $1.45 billion over time by funding 60% of Chesapeake’s share of drilling and completion expenditures until the $1.45 billion obligation has been funded, which Chesapeake expects to occur by year-end 2012.

During the 2009 fourth quarter, Chesapeake’s average daily net production of approximately 680 mmcfe in the Barnett increased approximately 7% over the 2009 third quarter and increased approximately 19% over the 2008 fourth quarter.  Chesapeake is currently producing approximately 515 mmcfe net per day (950 mmcfe gross operated) from the Barnett (net production was reduced by 25% as a result of the joint venture with Total) and anticipates reaching approximately 590 mmcfe net per day (1,120 mmcfe gross operated) by year-end 2010 and approximately 665 mmcfe net per day (1,260 mmcfe gross operated) by year-end 2011.

To further develop its 220,000 net acres of leasehold, Chesapeake anticipates operating an average of approximately 28 rigs in 2010 to drill approximately 300 net wells.

Chesapeake’s leasehold investment in the Barnett has been approximately $4.0 billion, of which $1.1 billion, or 26%, will be recouped through the 25% sale of Chesapeake’s interest in its leasehold to Total.  The company’s net investment in its Barnett leasehold is now approximately $13,400 per net acre on average.

Three notable recent wells completed by Chesapeake in the Barnett are as follows:

·   The Auld 1H in Ellis County, TX achieved a peak 24-hour rate of 13.0 mmcf per day;

·   The Crowley Eagles 4H in Tarrant County, TX achieved a peak 24-hour rate of 10.4 mmcf per day; and

·   The Crowley Eagles 1H in Tarrant County, TX achieved a peak 24-hour rate of 9.6 mmcf per day.

Anadarko Basin Granite Wash (western Oklahoma and Texas Panhandle):  In the various Granite Wash plays of the Anadarko Basin, Chesapeake is the largest leasehold owner with approximately 190,000 net acres and is also the most active driller and largest producer.  The Colony Granite Wash and the Texas Panhandle Granite Wash plays highlighted below are two particularly prolific areas within the Anadarko Basin Granite Wash and have become the two highest rate-of-return plays in the company.

Colony Granite Wash (western Oklahoma):  Discovered by Chesapeake in February 2007, the Colony Granite Wash play is primarily located in Custer and Washita counties in Oklahoma and is a subset of the greater Granite Wash plays of the Anadarko Basin.  In the Colony Granite Wash, Chesapeake is the largest leasehold owner with 120,000 net acres and is also the most active driller and largest producer in the play.  During the 2009 fourth quarter, Chesapeake’s average daily net production of approximately 105 mmcfe in the Colony Granite Wash was approximately flat to the 2009 third quarter and increased approximately 47% over the 2008 fourth quarter.  Chesapeake is currently producing approximately 110 mmcfe net per day (200 mmcfe gross operated) from the Colony Granite Wash and anticipates producing approximately 190 mmcfe net per day (350 mmcfe gross operated) by year-end 2010 and approximately 230 mmcfe net per day (420 mmcfe gross operated) by year-end 2011.

To further develop its 120,000 net acres of Colony Granite Wash leasehold, Chesapeake anticipates operating an average of approximately seven rigs in 2010 to drill approximately 40 net wells.  Due in large part to the play’s high oil and natural gas liquids content, the Colony Granite Wash is Chesapeake’s second highest rate-of-return play.

Three notable recent wells completed by Chesapeake in the Colony Granite Wash are as follows:

·   The Shirl Ann 1-14H in Washita County, OK achieved a peak 24-hour rate of 21.8 mmcfe per day

·   The Lee Roy 1-24H in Washita County, OK achieved a peak 24-hour rate of 21.6 mmcfe per day; and

·   The Javorsky 1-33H in Washita County, OK achieved a peak 24-hour rate of 20.6 mmcfe per day.

Texas Panhandle Granite Wash:  The Texas Panhandle Granite Wash play is located in Hemphill, Wheeler and Roberts counties in Texas and is a subset of the greater Granite Wash plays of the Anadarko Basin.  In the Texas Panhandle Granite Wash, Chesapeake is one of the largest leasehold owners with 70,000 net acres and also one of the most active drillers and largest producers in the play.  During the 2009 fourth quarter, Chesapeake’s average daily net production of approximately 100 mmcfe in the Texas Panhandle Granite Wash increased approximately 24% over the 2009 third quarter and increased approximately 20% over the 2008 fourth quarter.  Chesapeake is currently producing approximately 90 mmcfe net per day (130 mmcfe gross operated) from the Texas Panhandle Granite Wash and anticipates producing approximately 125 mmcfe net per day (180 mmcfe gross operated) by year-end 2010 and approximately 130 mmcfe net per day (185 mmcfe gross operated) by year-end 2011.

To further develop its 70,000 net acres of Texas Panhandle Granite Wash leasehold, Chesapeake anticipates operating an average of four rigs in 2010 to drill approximately 30 net wells.  Due in large part to the play’s high oil and natural gas liquids content, the Texas Panhandle Granite Wash is Chesapeake’s highest rate-of-return play.

Three notable recent wells completed by Chesapeake in the Texas Panhandle Granite Wash are as follows:

·   The Ruby Lee 102H in Wheeler County, TX achieved a peak 24-hour rate of 17.8 mmcfe per day;

·   The Ruby Lee 103H in Wheeler County, TX achieved a peak 24-hour rate of 12.8 mmcfe per day; and

·   The Reed T 8H in Wheeler County, TX achieved a peak 24-hour rate of 10.6 mmcfe per day.

2009 Fourth Quarter and Full Year Financial and Operational Results

Conference Call Information

Chesapeake is scheduled to release its 2009 fourth quarter and full year financial results after the close of trading on the New York Stock Exchange on Wednesday, February 17, 2010.  Also, a conference call to discuss this release of operational results and the February 17 release of financial results has been scheduled for Thursday, February 18, 2010, at 9:00 a.m. EST.  The telephone number to access the conference call is 913-312-0688 or toll-free 800-930-1344.  The passcode for the call is 2347767.  We encourage those who would like to participate in the call to dial the access number between 8:50 and 9:00 a.m. EST.  For those unable to participate in the conference call, a replay will be available for audio playback from 1:00 p.m. EST on February 18, 2010 through midnight EST on March 4, 2010.  The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112.  The passcode for the replay is 2347767.  The conference call will also be webcast live on the Internet and can be accessed by going to Chesapeake’s website at www.chk.com in the “Events” subsection of the “Investors” section of our website.  The webcast of the conference call will be available on our website for one year.

This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  Forward-looking statements give our current expectations or forecasts of future events.  They include estimates of natural gas and oil reserves under different pricing assumptions, expected natural gas and oil production, expectations regarding future natural gas and oil prices and costs, and planned drilling activity.  We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.

Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in our 2008 Form 10-K and 2009 second quarter Form 10-Q filed with the U.S. Securities and Exchange Commission on March 2, 2009 and August 10, 2009, respectively.  These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; impacts the current economic downturn may have on our business and financial condition; 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 planned asset monetization transactions, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the amount and timing of development expenditures; exploration and development drilling that does not result in commercially productive reserves; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas and oil sales and the need to secure hedging liabilities; uncertainties in evaluating natural gas and oil reserves of acquired properties and potential liabilities; the negative impact lower natural gas and oil prices could have on our ability to borrow; drilling and operating risks, including potential environmental liabilities; transportation capacity constraints and interruptions that could adversely affect our cash flow; potential increased operating costs resulting from proposed legislative and regulatory changes affecting our operations; and adverse results in pending or future litigation.

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

The SEC requires natural gas and oil companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of natural gas and oil that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.  For filings reporting year-end 2009 reserves, the SEC permits the optional disclosure of probable and possible reserves.  Chesapeake has elected not to report probable and possible reserves in its filings with the SEC.  In this press release, we use the terms "risked and unrisked unproved resources" and "estimated average resources per well" to describe Chesapeake’s internal estimates of volumes of natural gas and oil that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques.  These may be broader descriptions of potentially recoverable volumes than probable and possible reserves, as defined by SEC regulations.  Estimates of unproved resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the company.  We believe our estimates of unproved resources, both risked and unrisked, are reasonable, but such estimates have not been reviewed by independent engineers.  Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.

Chesapeake Energy Corporation is the second-largest producer of natural gas in the U.S.  Headquartered in Oklahoma City, the company's operations are focused on the development of onshore unconventional and conventional natural gas in the U.S. in the Barnett Shale, Haynesville Shale, Fayetteville Shale, Marcellus Shale, Anadarko Basin, Arkoma Basin, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and East Texas regions of the United States.  Further information is available at www.chk.com.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2009 ADDITIONS TO NATURAL GAS AND OIL PROPERTIES

BASED ON SEC PRICING OF 2009 AVERAGE 12-MONTH PRICES

 ($ in millions, except per-unit data)

(unaudited)

	Proved Reserves
	Cost	Bcfe(a)	$/mcfe
Exploration and development costs	$     3,380	4,248(b)	0.80
Acquisition of proved properties	61	33	1.84
Sale of proved properties	(576)	(220)	2.61
Other	131	—	—
Drilling and net acquisition costs	2,996	4,061	0.74
Revisions – price	—	(952)	—
Acquisition of unproved properties and leasehold	2,195	—	—
Sale of unproved properties and leasehold	(1,281)	—	—
Net unproved properties and leasehold  acquisition	914	—	—
Capitalized interest on leasehold and unproved property	627	—	—
Geological and geophysical costs	133	—	—
Capitalized interest and geological and geophysical costs	760	—	—
Subtotal	4,670	3,109	1.50
Asset retirement obligation and other	(2)	—	—
Total costs	$     4,668	3,109	1.50

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

TWELVE MONTHS ENDED DECEMBER 31, 2009

BASED ON SEC PRICING OF 2009 AVERAGE 12-MONTH PRICES

(unaudited)

	Bcfe(a)
Beginning balance, 01/01/09	12,051
Production	(906)
Acquisitions	33
Divestitures	(220)
Revisions – changes to previous estimates	(445)
Revisions – price	(952)
Extensions and discoveries	4,693
Ending balance, 12/31/09	14,254
Proved reserves annual growth rate	18%
Proved developed reserves	8,331
Proved developed reserves percentage	58%
Reserve replacement	3,109
Reserve replacement ratio (c)	343%

(a)   Reserve volumes estimated using new SEC reserve recognition standards and pricing assumptions based on the 2009 unweighted average first-day-of-the-month prices of $3.87 per mcf of natural gas and $61.14 per bbl of oil, before field differential adjustments.

(b)   Includes 445 bcfe of negative revisions resulting from changes to previous estimates and excludes downward revisions of 952 bcfe resulting from a lower natural gas price using the average 12-month price in 2009 compared to the NYMEX spot price as of December 31, 2008.

(c)   The company uses the reserve replacement ratio as an indicator of the company’s ability to replenish annual production volumes and grow its reserves.  It should be noted that the reserve replacement ratio is a statistical indicator that has limitations.  The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions.  Its predictive and comparative value is also limited for the same reasons.  In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2009 ADDITIONS TO NATURAL GAS AND OIL PROPERTIES

BASED ON SPOT PRICES AT DECEMBER 31, 2009

 ($ in millions, except per-unit data)

(unaudited)

	Proved Reserves
	Cost	Bcfe(a)	$/mcfe
Exploration and development costs	$     3,380	4,241(b)	0.80
Acquisition of proved properties	61	39	1.57
Sale of proved properties	(576)	(220)	2.61
Other	131	—	—
Drilling and net acquisition costs	2,996	4,060	0.74
Revisions – price	—	104	—
Acquisition of unproved properties and leasehold	2,195	—	—
Sale of unproved properties and leasehold	(1,281)	—	—
Net unproved properties and leasehold  acquisition	914	—	—
Capitalized interest on leasehold and unproved property	627	—	—
Geological and geophysical costs	133	—	—
Capitalized interest and geological and geophysical costs	760	—	—
Subtotal	4,670	4,164	1.12
Asset retirement obligation and other	(2)	—	—
Total costs	$     4,668	4,164	1.12

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

TWELVE MONTHS ENDED DECEMBER 31, 2009

BASED ON SPOT PRICES AT DECEMBER 31, 2009

(unaudited)

	Bcfe(a)
Beginning balance, 01/01/09	12,051
Production	(906)
Acquisitions	39
Divestitures	(220)
Revisions – changes to previous estimates	(515)
Revisions – price	104
Extensions and discoveries	4,756
Ending balance, 12/31/09	15,309
Proved reserves annual growth rate	27%
Proved developed reserves	8,828
Proved developed reserves percentage	58%
Reserve replacement	4,164
Reserve replacement ratio (c)	460%

(a)   Reserve volumes estimated using new SEC reserve recognition standards and NYMEX spot prices at December 31, 2009 of $5.79 per mcf of natural gas and $79.34 per bbl of oil, before field differential adjustments.

(b)   Includes 515 bcfe of negative revisions resulting from changes to previous estimates and excludes upward revisions of 104 bcfe resulting from higher natural gas and oil prices using NYMEX spot prices as of December 31, 2009 compared to NYMEX spot prices as of December 31, 2008.

(c)   The company uses the reserve replacement ratio as an indicator of the company’s ability to replenish annual production volumes and grow its reserves.  It should be noted that the reserve replacement ratio is a statistical indicator that has limitations.  The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions.  Its predictive and comparative value is also limited for the same reasons.  In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2009 ADDITIONS TO NATURAL GAS AND OIL PROPERTIES

BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT DECEMBER 31, 2009

 ($ in millions, except per-unit data)

(unaudited)

	Proved Reserves
	Cost	Bcfe(a)	$/mcfe
Exploration and development costs	$     3,380	4,303(b)	0.79
Acquisition of proved properties	61	40	1.52
Sale of proved properties	(576)	(220)	2.61
Other	131	—	—
Drilling and net acquisition costs	2,996	4,123	0.73
Revisions – price	—	272	—
Acquisition of unproved properties and leasehold	2,195	—	—
Sale of unproved properties and leasehold	(1,281)	—	—
Net unproved properties and leasehold acquisition	914	—	—
Capitalized interest on leasehold and unproved property	627	—	—
Geological and geophysical costs	133	—	—
Capitalized interest and geological and geophysical costs	760	—	—
Subtotal	4,670	4,395	1.06
Asset retirement obligation and other	(2)	—	—
Total costs	$     4,668	4,395	1.06

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

TWELVE MONTHS ENDED DECEMBER 31, 2009

BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT DECEMBER 31, 2009

(unaudited)

	Bcfe(a)
Beginning balance, 01/01/09	12,051
Production	(906)
Acquisitions	40
Divestitures	(220)
Revisions – changes to previous estimates	(477)
Revisions – price	272
Extensions and discoveries	4,780
Ending balance, 12/31/09	15,540
Proved reserves annual growth rate	29%
Proved developed reserves	9,005
Proved developed reserves percentage	58%
Reserve replacement	4,395
Reserve replacement ratio (c)	485%

(a)   Reserve volumes estimated using new SEC reserve recognition standards and 10-year average NYMEX strip prices as of December 31, 2009 of $6.94 per mcf of natural gas and $92.24 per bbl of oil, before field differential adjustments.  Chesapeake uses such forward-looking market-based data in developing its drilling plans, assessing its capital expenditure needs and projecting future cash flows.  Chesapeake believes these prices are better indicators of the likely economic producibility of proved reserves than the trailing average 12-month price required by the SEC's reporting rule or a period-end spot price, as previously required in SEC reporting.

(b)   Includes 477 bcfe of negative revisions resulting from changes to previous estimates and excludes upward revisions of 272 bcfe resulting from higher natural gas and oil prices using 10-year average NYMEX strip prices as of December 31, 2009 compared to NYMEX spot prices as of December 31, 2008.

(c)   The company uses the reserve replacement ratio as an indicator of the company’s ability to replenish annual production volumes and grow its reserves.  It should be noted that the reserve replacement ratio is a statistical indicator that has limitations.  The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions.  Its predictive and comparative value is also limited for the same reasons.  In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF PV-10

($ in millions)

(unaudited)

	December 31, 2009		December 31, 2008
Standardized measure of discounted future net of cash flows	$	8,203	$	11,833
Discounted future cash flows for income taxes		1,246		3,768
Discounted future net cash flows before income taxes (PV-10)	$	9,449	$	15,601

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

The company's December 31, 2009 PV-10 and standardized measure were calculated using the unweighted average first-of-the-month prices for the twelve months in 2009 of $3.87 per mcf and $61.14 per bbl, before field differential adjustments.  The company's December 31, 2008 PV-10 and standardized measure were calculated using year-end 2008 spot prices of $5.71 per mcf and $44.61 per bbl, before field differential adjustments.

EX-99.1

Exhibit 99.2

  N e w s   R e l e a s e Chesapeake Energy Corporation P. O. Box 18496 Oklahoma City, OK  73154

FOR IMMEDIATE RELEASE

FEBRUARY 17, 2010

INVESTOR CONTACTS:	MEDIA CONTACT:
JEFFREY L. MOBLEY, CFA (405) 767-4763 jeff.mobley@chk.com JOHN J. KILGALLON (405) 935-4441 john.kilgallon@chk.com	JIM GIPSON  (405) 935-1310 jim.gipson@chk.com

CHESAPEAKE ENERGY CORPORATION REPORTS FINANCIAL RESULTS

FOR THE 2009 FOURTH QUARTER AND FULL YEAR

Company Reports 2009 Fourth Quarter Net Loss to Common Shareholders of $530 Million,

or $0.84 per Fully Diluted Common Share, on Revenue of $2.2 Billion; Adjusted

Net Income Available to Common Shareholders Was $490 Million,

or $0.77 per Fully Diluted Common Share

2009 Full Year Net Loss to Common Shareholders Was $5.9 Billion, or $9.57 per

 Fully Diluted Common Share, on Revenue of $7.7 Billion; Adjusted Net Income

 Available to Common Shareholders Was $1.6 Billion,

or $2.55 per Fully Diluted Common Share

2009 Fourth Quarter Production of 2.6 Bcfe per Day Increases 13% Over 2008 Fourth

Quarter Production; 2009 Full Year Production of 2.5 Bcfe per Day

Increases 8% Over 2008 Full Year Production

OKLAHOMA CITY, OKLAHOMA, FEBRUARY 17, 2010 – Chesapeake Energy Corporation (NYSE:CHK) today announced financial results for the 2009 fourth quarter and full year.  For the 2009 fourth quarter, Chesapeake reported a net loss to common shareholders of $530 million ($0.84 per fully diluted common share) and operating cash flow (defined as cash flow from operating activities before changes in assets and liabilities) of $1.212 billion on revenue of $2.222 billion and production of 241 billion cubic feet of natural gas equivalent (bcfe).  For the 2009 full year, Chesapeake reported a net loss to common shareholders of $5.853 billion ($9.57 per fully diluted common share) and operating cash flow of $4.333 billion on revenue of $7.702 billion and production of 906 bcfe.

The company’s 2009 fourth quarter and full year results include a realized natural gas and oil hedging gain of $544 million and $2.346 billion, respectively.  The results also include various items that are typically not included in published estimates of the company’s financial results by certain securities analysts.  Excluding the items detailed below, for the 2009 fourth quarter, Chesapeake reported adjusted net income to common shareholders of $490 million ($0.77 per fully diluted common share) and adjusted ebitda of $1.256 billion.  For the 2009 full year, Chesapeake generated adjusted net income to common shareholders of $1.585 billion ($2.55 per fully diluted common share) and adjusted ebitda of $4.407 billion.  The excluded items and their effects on 2009 fourth quarter and full year reported results are detailed as follows:

·   a net non-cash unrealized after-tax mark-to-market loss of $126 million for 2009 fourth quarter and $311 million for the full year resulting from the company’s natural gas, oil and interest rate hedging programs;

·   a non-cash after-tax impairment charge of $875 million for the 2009 fourth quarter and $6.875 billion for the full year related to the carrying value of natural gas and oil properties under the full-cost method of accounting;

·   a non-cash combined after-tax impairment charge of $5 million for the 2009 fourth quarter and $80 million for the full year related primarily to certain midstream assets contributed to the newly formed midstream joint venture with Global Infrastructure Partners;

·   a non-cash after-tax impairment charge of $102 million for the full year related to certain investments;

·   a non-cash after-tax charge of $14 million for the 2009 fourth quarter and $25 million for the full year on exchanges of certain of the company’s contingent convertible senior notes for shares of common stock; and

·   a combined after-tax charge of $45 million for the 2009 full year related to restructuring and relocation costs related to the company’s Eastern Division, other workforce reduction costs and losses on the sales of certain gathering systems.

The various items described above do not materially affect the calculation of operating cash flow.  A reconciliation of operating cash flow, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 12 – 16 of this release.

Key Operational and Financial Statistics Summarized

The table below summarizes Chesapeake’s key results during the 2009 fourth quarter and compares them to results during the 2009 third quarter and the 2008 fourth quarter and also compares the 2009 full year to the 2008 full year.

	Three Months Ended							Full Year Ended
	12/31/09		9/30/09			12/31/08(a)		12/31/09	12/31/08(a)
Average daily production (in mmcfe)		2,618		2,483			2,316	2,481	2,303
Natural gas as % of total production		93		92			92	92	92
Natural gas production (in bcf)		224.5		210.3			196.0	834.8	775.4
Average realized natural gas price ($/mcf) (b)		6.05		6.04			7.13	5.93	8.09
Oil production (in mbbls)		2,737		3,027			2,848	11,790	11,220
Average realized oil price ($/bbl) (b)		71.61		66.42			54.80	58.38	70.48
Natural gas equivalent production (in bcfe)		240.9		228.5			213.1	905.5	842.7
Natural gas equivalent realized price ($/mcfe) (b)		6.45		6.44			7.29	6.22	8.38
Marketing, gathering and compression
net margin ($/mcfe)		.23		.13			.11	.16	.11
Service operations net margin ($/mcfe)		.02		.00			.04	.01	.04
Production expenses ($/mcfe)		(.86)		(.96	)		(1.09)	(.97)	(1.05)
Production taxes ($/mcfe)		(.15)		(.11	)		(.16)	(.12)	(.34)
General and administrative costs ($/mcfe) (c)		(.28)		(.32	)		(.33)	(.29)	(.35)
Stock-based compensation ($/mcfe)		(.09)		(.09	)		(.09)	(.09)	(.10)
DD&A of natural gas and oil properties ($/mcfe)		(1.39)		(1.29	)		(2.12)	(1.51)	(2.34)
D&A of other assets ($/mcfe)		(.28)		(.27	)		(.24)	(.27)	(.21)
Interest expense ($/mcfe) (b)		(.19)		(.28	)		.05	(.22)	(.22)
Operating cash flow ($ in millions) (d)		1,212		1,116			1,054	4,333	5,299
Operating cash flow ($/mcfe)		5.03		4.89			4.95	4.78	6.29
Adjusted ebitda ($ in millions) (e)		1,256		1,133			1,242	4,407	5,633
Adjusted ebitda ($/mcfe)		5.21		4.96			5.83	4.87	6.68
Net income to common shareholders ($ in millions)		(530)		186			(1,001)	(5,853)	504
Earnings per share – assuming dilution ($)		(.84)		.30			(1.74)	(9.57)	.93
Adjusted net income to common shareholders ($ in millions) (f)		490		440			438	1,585	1,981
Adjusted earnings per share – assuming dilution ($)		.77		.70			.75	2.55	3.60

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options
(b)	Includes the effects of realized gains (losses) from hedging, but does not include the effects of unrealized gains (losses) from hedging
(c)	Excludes expenses associated with noncash stock-based compensation
(d)	Defined as cash flow provided by operating activities before changes in assets and liabilities
(e)	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 14
(f)	Defined as net income (loss) available to common shareholders, as adjusted to remove the effects of certain items detailed on pages 15 and 16

2009 Fourth Quarter Average Daily Production Increases 5% Over 2009 Third Quarter

Production and 13% Over 2008 Fourth Quarter Production; 2009 Full Year Average

Daily Production Increases 8% Over 2008 Full Year Average Daily Production,

Setting Record for 20th Consecutive Year

As announced on February 16, 2010, Chesapeake’s daily production for the 2009 fourth quarter averaged 2.618 bcfe, an increase of 135 million cubic feet of natural gas equivalent (mmcfe), or 5%, over the 2.483 bcfe produced per day in the 2009 third quarter and an increase of 302 mmcfe, or 13%, over the 2.316 bcfe produced per day in the 2008 fourth quarter.  Adjusted for the company’s voluntary production curtailments due to low natural gas prices (approximately 26 mmcfe per day during the 2009 fourth quarter), the company’s volumetric production payment transactions (which combined averaged approximately 96 mmcfe per day during the 2009 fourth quarter) and the estimated impact from various divestitures (which would have averaged approximately 49 mmcfe per day during the 2009 fourth quarter), Chesapeake’s sequential and year-over-year production growth rates would have been 5% and 17%, respectively, after making similar adjustments to prior quarters.  Chesapeake’s 2009 fourth quarter average daily production of 2.618 bcfe consisted of 2.440 billion cubic feet of natural gas (bcf) and 29,750 barrels of oil and natural gas liquids (bbls).  The company’s 2009 fourth quarter production of 241 bcfe was comprised of 225 bcf (93% on a natural gas equivalent basis) and 2.7 million barrels of oil and natural gas liquids (mmbbls) (7% on a natural gas equivalent basis).

The company’s daily production for the 2009 full year averaged 2.481 bcfe, an increase of 178 mmcfe, or 8%, over the 2.303 bcfe of daily production for the 2008 full year.  Adjusted for the company’s voluntary production curtailments due to low natural gas prices (approximately 47 mmcfe per day during the 2009 full year), the company’s volumetric production payment transactions (which combined averaged approximately 157 mmcfe per day during the 2009 full year) and the estimated impact from various divestitures (which would have averaged approximately 193 mmcfe per day during the 2009 full year), Chesapeake’s year-over-year production growth rate would have been 19%, after making similar adjustments to the 2008 full year.  Chesapeake’s average daily production for the 2009 full year of 2.481 bcfe consisted of 2.287 bcf and 32,301 bbls.  The company’s 2009 full year production of 906 bcfe was comprised of 835 bcf (92% on a natural gas equivalent basis) and 11.8 mmbbls (8% on a natural gas equivalent basis).  The 2009 full year was Chesapeake’s 20th consecutive year of sequential production growth.  Chesapeake anticipates delivering full-year production growth of approximately 8-10% in 2010 and 15-17% in 2011, net of property divestitures.

Average Realized Prices, Hedging Results and Hedging Positions Detailed

Average prices realized during the 2009 fourth quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives), were $6.05 per thousand cubic feet (mcf) and $71.61 per bbl, for a realized natural gas equivalent price of $6.45 per thousand cubic feet of natural gas equivalent (mcfe).  Realized gains from natural gas and oil hedging activities during the 2009 fourth quarter generated a $2.42 gain per mcf and a $0.69 gain per bbl for a 2009 fourth quarter realized hedging gain of $544 million, or $2.26 per mcfe.  Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2009 fourth quarter were a negative $0.53 per mcf and a negative $5.27 per bbl.

By comparison, average prices realized during the 2008 fourth quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $7.13 per mcf and $54.80 per bbl, for a realized natural gas equivalent price of $7.29 per mcfe.  Realized gains from natural gas and oil hedging activities during the 2008 fourth quarter generated a $2.25 gain per mcf and a $1.61 gain per bbl for a 2008 fourth quarter realized hedging gain of $446 million, or $2.09 per mcfe.  Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2008 fourth quarter were a negative $2.07 per mcf and a negative $5.55 per bbl.

For the 2009 full year, average prices realized (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.93 per mcf and $58.38 per bbl, for a realized natural gas equivalent price of $6.22 per mcfe.  Realized gains and losses from natural gas and oil hedging activities during the 2009 full year generated a $2.77 gain per mcf and a $2.78 gain per bbl for a 2009 full year realized hedging gain of $2.346 billion, or $2.59 per mcfe.  Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2009 full year were a negative $0.83 per mcf and a negative $6.20 per bbl.

By comparison, average prices realized during the 2008 full year (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $8.09 per mcf and $70.48 per bbl, for a realized natural gas equivalent price of $8.38 per mcfe.  Realized gains and losses from natural gas and oil hedging activities during the 2008 full year generated a $0.35 gain per mcf and a $24.56 loss per bbl for a 2008 full year realized hedging loss of $8 million, or $0.01 per mcfe.  Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2008 full year were a negative $1.30 per mcf and a negative $4.61 per bbl.

The following tables summarize Chesapeake’s open hedge position through swaps and collars as of February 17, 2010.  Depending on changes in natural gas and oil futures markets and management’s view of underlying natural gas and oil supply and demand trends, Chesapeake may either increase or decrease its hedging positions at any time in the future without notice.

Open Swap Positions as of February 17, 2010

	Natural Gas		Oil
Year	% Hedged	$ NYMEX	% Hedged	$ NYMEX
2010	53%	7.58	59%	89.62
2011	7%	8.71	19%	96.09

Open Natural Gas Collar Positions as of February 17, 2010

		Average Floor	Average Ceiling
Year	% Hedged	$ NYMEX	$ NYMEX
2010	8%	6.75	9.03
2011	1%	7.70	11.50

Note:  Certain open natural gas swap positions include knockout swaps with knockout provisions at prices ranging from $5.50 to $6.75 per mcf covering 15 bcf in 2010, or approximately 3% of the company’s natural gas swap positions in 2010, and $5.75 to $6.50 per mcf covering 24 bcf in 2011, or approximately 33% of the company’s natural gas swap positions in 2011.  Certain open natural gas collar positions include three-way collars that include written put options with strike prices ranging from $4.25 to $4.35 per mcf covering 12 bcf in 2010, or approximately 18% of the company’s natural gas collar positions in 2010.  Also, certain open oil swap positions include knockout swaps with knockout provisions at a price of $60 per bbl covering 5 mmbbls and 1 mmbbls in 2010 and 2011, respectively, or approximately 52% and 33% of the company’s oil swap positions in 2010 and in 2011, respectively.

As of February 12, 2010, Chesapeake’s natural gas and oil hedging positions with 14 different counterparties had a positive mark-to-market value of approximately $95 million.  The company’s realized hedging gains for the 2009 full year were $2.346 billion and since January 1, 2001 have been $4.421 billion.

The company’s updated forecasts for 2010 and 2011 are attached to this release in an Outlook dated February 17, 2010, labeled as Schedule “A,” which begins on page 17.  This Outlook has been changed from the Outlook dated January 4, 2010, attached as Schedule “B,” which begins on page 21, to reflect various updated information.

Company Closes Barnett Shale Joint Venture with Total and

Closes Sixth Volumetric Production Payment Transaction

As previously disclosed, on January 26, 2010, Chesapeake and Total E&P USA, Inc., a wholly-owned subsidiary of Total S.A. (NYSE: TOT, FP: FP) (“Total”), closed the $2.25 billion Barnett Shale joint venture transaction, whereby Total acquired a 25% interest in Chesapeake’s upstream Barnett Shale assets.  Total paid Chesapeake approximately $800 million in cash at closing and will pay a further $1.45 billion over time by funding 60% of Chesapeake’s share of future drilling and completion expenditures.  Chesapeake expects this drilling carry to be funded by year-end 2012.  Additionally, on February 5, 2010 the company sold certain Chesapeake-operated long-lived producing assets in East Texas and the Texas Gulf Coast in its sixth volumetric production payment (VPP) transaction for proceeds of $180 million, or $3.95 per mcfe of proved reserves.  The assets in the VPP included proved reserves of approximately 45.5 bcfe and current net production of approximately 20 mmcfe per day. 

Conference Call Information

A conference call to discuss this release of financial results and the company's release of its operational results issued on February 16, 2010 has been scheduled for Thursday morning, February 18, 2010, at 9:00 a.m. EST.  The telephone number to access the conference call is913-312-0688 or toll-free 800-930-1344.  The passcode for the call is 2347767.  We encourage those who would like to participate in the call to dial the access number between 8:50 and 9:00 a.m. EST.  For those unable to participate in the conference call, a replay will be available for audio playback from 1:00 p.m. EST on February 18, 2010 through midnight EST on March 4, 2010.  The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112.  The passcode for the replay is 2347767.  The conference call will also be webcast live on the Internet and can be accessed by going to Chesapeake’s website at www.chk.com in the “Events” subsection of the “Investors” section of our website.  The webcast of the conference call will be available on our website for one year.

This press release and the accompanying Outlooks include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  Forward-looking statements give our current expectations or forecasts of future events.  They include expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, planned capital expenditures and anticipated asset acquisitions and sales, projected cash flow and liquidity, business strategy and other plans and objectives for future operations.  Disclosures concerning the fair value of derivative contracts and their estimated contribution 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 press release, and we undertake no obligation to update this information.

Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in our 2008 Form 10-K and 2009 second quarter Form 10-Q filed with the U.S. Securities and Exchange Commission on March 2, 2009 and August 10, 2009, respectively.  These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; impacts the current economic downturn may have on our business and financial condition; 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 planned asset monetization transactions, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the amount and timing of development expenditures; exploration and development drilling that does not result in commercially productive reserves; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas and oil sales and the need to secure hedging liabilities; uncertainties in evaluating natural gas and oil reserves of acquired properties and potential liabilities; the negative impact lower natural gas and oil prices could have on our ability to borrow; drilling and operating risks, including potential environmental liabilities; transportation capacity constraints and interruptions that could adversely affect our cash flow; potential increased operating costs resulting from proposed legislative and regulatory changes affecting our operations; and adverse results in pending or future litigation.

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

Chesapeake Energy Corporation is the second-largest producer of natural gas in the U.S.  Headquartered in Oklahoma City, the company's operations are focused on the development of onshore unconventional and conventional natural gas in the U.S. in the Barnett Shale, Haynesville Shale, Fayetteville Shale, Marcellus Shale, Anadarko Basin, Arkoma Basin, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and East Texas regions of the United States.  Further information is available at www.chk.com.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)

THREE MONTHS ENDED:	December 31,					December 31,
	2009					2008 (a)
	$			$/mcfe		$			$/mcfe
REVENUES:
Natural gas and oil sales		1,368		5.68			2,271		10.66
Marketing, gathering and compression sales		803		3.33			664		3.12
Service operations revenue		51		0.21			46		0.21
Total Revenues		2,222		9.22			2,981		13.99
OPERATING COSTS:
Production expenses		206		0.86			231		1.09
Production taxes		36		0.15			35		0.16
General and administrative expenses		89		0.37			89		0.42
Marketing, gathering and compression expenses		747		3.10			641		3.01
Service operations expense		47		0.19			38		0.17
Natural gas and oil depreciation, depletion and amortization		335		1.39			452		2.12
Depreciation and amortization of other assets		67		0.28			50		0.24
Impairment of natural gas and oil properties and other assets		1,408		5.84			2,830		13.28
Total Operating Costs		2,935		12.18			4,366		20.49
INCOME (LOSS) FROM OPERATIONS		(713	)	(2.96	)		(1,385	)	(6.50	)
OTHER INCOME (EXPENSE):
Other income (expense)		(2	)	(0.01	)		12		0.05
Interest expense		(62	)	(0.25	)		(84	)	(0.40	)
Impairment of investments		—		—			(180	)	(0.84	)
Gain (Loss) on exchanges of Chesapeake debt		(21	)	(0.09	)		27		0.13
Total Other Income (Expense)		(85	)	(0.35	)		(225	)	(1.06	)
INCOME (LOSS) BEFORE INCOME TAXES		(798	)	(3.31	)		(1,610	)	(7.56	)
Income Tax Expense (Benefit):
Current income taxes		3		0.01			227		1.06
Deferred income taxes		(302	)	(1.25	)		(842	)	(3.95	)
Total Income Tax Expense  (Benefit)		(299	)	(1.24	)		(615	)	(2.89	)
NET INCOME (LOSS)		(499	)	(2.07	)		(995	)	(4.67	)
Net (income) loss attributable to noncontrolling interest		(25	)	(0.11	)		—		—
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE		(524	)	(2.18	)		(995	)	(4.67	)
Preferred stock dividends		(6	)	(0.02	)		(6	)	(0.03	)
NET INCOME (LOSS) AVAILABLE TO CHESAPEAKE   COMMON STOCKHOLDERS		(530	)	(2.20	)		(1,001	)	(4.70	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	(0.84	)			$	(1.74	)
Assuming dilution	$	(0.84	)			$	(1.74	)
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)
Basic		628					575
Assuming dilution		628					575

(a) Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)

TWELVE MONTHS ENDED:	December 31,					December 31,
	2009					2008 (a)
	$			$/mcfe		$			$/mcfe
REVENUES:
Natural gas and oil sales		5,049		5.57			7,858		9.32
Marketing, gathering and compression sales		2,463		2.72			3,598		4.27
Service operations revenue		190		0.21			173		0.21
Total Revenues		7,702		8.50			11,629		13.80
OPERATING COSTS:
Production expenses		876		0.97			889		1.05
Production taxes		107		0.12			284		0.34
General and administrative expenses		349		0.38			377		0.45
Marketing, gathering and compression expenses		2,316		2.56			3,505		4.16
Service operations expense		182		0.20			143		0.17
Natural gas and oil depreciation, depletion and amortization		1,371		1.51			1,970		2.34
Depreciation and amortization of other assets		244		0.27			174		0.21
Impairment of natural gas and oil properties and other assets		11,130		12.29			2,830		3.35
Loss on sale of other property and equipment		38		0.04			—		—
Restructuring costs		34		0.04			—		—
Total Operating Costs		16,647		18.38			10,172		12.07
INCOME (LOSS) FROM OPERATIONS		(8,945	)	(9.88	)		1,457		1.73
OTHER INCOME (EXPENSE):
Other income (expense)		(28	)	(0.03	)		(11	)	(0.01	)
Interest expense		(113	)	(0.13	)		(271	)	(0.32	)
Impairment of investments		(162	)	(0.18	)		(180	)	(0.21	)
Loss on exchanges or repurchases of Chesapeake debt		(40	)	(0.04	)		(4	)	(0.01	)
Total Other Income (Expense)		(343	)	(0.38	)		(466	)	(0.55	)
INCOME (LOSS) BEFORE INCOME TAXES		(9,288	)	(10.26	)		991		1.18
Income Tax Expense (Benefit):
Current income taxes		4		—			423		0.50
Deferred income taxes		(3,487	)	(3.85	)		(36	)	(0.04	)
Total Income Tax Expense (Benefit)		(3,483	)	(3.85	)		387		0.46
NET INCOME (LOSS)		(5,805	)	(6.41	)		604		0.72
Net (income) loss attributable to noncontrolling interest		(25	)	(0.03	)		—		—
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE		(5,830	)	(6.44	)		604		0.72
Preferred stock dividends		(23	)	(0.02	)		(33	)	(0.04	)
Loss on conversion/exchange of preferred stock		—		—			(67	)	(0.08	)
NET INCOME (LOSS) AVAILABLE TO CHESAPEAKE COMMON STOCKHOLDERS		(5,853	)	(6.46	)		504		0.60
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	(9.57	)			$	0.94
Assuming dilution	$	(9.57	)			$	0.93
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)
Basic		612					536
Assuming dilution		612					545

(a) Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)

	December 31,		December 31,
	2009		2008 (a)
Cash and cash equivalents	$	307	$	1,749
Other current assets		2,139		2,543
Total Current Assets		2,446		4,292
Property and equipment (net)		26,710		33,308
Other assets		758		993
Total Assets	$	29,914	$	38,593
Current liabilities	$	2,688	$	3,621
Long-term debt, net (b)		12,295		13,175
Asset retirement obligation		282		269
Other long-term liabilities		1,249		311
Deferred tax liability		1,059		4,200
Total Liabilities		17,573		21,576
Chesapeake Stockholders’ Equity		11,444		17,017
Noncontrolling interest		897		—
Total equity		12,341		17,017
Total Liabilities & Equity	$	29,914	$	38,593
Common Shares Outstanding (in millions)		648		607

CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

($ in millions)

(unaudited)

	December 31,	% of Total Book	December 31,	% of Total Book
	2009	Capitalization	2008 (a)	Capitalization
Total debt, net of cash (b)	$11,988	49%	$11,426	40%
Chesapeake Stockholders' equity	11,444	47%	17,017	60%
Noncontrolling interest	897	4%	—	—
Total	$24,329	100%	$28,443	100%

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.
(b)	Includes $1.936 billion of borrowings under the company’s $3.5 billion revolving bank credit facility, the company’s $250 million midstream revolving bank credit facility and the company’s $500 million midstream joint venture revolving bank credit facility.  At December 31, 2009, the company had $2.273 billion of additional borrowing capacity under these three revolving bank credit facilities.

CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA – NATURAL GAS AND OIL SALES AND INTEREST EXPENSE

 (unaudited)

	THREE MONTHS ENDED						TWELVE MONTHS ENDED
	DECEMBER 31,							DECEMBER 31,
		2009			2008			2009			2008
Natural Gas and Oil Sales ($ in millions):
Natural gas sales	$	816		$	957			$	2,635		$	6,003
Natural gas derivatives – realized gains (losses)		542			441				2,313			267
Natural gas derivatives – unrealized gains (losses)		(94	)		195				(492	)		521
Total Natural Gas Sales		1,264			1,593				4,456			6,791
Oil sales		194			151				656			1,066
Oil derivatives – realized gains (losses)		2			5				33			(275	)
Oil derivatives – unrealized gains (losses)		(92	)		522				(96	)		276
Total Oil Sales		104			678				593			1,067
Total Natural Gas and Oil Sales	$	1,368		$	2,271			$	5,049		$	7,858
Average Sales Price – excluding gains (losses) on derivatives:
Natural gas ($ per mcf)	$	3.63		$	4.88			$	3.16		$	7.74
Oil ($ per bbl)	$	70.92		$	53.19			$	55.60		$	95.04
Natural gas equivalent ($ per mcfe)	$	4.19		$	5.20			$	3.63		$	8.39
Average Sales Price – excluding unrealized gains (losses)  on derivatives:
Natural gas ($ per mcf)	$	6.05		$	7.13			$	5.93		$	8.09
Oil ($ per bbl)	$	71.61		$	54.80			$	58.38		$	70.48
Natural gas equivalent ($ per mcfe)	$	6.45		$	7.29			$	6.22		$	8.38
Interest Expense (Income) ($ in millions):(a)
Interest	$	50		$	(3	)		$	227		$	192
Derivatives – realized (gains) losses		(4	)		(7	)			(23	)		(6	)
Derivatives – unrealized (gains) losses		16			94				(91	)		85
Total Interest Expense	$	62		$	84			$	113		$	271

(a) Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

($ in millions)

(unaudited)

THREE MONTHS ENDED:	December 31,			December 31,
	2009			2008 (a)
Beginning cash	$	520		$	1,964
Cash provided by operating activities	$	1,226		$	971
Cash (used in) provided by investing activities:
Exploration and development of natural gas and oil properties	$	(776	)	$	(1,483	)
Acquisitions of natural gas and oil companies, proved and unproved properties and leasehold, net of cash acquired		(927	)		(902	)
Proceeds from divestitures of proved and unproved properties, leasehold and VPPs		197			1,794
Additions to other property and equipment		(321	)		(1,104	)
Proceeds from sales of drilling rigs and compressors		—			18
Other		19			(6	)
Total cash used in investing activities	$	(1,808	)	$	(1,683	)
Cash provided by financing activities	$	369		$	497
Ending cash	$	307		$	1,749

TWELVE MONTHS ENDED:	December 31,			December 31,
	2009			2008 (a)
Beginning cash	$	1,749		$	1
Cash provided by operating activities	$	4,356		$	5,357
Cash (used in) provided by investing activities:
Exploration and development of natural gas and oil properties	$	(3,543	)	$	(6,104	)
Acquisitions of natural gas and oil companies, proved and unproved properties and leasehold, net of cash acquired		(2,298	)		(8,593	)
Proceeds from divestitures of proved and unproved properties, leasehold and VPPs		1,926			7,670
Additions to other property and equipment		(1,683	)		(3,073	)
Proceeds from sales of drilling rigs and compressors		68			178
Other		68			(43	)
Total cash used in investing activities	$	(5,462	)	$	(9,965	)
Cash (used in) provided by financing activities	$	(336	)	$	6,356
Ending cash	$	307		$	1,749

(a) Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)

THREE MONTHS ENDED:	December 31,			September 30,			December 31,
	2009			2009			2008 (a)
CASH PROVIDED BY OPERATING ACTIVITIES	$	1,226		$	1,132		$	971
Changes in assets and liabilities		(14	)		(16	)		83
OPERATING CASH FLOW (b)	$	1,212		$	1,116		$	1,054

THREE MONTHS ENDED:	December 31,			September 30,		December 31,
	2009			2009		2008 (a)
NET INCOME (LOSS)	$	(499	)	$	192	$	(995	)
Income tax expense (benefit)		(299	)		115		(615	)
Interest expense		62			43		84
Depreciation and amortization of other assets		67			62		50
Natural gas and oil depreciation, depletion and amortization		335			295		452
EBITDA (c)	$	(334	)	$	707	$	(1,024	)

THREE MONTHS ENDED:	December 31,			September 30,			December 31,
	2009			2009			2008 (a)
CASH PROVIDED BY OPERATING ACTIVITIES	$	1,226		$	1,132		$	971
Changes in assets and liabilities		(14	)		(16	)		83
Interest expense		62			43			84
Unrealized gains (losses) on natural gas and oil derivatives		(186	)		(285	)		717
Impairment of natural gas and oil properties and other assets		(1,408	)		(86	)		(2,830	)
Loss on sale of other property and equipment		—			(38	)		—
Impairment of investments		—			—			(180	)
Other non-cash items		(14	)		(43	)		131
EBITDA (c)	$	(334	)	$	707		$	(1,024	)

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.
(b)	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.
(c)	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 and our senior note indentures.  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)

TWELVE MONTHS ENDED:	December 31,			December 31,
	2009			2008 (a)
CASH PROVIDED BY OPERATING ACTIVITIES	$	4,356		$	5,357
Changes in assets and liabilities		(23	)		(58	)
OPERATING CASH FLOW (b)	$	4,333		$	5,299

TWELVE MONTHS ENDED:	December 31,			December 31,
	2009			2008 (a)
NET INCOME (LOSS)	$	(5,805	)	$	604
Income tax expense (benefit)		(3,483	)		387
Interest expense		113			271
Depreciation and amortization of other assets		244			174
Natural gas and oil depreciation, depletion and amortization		1,371			1,970
EBITDA (c)	$	(7,560	)	$	3,406

TWELVE MONTHS ENDED:	December 31,			December 31,
	2009			2008 (a)
CASH PROVIDED BY OPERATING ACTIVITIES	$	4,356		$	5,357
Changes in assets and liabilities		(23	)		(58	)
Interest expense		113			271
Unrealized gains (losses) on natural gas and oil derivatives		(588	)		797
Impairment of natural gas and oil properties and other assets		(11,130	)		(2,830	)
Loss on sale of other property and equipment		(38	)		—
Impairment of investments		(162	)		(180	)
Restructuring costs		(12	)		—
Other non-cash items		(76	)		49
EBITDA (c)	$	(7,560	)	$	3,406

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.
(b)	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.
(c)	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 and our senior note indentures.  Ebitda is not a measure of financial performance under GAAP.  Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED EBITDA

($ in millions)

(unaudited)

	December 31,			September 30,		December 31,
THREE MONTHS ENDED:	2009			2009		2008 (a)
EBITDA	$	(334	)	$	707	$	(1,024	)
Adjustments, before tax:
(Income) attributable to noncontrolling interest		(25	)		—		—
Unrealized (gains) losses on natural gas and oil derivatives		186			285		(717	)
Loss (gain) on exchanges of Chesapeake debt		21			17		(27	)
Impairment of natural gas and oil properties and other assets		1,408			86		2,830
Loss on sale of other property and equipment		—			38		—
Impairment of investments		—			—		180
Adjusted ebitda (b)	$	1,256		$	1,133	$	1,242

	December 31,			December 31,
TWELVE  MONTHS ENDED:	2009			2008 (a)
EBITDA	$	(7,560	)	$	3,406
Adjustments, before tax:
(Income) attributable to noncontrolling interest		(25	)		—
Unrealized (gains) losses on natural gas and oil derivatives		588			(797	)
Loss on exchanges of Chesapeake debt		40			4
Impairment of natural gas and oil properties and other assets		11,130			2,830
Loss on sale of other property and equipment		38			—
Impairment of investments		162			180
Restructuring costs		34			—
Consent fees on senior notes		—			10
Adjusted ebitda (b)	$	4,407		$	5,633

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

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS

($ in millions, except per-share data)

(unaudited)

	December 31,			September 30,		December 31,
THREE MONTHS ENDED:	2009			2009		2008 (a)
Net income (loss) available to Chesapeake common shareholders	$	(530	)		186	$	(1,001	)
Adjustments:
Unrealized (gains) losses on derivatives, net of tax		126			166		(380	)
Impairment of natural gas and oil properties and other assets, net of tax		880			54		1,726
Loss on sale of other property and equipment, net of tax		—			24		—
Impairment of investments, net of tax		—			—		110
Loss (gain) on exchanges of Chesapeake debt, net of tax		14			10		(17	)
Adjusted net income available to Chesapeake common shareholders (b)		490			440		438
Preferred stock dividends		6			6		6
Total adjusted net income	$	496		$	446	$	444
Weighted average fully diluted shares outstanding (c)		644			637		590
Adjusted earnings per share assuming dilution(b)	$	0.77		$	0.70	$	0.75

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.
(b)	Adjusted net income available to common shareholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results.  The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:
	i.	Management uses adjusted net income available to common shareholders 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 shareholders 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.
(c)	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 SHAREHOLDERS

($ in millions, except per-share data)

(unaudited)

	December 31,			December 31,
TWELVE MONTHS ENDED:	2009			2008 (a)
Net income (loss) available to Chesapeake common shareholders	$	(5,853	)	$	504
Adjustments:
Unrealized (gains) losses on derivatives, net of tax		311			(434	)
Impairment of natural gas and oil properties and other assets, net of tax		6,955			1,726
Loss on sale of other property and equipment, net of tax		24			—
Impairment of investments, net of tax		102			110
Restructuring costs, net of tax		21			—
Loss on exchanges of Chesapeake debt, net of tax		25			2
Consent fees on senior notes, net of tax		—			6
Loss on conversions or exchanges of preferred stock		—			67
Adjusted net income available to Chesapeake common shareholders (b)		1,585			1,981
Preferred stock dividends		23			33
Interest on contingent convertible notes, net of tax		—			12
Total adjusted net income	$	1,608		$	2,026
Weighted average fully diluted shares outstanding (c)		631			562
Adjusted earnings per share assuming dilution(b)	$	2.55		$	3.60

(a)	Reflects the adoption and retrospective application of accounting guidance for debt with conversion and other options.
(b)	Adjusted net income available to common shareholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results.  The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:
	i.	Management uses adjusted net income available to common shareholders 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 shareholders 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.
(c)	Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

SCHEDULE “A”

CHESAPEAKE’S OUTLOOK AS OF FEBRUARY 17, 2010

Years Ending December 31, 2010 and 2011

Our policy is to periodically provide guidance on certain factors that affect our future financial performance.  As of February 17, 2010, we are using the following key assumptions in our projections for 2010 and 2011.

The primary changes from our January 4, 2010 Outlook are in italicized bold and are explained as follows:

1)   Our production guidance has been increased;

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

3)   Certain cost assumptions have been updated;

4)   Our rate of DD&A for natural gas and oil has been reduced to reflect our 2009 year-end impairment charge; and

5)   Our cash flow projections have been updated, including increased drilling capital expenditures to reflect additional drilling on oil and natural gas liquids rich plays and anticipated cost inflation, partially offset by improved drilling efficiencies.

	Year Ending 12/31/2010	Year Ending 12/31/2011
Estimated Production:
Natural gas – bcf	882 – 902	1,025 – 1,045
Oil – mbbls	15,500	17,500
Natural gas equivalent – bcfe	975 – 995	1,130 – 1,150
Daily natural gas equivalent midpoint – mmcfe	2,700	3,125
Year-over-year estimated production increase	8 – 10%	15 – 17%
Year-over-year estimated production increase excluding divestitures and curtailments	15 – 17%	16 – 18%
NYMEX Price(a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$6.26	$7.50
Oil - $/bbl	$79.87	$80.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$1.24	$0.25
Oil - $/bbl	$4.25	$5.78
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	15 – 25%	15 – 25%
Oil - $/bbl	10 – 15%	10 – 15%
Operating Costs per Mcfe of Projected Production:
Production expense	$0.85 – 0.95	$0.85 – 0.95
Production taxes (~ 5% of O&G revenues)	$0.25 – 0.30	$0.30 – 0.35
General and administrative(b)	$0.30 – 0.35	$0.30 – 0.35
Stock-based compensation (non-cash)	$0.09 – 0.11	$0.09 – 0.11
DD&A of natural gas and oil assets	$1.35 – 1.55	$1.35 – 1.55
Depreciation of other assets	$0.20 – 0.25	$0.20 – 0.25
Interest expense(c)	$0.30 – 0.35	$0.30 – 0.35
Other Income per Mcfe:
Marketing, gathering and compression net margin	$0.07 – 0.09	$0.07 – 0.09
Service operations net margin	$0.04 – 0.06	$0.04 – 0.06
Equity in income of midstream joint venture (CMP)	$0.04 – 0.06	$0.04 – 0.06
Book Tax Rate (all deferred)	38.5%	38.5%
Equivalent Shares Outstanding (in millions):
Basic	625 – 630	635 – 640
Diluted	640 – 645	645 – 650

		Year Ending 12/31/2010	Year Ending 12/31/2011
Cash Flow Projections ($ in millions):
Operating cash flow before changes in assets and liabilities(d)(e)		$4,900 – 5,000	$5,300 – 6,000
Net leasehold and producing property transactions		$1,300 – 1,700	$1,000 – 1,300
Drilling capital expenditures		($4,100 – 4,400)	($4,300 – 4,600)
Dividends, capitalized interest, cash income taxes, etc.		($350 – 400)	($500 – 600)
Other		($500 – 600)	($250 – 300)
Projected Net Cash Change		$1,250 – 1,300	$1,250 – 1,800
(a)	NYMEX natural gas prices have been updated for actual contract prices through February 2010 and NYMEX oil prices have been updated for actual contract prices through January 2010.
(b)	Excludes expenses associated with noncash stock compensation.
(c)	Does not include gains or losses on interest rate derivatives.
(d)	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.
(e)	Assumes NYMEX prices of $6.50 to $7.50 per mcf and $80.00 per bbl in 2010 and $7.00 to $8.00 per mcf and $80.00 per bbl in 2011.

At December 31, 2009, the company had approximately $2.6 billion of cash and cash equivalents and additional borrowing capacity under its three revolving bank credit facilities.

Commodity Hedging Activities

The company utilizes hedging strategies to hedge the price of a portion of its future natural gas and oil production.  These strategies include:

1)	Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.
2)	Collars: These instruments contain a fixed floor price (put) and ceiling price (call).  If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price.  If the market price is between the put and the call strike price, no payments are due from either party.  On occasion, we make a three-way collar by selling an additional put option with the collar in exchange for a more favorable strike price on the collar.  This eliminates the counterparty’s downside exposure below the second put option.
3)	Knockout swaps: Chesapeake receives a fixed price and pays a floating market price.  The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain pre-determined knockout prices.
4)	Call options: Chesapeake receives a premium from the counterparty in exchange for the sale of a call option.  If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess.  If the market price settles below the fixed price of the call option, no payment is due from either party.
5)	Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point.  For non-Appalachian Basin basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.  For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

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

Commodity markets are volatile, and as a result, Chesapeake’s hedging activity is dynamic.  As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction.

Chesapeake enters into natural gas and oil derivative transactions in order to mitigate a portion of its exposure to adverse market changes in natural gas and oil prices.  Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to natural gas and oil sales.  All realized gains and losses from natural gas and oil derivatives are included in natural gas and oil sales in the month of related production.  In accordance with generally accepted accounting principles, certain derivatives do not qualify for designation as cash flow hedges.  Changes in the fair value of these nonqualifying derivatives that occur prior to their maturity (i.e., because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within natural gas and oil sales.  Changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings.  Any change in fair value resulting from ineffectiveness is recognized currently in natural gas and oil sales.

The company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas trades:

	Open Swaps (Bcf)	Avg. NYMEX  Strike Price of Open Swaps	Assuming Natural Gas Production (Bcf)	Open Swap Positions as a % of Estimated Total Natural Gas Production	Total Gains from Lifted Trades ($ millions)	Total Lifted Gain per Mcf of Estimated Total Natural Gas Production
Q1 2010	110	$7.53			$35.9
Q2 2010	123	$7.43			$37.9
Q3 2010	118	$7.60			$65.7
Q4 2010	119	$7.75			$65.2
Total 2010(a)	470	$7.58	892	53%	$204.7	$0.23
Total 2011(a)	72	$8.71	1,035	7%	$62.7	$0.06

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at prices ranging from $5.50 to $6.75 covering 15 bcf in 2010 and $5.75 to $6.50 covering 24 bcf in 2011.

The company currently has the following open natural gas collars in place:

	Open Collars (Bcf)	Avg. NYMEX Floor Price	Avg. NYMEX Ceiling Price	Assuming Natural Gas Production (Bcf)	Open Collars as a % of Estimated Total Natural Gas Production
Q1 2010	43	$6.49	$8.51
Q2 2010	16	$7.04	$9.17
Q3 2010	4	$7.60	$11.75
Q4 2010	4	$7.60	$11.75
Total 2010(a)	67	$6.75	$9.03	892	8%
Total 2011	7	$7.70	$11.50	1,035	1%

(a) Certain collar arrangements include three-way collars that include written put options with a strike price ranging from $4.25 to $4.35 covering 12 bcf in 2010.

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

	Call Options (Bcf)	Avg. NYMEX Floor Price	Avg. Premium per mcf	Assuming Natural Gas Production (Bcf)	Call Options as a % of Estimated Total Natural Gas Production
Q1 2010	28	$10.19	$1.47
Q2 2010	38	$9.87	$1.11
Q3 2010	43	$9.93	$0.98
Q4 2010	43	$10.10	$0.98
Total 2010	152	$10.01	$1.10	892	17%
Total 2011	73	$10.25	$0.57	1,035	7%

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

	Non-Appalachia			Appalachia
	Volume (Bcf)	NYMEX less(a)		Volume (Bcf)	NYMEX plus(a)
2010	—	$	—	10	$	0.26
2011	45		0.82	12		0.25
2012	43		0.85	—		—
Totals	88	$	0.84	22	$	0.26

(a) weighted average

The company also has the following crude oil swaps in place:

	Open Swaps (mbbls)	Avg. NYMEX Strike Price	Assuming Oil Production (mbbls)	Open Swap Positions as a % of Estimated Total Oil Production	Total Gains (Losses) from Lifted Trades ($ millions)	Total Lifted Gains (Losses) per bbl of Estimated Total Oil Production
Q1 2010	2,250	$89.62	—	—	$(4.0)	—
Q2 2010	2,275	$89.62	—	—	$(4.0)	—
Q3 2010	2,300	$89.62	—	—	$(4.2)	—
Q4 2010	2,300	$89.62	—	—	$(4.2)	—
Total 2010(a)	9,125	$89.62	15,500	59%	$(16.4)	$(1.06)
Total 2011(a)	3,285	$96.09	17,500	19%	$32.8	$1.88

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 5 mmbbls and 1 mmbbls in 2010 and 2011, respectively.

Note:  Not shown above are written call options covering 1 mmbbls of oil production in 2010 at a weighted average price of $101.25 per bbl for a weighted average discount of $1.93 per bbl and 5 mmbls of oil production in 2011 at a weighted average price of $101.54 per bbl for a weighted average premium of $3.29 per bbl.

SCHEDULE “B”

CHESAPEAKE’S OUTLOOK AS OF JANUARY 4, 2010

(PROVIDED FOR REFERENCE ONLY)

NOW SUPERSEDED BY OUTLOOK AS OF FEBRUARY 17, 2010

Years Ending December 31, 2010 and 2011

Our policy is to periodically provide guidance on certain factors that affect our future financial performance.  As of January 4, 2010, we are using the following key assumptions in our projections for 2010 and 2011.

The primary changes from our November 2, 2009 Outlook are in italicized bold and are explained as follows:

1)   Projected production volumes have been updated to reflect the production loss from the expected sale of 25% of our Barnett assets to Total (initially approximately 175 mmcfe per day) and production gains from the ongoing outperformance of our drilling programs. We believe these two factors will cancel each other in 2010 and therefore our 2010 production guidance remains unchanged at 2,650 mmcfe per day.  However, we have increased  our 2011 production forecast by 50 mmcfe per day to reflect the anticipated ongoing outperformance of our drilling programs;

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

3)   Our cash flow projections have been updated.

	Year Ending 12/31/2010	Year Ending 12/31/2011
Estimated Production:
Natural gas – bcf	882 – 902	1,022 – 1,047
Oil – mbbls	12,500	13,000
Natural gas equivalent – bcfe	957 – 977	1,100 – 1,125
Daily natural gas equivalent midpoint – mmcfe	2,650	3,050
Year-over-year estimated production increase	6 – 8%	14 – 16%
Year-over-year estimated production increase excluding divestitures and curtailments	12 – 14%	15 – 17%
NYMEX Price (for calculation of realized hedging effects only):
Natural gas - $/mcf	$7.00	$7.50
Oil - $/bbl	$80.00	$80.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$0.70	$0.23
Oil - $/bbl	$4.74	$8.30
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	15 – 25%	15 – 25%
Oil - $/bbl	7 – 10%	7 – 10%
Operating Costs per Mcfe of Projected Production:
Production expense	$0.90 – 1.10	$0.90 – 1.10
Production taxes (~ 5% of O&G revenues)	$0.30 – 0.35	$0.30 – 0.35
General and administrative(a)	$0.33 – 0.37	$0.33 – 0.37
Stock-based compensation (non-cash)	$0.10 – 0.12	$0.10 – 0.12
DD&A of natural gas and oil assets	$1.50 – 1.70	$1.50 – 1.70
Depreciation of other assets	$0.20 – 0.25	$0.20 – 0.25
Interest expense(b)	$0.35 – 0.40	$0.35 – 0.40
Other Income per Mcfe:
Marketing, gathering and compression net margin	$0.07 – 0.09	$0.07 – 0.09
Service operations net margin	$0.04 – 0.06	$0.04 – 0.06
Equity in income of midstream joint venture (CMP)	$0.04 – 0.06	$0.04 – 0.06
Book Tax Rate (all deferred)	39%	39%
Equivalent Shares Outstanding (in millions):
Basic	625 – 630	635 – 640
Diluted	640 – 645	645 – 650

		Year Ending 12/31/2010	Year Ending 12/31/2011
Cash Flow Projections ($ in millions):
Operating cash flow before changes in assets and liabilities(c)(d)		$4,450 – 4,750	$5,000 – 5,600
Net leasehold and producing property transactions		$1,300 – 1,700	$1,000 – 1,300
Drilling capital expenditures		($4,000 – 4,300)	($4,100 – 4,400)
Dividends, capitalized interest, cash income taxes, etc.		($350 – 400)	($450 – 550)
Other		($500 – 600)	($250 – 300)
Projected Net Cash Change		$900 – 1,150	$1,200 – 1,650
(a)	Excludes expenses associated with noncash stock compensation.
(b)	Does not include gains or losses on interest rate derivatives (ASC 815).
(c)	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.
(d)	Assumes NYMEX natural gas prices of $6.50 to $7.50 per mcf and NYMEX oil prices of $80.00 per bbl in 2010 and  NYMEX natural gas prices of $ 7.00 to $8.00 per mcf and NYMEX oil prices of $80.00 per bbl in 2011.

At December 31, 2009, the company had approximately $2.5 billion of cash and cash equivalents and additional borrowing capacity under its three revolving bank credit facilities.

Commodity Hedging Activities

The company utilizes hedging strategies to hedge the price of a portion of its future natural gas and oil production.  These strategies include:

1)	Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.
2)	Collars: These instruments contain a fixed floor price (put) and ceiling price (call).  If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price.  If the market price is between the put and the call strike price, no payments are due from either party.  On occasion, we make a three-way collar by selling an additional put option with the collar in exchange for a more favorable strike price on the collar.  This eliminates the counterparty’s downside exposure below the second put option.
3)	Knockout swaps: Chesapeake receives a fixed price and pays a floating market price.  The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain pre-determined knockout prices.
4)	Call options: Chesapeake receives a premium from the counterparty in exchange for the sale of a call option.  If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess.  If the market price settles below the fixed price of the call option, no payment is due from either party.
5)	Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point.  For non-Appalachian Basin basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.  For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

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

Commodity markets are volatile, and as a result, Chesapeake’s hedging activity is dynamic.  As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction.

Chesapeake enters into natural gas and oil derivative transactions in order to mitigate a portion of its exposure to adverse market changes in natural gas and oil prices.  Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to natural gas and oil sales.  All realized gains and losses from natural gas and oil derivatives are included in natural gas and oil sales in the month of related production.  Pursuant to ASC 815, certain derivatives do not qualify for designation as cash flow hedges.  Changes in the fair value of these nonqualifying derivatives that occur prior to their maturity (i.e., because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within natural gas and oil sales.  Following provisions of ASC 815, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings.  Any change in fair value resulting from ineffectiveness is recognized currently in natural gas and oil sales.

The company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas trades:

	Open Swaps (Bcf)	Avg. NYMEX  Strike Price of Open Swaps	Assuming  Natural Gas Production (Bcf)	Open Swap Positions as a % of Estimated Total Natural Gas Production	Total Gains from Lifted Trades ($ millions)	Total Lifted Gain per Mcf of Estimated Total Natural Gas Production
Q1 2010	97	$7.46			$35.9
Q2 2010	99	$7.27			$37.9
Q3 2010	94	$7.54			$65.7
Q4 2010	96	$7.69			$65.2
Total 2010(a)	386	$7.49	892	43%	$204.7	$0.23
Total 2011(a)	64	$8.69	1,035	6%	$62.7	$0.06

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at $5.50 to $6.75 covering 15 bcf in 2010 and $5.75 to 6.50 covering 24 bcf in 2011.

The company currently has the following open natural gas collars in place:

	Open Collars (Bcf)	Avg. NYMEX Floor Price	Avg. NYMEX Ceiling Price	Assuming Natural Gas Production (Bcf)	Open Collars as a % of Estimated Total Natural Gas Production
Q1 2010	43	$6.49	$8.51
Q2 2010	16	$7.04	$9.17
Q3 2010	4	$7.60	$11.75
Q4 2010	4	$7.60	$11.75
Total 2010(a)	67	$6.75	$9.03	892	8%
Total 2011	7	$7.70	$11.50	1,035	1%

(a) Certain collar arrangements include three-way collars that include written put options with a strike price ranging from $4.25 to $4.35 covering 12 bcf in 2010.

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

	Call Options (Bcf)	Avg. NYMEX Floor Price	Avg. Premium per mcf	Assuming Natural Gas Production (Bcf)	Call Options as a % of Estimated Total Natural Gas Production
Q1 2010	28	$10.19	$1.47
Q2 2010	38	$9.87	$1.11
Q3 2010	43	$9.93	$0.98
Q4 2010	43	$10.10	$0.98
Total 2010	152	$10.01	$1.10	892	17%
Total 2011	73	$10.25	$0.57	1,035	7%

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

	Non-Appalachia			Appalachia
	Volume (Bcf)	NYMEX less(a)		Volume (Bcf)	NYMEX plus(a)
2010	—		—	10		0.26
2011	45		0.82	12		0.25
2012	43		0.85	—		—
Totals	88	$	0.84	22	$	0.26

(a) weighted average

The company also has the following crude oil swaps in place:

	Open Swaps (mbbls)	Avg. NYMEX Strike Price	Assuming Oil Production (mbbls)	Open Swap Positions as a % of Estimated Total Oil Production	Total Gains (Losses) from Lifted Trades ($ millions)	Total Lifted Gains (Losses) per bbl of  Estimated Total Oil Production
Q1 2010	1,980	$89.56	—	—	$(4.0)	—
Q2 2010	2,002	$89.56	—	—	$(4.0)	—
Q3 2010	2,024	$89.56	—	—	$(4.2)	—
Q4 2010	2,024	$89.56	—	—	$(4.2)	—
Total 2010(a)	8,030	$89.56	12,500	64%	$(16.4)	$(1.31)
Total 2011(a)	3,285	$96.09	13,000	25%	$32.8	$2.53

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 5 mmbbls and 1 mmbbls in 2010 and 2011, respectively.

Note:  Not shown above are written call options covering 3 mmbbls of oil production in 2010 at a weighted average price of $105.00 per bbl for a weighted average discount of $1.10 per bbl and 4 mmbls of oil production in 2011 at a weighted average price of $105.00 per bbl for a weighted average premium of $4.27 per bbl.