CHESAPEAKE ENERGY CORP - FORM 8-K - EX-99.1 - PRESS RELEASE

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8-K - CURRENT REPORT - CHESAPEAKE ENERGY CORP	chk02212012_8k.htm

Exhibit 99.1

News Release

FOR IMMEDIATE RELEASE
FEBRUARY 21, 2012

CHESAPEAKE ENERGY CORPORATION REPORTS FINANCIAL AND

OPERATIONAL RESULTS FOR THE 2011 FOURTH QUARTER AND FULL YEAR

Company Reports 2011 Fourth Quarter Net Income to Common Stockholders of

$429 Million, or $0.63 per Fully Diluted Common Share, on Revenue of $2.7 Billion;

Company Reports Adjusted Net Income Available to Common Stockholders of

$394 Million, or $0.58 per Fully Diluted Common Share, and Adjusted Ebitda

and Operating Cash Flow of $1.3 Billion

Company Reports 2011 Full Year Net Income to Common Stockholders of $1.6 Billion,

or $2.32 per Fully Diluted Common Share, on Revenue of $11.6 Billion; Company

Reports Adjusted Net Income Available to Common Stockholders of $1.9 Billion,

or $2.80 per Fully Diluted Common Share, Adjusted Ebitda of $5.4 Billion

and Operating Cash Flow of $5.3 Billion

2011 Full Year Production Totals 1.194 Tcfe for an Average of 3.272 Bcfe per Day, an

Increase of 15% Year over Year; 2011 Full Year Liquids Production Increases 72%, or

Approximately 36,000 Barrels per Day, to Average Approximately 87,000 Barrels per Day

2011 Year-End Proved Reserves Reach 18.8 Tcfe; Company Adds Proved Reserves

of 5.6 Tcfe through the Drillbit at a Drilling and Completion Cost on

Proved Properties of $1.08 per Mcfe

Chesapeake’s Current Natural Gas Curtailments Reach Approximately

1.0 Bcf per Day of Gross Operated Production

OKLAHOMA CITY, OKLAHOMA, FEBRUARY 21, 2012 – Chesapeake Energy Corporation (NYSE:CHK) today announced financial and operational results for the 2011 fourth quarter and full year. For the 2011 fourth quarter, Chesapeake reported net income to common stockholders of $429 million ($0.63 per fully diluted common share), ebitda of $1.375 billion (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization) and operating cash flow of $1.311 billion (defined as cash flow from operating activities before changes in assets and liabilities) on revenue of $2.727 billion and production of 331 billion cubic feet of natural gas equivalent (bcfe). For the 2011 full year, Chesapeake reported net income to common stockholders of $1.570 billion ($2.32 per fully diluted common share), ebitda of $4.847 billion and operating cash flow of $5.309 billion on revenue of $11.635 billion and production of 1.194 trillion cubic feet of natural gas equivalent (tcfe).

INVESTOR CONTACTS:		MEDIA CONTACTS:		CHESAPEAKE ENERGY CORPORATION
Jeffrey L. Mobley, CFA	John J. Kilgallon	Michael Kehs	Jim Gipson	6100 North Western Avenue
(405) 767-4763	(405) 935-4441	(405) 935-2560	(405) 935-1310	P.O. Box 18496
jeff.mobley@chk.com	john.kilgallon@chk.com	michael.kehs@chk.com	jim.gipson@chk.com	Oklahoma City, OK 73154

The company’s 2011 fourth quarter and full year results include realized natural gas and liquids hedging gains of $315 million and $1.554 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 2011 fourth quarter, Chesapeake reported adjusted net income to common stockholders of $394 million ($0.58 per fully diluted common share) and adjusted ebitda of $1.308 billion, and for the 2011 full year, Chesapeake reported adjusted net income to common stockholders of $1.936 billion ($2.80 per fully diluted common share) and adjusted ebitda of $5.406 billion. The primary excluded items and their effects on the 2011 fourth quarter and full year reported results are detailed as follows:

·	a net unrealized after-tax mark-to-market loss of $207 million for the fourth quarter and $486 million for the full year resulting from the company’s natural gas, liquids and interest rate hedging programs;

·	a net after-tax gain of $242 million for the fourth quarter and $238 million for the full year related to sales and impairments of certain of the company’s fixed assets; and

·	a net after-tax loss of $118 million for the full year related to the purchase or exchange of certain of the company’s senior notes and a related loss on foreign currency derivatives.

A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 19 – 23 of this release.

Key Operational and Financial Statistics Summarized

The table below summarizes Chesapeake’s key results during the 2011 fourth quarter and compares them to results during the 2011 third quarter and the 2010 fourth quarter and also compares the 2011 full year to the 2010 full year.

	Three Months Ended			Full Year Ended
	12/31/11	9/30/11	12/31/10	12/31/11	12/31/10
Average daily production (in mmcfe)(a)	3,596	3,329	2,920	3,272	2,836
Natural gas equivalent production (in bcfe)	331	306	269	1,194	1,035
Natural gas equivalent realized price ($/mcfe)(b)	5.08	5.78	5.87	5.70	6.09
Oil and NGL (liquids) production (in mbbls)	9,767	8,669	5,562	31,676	18,395
Liquids as % of total production	18	17	12	16	11
Average realized liquids price ($/bbl)(b)	64.12	63.03	62.62	63.90	62.71
Liquids as % of realized revenue	37	31	22	30	18
Liquids as % of unhedged revenue	47	40	34	40	25
Natural gas production (in bcf)	272	254	235	1,004	925
Natural gas as % of total production	82	83	88	84	89
Average realized natural gas price ($/mcf)(b)	3.87	4.82	5.22	4.77	5.57
Natural gas as % of realized revenue	63	69	78	70	82
Natural gas as % of unhedged revenue	53	60	66	60	75
Marketing, gathering and compression net margin ($/mcfe)(c)	0.07	0.10	0.13	0.10	0.12
Oilfield services net margin ($/mcfe) (c)	0.09	0.11	0.05	0.10	0.03
Production expenses ($/mcfe)	(0.88)	(0.92)	(0.90)	(0.90)	(0.86)
Production taxes ($/mcfe)	(0.15)	(0.16)	(0.14)	(0.16)	(0.15)
General and administrative costs ($/mcfe)(d)	(0.35)	(0.41)	(0.34)	(0.38)	(0.36)
Stock-based compensation ($/mcfe)	(0.06)	(0.08)	(0.08)	(0.08)	(0.08)
DD&A of natural gas and liquids properties ($/mcfe)	(1.46)	(1.38)	(1.37)	(1.37)	(1.35)
D&A of other assets ($/mcfe)	(0.26)	(0.24)	(0.23)	(0.24)	(0.21)
Interest income (expense) ($/mcfe)(b)	(0.04)	(0.01)	0.01	(0.03)	(0.08)
Operating cash flow ($ in millions)(e)	1,311	1,409	1,370	5,309	5,168
Operating cash flow ($/mcfe)	3.96	4.60	5.10	4.45	4.99
Adjusted ebitda ($ in millions)(f)	1,308	1,385	1,274	5,406	5,083
Adjusted ebitda ($/mcfe)	3.95	4.52	4.75	4.53	4.91
Net income to common stockholders ($ in millions)	429	879	180	1,570	1,663
Earnings per share – diluted ($)	0.63	1.23	0.28	2.32	2.51
Adjusted net income to common stockholders ($ in millions)(g)	394	496	478	1,936	1,971
Adjusted earnings per share – diluted ($)	0.58	0.72	0.70	2.80	2.95

(a)

Includes effect of the Fayetteville Shale asset sale to BHP Billiton on March 31, 2011 (which had an average production loss impact of approximately 400 mmcfe per day in both the 2011 fourth and third quarters and approximately 300 mmcfe per day for the 2011 full year) and the VPP #9 sale in May 2011 (which had an average production loss impact of approximately 70 mmcfe per day in the 2011 fourth and third quarters and approximately 45 mmcfe per day for the 2011 full year).

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

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

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

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

(f)	Defined as net income before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on pages 21.

(g)	Defined as net income available to common stockholders, as adjusted to remove the effects of certain items detailed on pages 22 and 23.

2011 Full Year Average Daily Production Increases 15% over 2010 Full Year Average

Daily Production, Setting Record for 22nd Consecutive Year; 2011 Fourth Quarter

Liquids Production Increases 76% Year over Year and Delivers 18% of Total

Production and 47% of Unhedged Natural Gas and Liquids Revenue

Chesapeake’s daily production for the 2011 fourth quarter averaged 3.596 bcfe, an increase of 8% from the average 3.329 bcfe produced per day in the 2011 third quarter and an increase of 23% from the average 2.920 bcfe produced per day in the 2010 fourth quarter. Chesapeake’s average daily production of 3.596 bcfe for the 2011 fourth quarter consisted of approximately 2.959 billion cubic feet of natural gas (bcf) (82% on a natural gas equivalent basis) and approximately 106,000 barrels (bbls) of oil and natural gas liquids (collectively “liquids”) (18% on a natural gas equivalent basis). For the 2011 fourth quarter, the company’s year-over-year growth rate of natural gas production was 16% and its year-over-year growth rate of liquids production was 76%, or approximately 46,000 bbls per day. The company’s percentage of revenue from liquids in the 2011 fourth quarter was 47% of total unhedged natural gas and liquids revenue compared to 40% in the 2011 third quarter and 34% in the 2010 fourth quarter.

The company’s daily production for the 2011 full year averaged 3.272 bcfe, an increase of 15% over the 2.836 bcfe of average daily production for the 2010 full year. Chesapeake’s average daily production for the 2011 full year of 3.272 bcfe consisted of 2.751 bcf (84% on a natural gas equivalent basis) and approximately 87,000 bbls (16% on a natural gas equivalent basis). For the 2011 full year, the company’s year-over-year growth rate of natural gas production was 9% and its year-over-year growth rate of liquids production was 72%, or approximately 36,000 barrels per day. The company’s percentage of revenue from liquids in the 2011 full year was 40% of total unhedged natural gas and liquids revenue compared to 25% in the 2010 full year and 20% in the 2009 full year. The 2011 full year was Chesapeake’s 22nd consecutive year of sequential production growth.

Average Realized Prices, Hedging Results and Hedging Positions Detailed

Average prices realized during the 2011 fourth quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $3.87 per thousand cubic feet of natural gas (mcf) and $64.12 per bbl, for a realized natural gas equivalent price of $5.08 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains from natural gas and liquids hedging activities during the 2011 fourth quarter generated a $1.23 gain per mcf and a $2.06 loss per bbl for a 2011 fourth quarter realized hedging gain of $315 million, or $0.95 per mcfe.

By comparison, average prices realized during the 2010 fourth quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.22 per mcf and $62.62 per bbl, for a realized natural gas equivalent price of $5.87 per mcfe. Realized gains from natural gas and liquids hedging activities during the 2010 fourth quarter generated a $2.39 gain per mcf and a $1.43 gain per bbl for a 2010 fourth quarter realized hedging gain of $571 million, or $2.13 per mcfe.

For the 2011 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 $4.77 per mcf and $63.90 per bbl, for a realized natural gas equivalent price of $5.70 per mcfe. Realized gains from natural gas and liquids hedging activities during the 2011 full year generated a $1.65 gain per mcf and a $3.21 loss per bbl for a 2011 full year realized hedging gain of $1.554 billion, or $1.30 per mcfe.

By comparison, average prices realized during the 2010 full year (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.57 per mcf and $62.71 per bbl, for a realized natural gas equivalent price of $6.09 per mcfe. Realized gains from natural gas and liquids hedging activities during the 2010 full year generated a $2.14 gain per mcf and a $4.04 gain per bbl for a 2010 full year realized hedging gain of $2.056 billion, or $1.99 per mcfe.

The company’s realized cash hedging gains since January 1, 2006 have been $8.404 billion, or $1.59 per mcfe.

Company Provides Update on Hedging Positions

The following table summarizes Chesapeake’s 2012 and 2013 open swap positions as of February 21, 2012. Depending on changes in natural gas and oil futures markets and management’s view of underlying natural gas and liquids supply and demand trends, Chesapeake may increase or decrease some or all of its hedging positions at any time in the future without notice.

	Natural Gas			Liquids
Year	% of Forecasted Production		$ NYMEX Natural Gas	% of Forecasted Production		$ NYMEX Oil WTI
2012	0	%	—	43	%	$102.48
2013	0	%	—	5	%	$102.59

In addition to the open hedging positions disclosed above, as of February 21, 2012, the company had an additional $184 million and $47 million of net hedging gains on closed contracts and premiums for call options that will be realized in 2012 and 2013, respectively, as set forth below.

	Natural Gas				Liquids
Year		Forecasted Production (bcf)	Gains/Premiums ($ in millions)	($/mcf)	Forecasted Production (mbbls)	Gains (Losses)/ Premiums ($ in millions)	($/bbl)
2012		970	$400	$0.41	55,000	$(216)	$(3.93)
2013		1,040	$21	$0.02	76,000	$26	$0.35

Details of the company’s year-end hedging positions will be included in the company’s 2011 Form 10-K to be filed with the Securities and Exchange Commission (SEC) and current positions are disclosed in summary format in the company’s Outlook dated February 21, 2012 for 2012 and 2013, which is attached to this release as Schedule “A,” beginning on page 24. The Outlook has been changed from the Outlook dated November 3, 2011, attached as Schedule “B,” which begins on page 28, to reflect various updated information.

Proved Natural Gas and Oil Reserves Increase by 1.7 Tcfe, or 10% for the 2011 Full Year

to 18.8 Tcfe Despite the Sale of 2.8 Tcfe of Proved Reserves; Proved Reserves on a Boe

Basis Now Reach 3.1 Billion Boe; Company Adds Proved Reserves of 5.6 Tcfe through

the Drillbit in 2011 at a Drilling and Completion Cost of $1.08 per Mcfe

The following table compares Chesapeake’s December 31, 2011 proved reserves, the increase over its year-end 2010 proved reserves, reserve replacement ratio, estimated future net cash flows from proved reserves (discounted at an annual rate of 10% before income taxes (PV-10)) and proved developed percentage based on the trailing 12-month average price required under SEC rules and the 10-year average NYMEX strip prices as of December 31, 2011.

Pricing Method	Natural Gas Price ($/mcf)	Oil Price ($/bbl)	Proved Reserves (tcfe)(a)	Proved Reserves Growth (tcfe)(b)	Proved Reserves Growth %(b)	Reserve Replacement Ratio	PV-10 (billions)	Proved Developed Percentage
Trailing 12-month average (SEC)(c)	$4.12	$95.97	18.8	1.7	10%	242%	$19.9	54%
12/31/11 10-year average NYMEX strip(d)	$4.92	$92.61	19.9	2.3	13%	291%	$23.8	53%

(a)	After sales of proved reserves of approximately 2.8 tcfe during 2011.

(b)

Compares proved reserves and growth for 2011 under comparable pricing methods. At year-end 2010, Chesapeake’s proved reserves were 17.1 tcfe using trailing 12-month average prices, which are required by SEC reporting rules, and 17.6 tcfe using the 10-year average NYMEX strip prices as of December 31, 2010.

(c)

Reserve volumes estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of December 31, 2011. This pricing yields estimated "proved reserves" for SEC reporting purposes. Natural gas and oil volumes estimated under the 10-year average NYMEX strip reflect an alternative pricing scenario that illustrates the sensitivity of proved reserves to a different pricing assumption.

(d)

Futures prices represent an unbiased consensus estimate by market participants about the likely prices to be received for future production. Management believes that 10-year average NYMEX strip prices provide a better indicator of the likely economic producibility of the company’s proved reserves than the historical 12-month average price.

The following table summarizes Chesapeake’s proved well costs for the 2011 full year using the two pricing methods described above.

	Trailing 12-Month Average (SEC) Pricing ($/mcfe)	12/31/11 10-year Average NYMEX Strip Pricing ($/mcfe)
Proved well costs (a)	$1.08	$0.99

(a)	Includes performance-related reserve revisions and excludes price-related revisions. Costs are net of $2.570 billion of well cost carries paid by the company’s joint venture partners.

A complete reconciliation of proved reserves and reserve replacement ratios based on these two alternative pricing methods, along with total costs, is presented on pages 14 and 15 of this release. Also, a reconciliation of PV-10 to the standardized measure is presented on page 16 of this release.

Additionally, the net book value of the company’s other assets was $7.5 billion as of December 31, 2011, compared to $6.1 billion as of December 31, 2010.

Chesapeake’s Leasehold and 3-D Seismic Inventories Total 15.3 Million Net Acres

and 30.8 Million Acres, Respectively; Risked Unproved Resources in the

Company’s Inventory Total 114 Tcfe; Unrisked Unproved

Resources Total 352 Tcfe

Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (15.3 million net acres) and 3-D seismic (30.8 million acres) in the U.S. The company has also accumulated the largest inventory of U.S. natural gas shale play leasehold (2.2 million net acres) and now owns a leading position in 11 of what Chesapeake believes are the Top 15 unconventional liquids-rich plays in the U.S. – the Granite Wash, Cleveland, Tonkawa and Mississippi Lime plays in the Anadarko Basin; the Avalon, Bone Spring, Wolfcamp and Wolfberry plays in the Permian Basin; the Eagle Ford Shale in South Texas; the Niobrara Shale in the Powder River Basin; and the Utica Shale in the Appalachian Basin.

On its leasehold inventory, Chesapeake has identified an estimated 19.9 tcfe of proved reserves (using volume estimates based on the 10-year average NYMEX strip prices as of December 31, 2011 as compared to 18.8 tcfe using SEC pricing), 114 tcfe of risked unproved resources and 352 tcfe of unrisked unproved resources. The company is currently using 161 operated drilling rigs to further develop its inventory of approximately 39,200 net risked drillsites. Of Chesapeake’s 161 operated rigs, 125 are drilling wells primarily focused on developing unconventional liquids-rich plays, 34 are drilling wells primarily focused on unconventional natural gas plays and two are drilling conventional natural gas plays. By April 1, 2012, the company estimates it will be using 157 operated rigs, of which 131 will be drilling wells primarily focused on developing unconventional liquids-rich plays, while only 26 will be drilling wells primarily focused on unconventional natural gas plays and no rigs will be drilling conventional natural gas plays – the first time in the company’s nearly 23-year history it has not been drilling a conventional natural gas well.

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

		Risked	Total	Risked	Unrisked	4Q2011 Avg	Feb 2012
	CHK	Net	Proved	Unproved	Unproved	Daily Net	Operated
	Net	Undrilled	Reserves	Resources	Resources	Production	Rig
Play Type	Acreage(a)	Wells	(bcfe)(a)(b)	(bcfe)(a)	(bcfe)(a)	(mmcfe)	Count

Unconventional Natural Gas Plays	2,180,000	13,400	10,340	56,700	129,500	2,027	34

Unconventional Liquids Plays	6,595,000	16,150	4,982	49,500	187,000	981	125

Other Plays	6,505,000	9,650	4,565	7,300	35,200	588	2

Totals	15,280,000	39,200	19,887	113,500	351,700	3,596	161

(a) As of December 31, 2011, pro forma for recent leasehold transactions.

(b) Based on 10-year average NYMEX strip prices at December 31, 2011.

In recognition of the value gap between liquids and natural gas prices, Chesapeake has directed a significant portion of its technological and leasehold acquisition expertise during the past three years to identify, secure and commercialize new unconventional liquids-rich plays. To date, Chesapeake has built leasehold positions and established production in multiple unconventional liquids-rich plays on approximately 6.6 million net leasehold acres with 830 million bbls of oil equivalent of proved reserves, 8.3 billion bbls of oil equivalent (bboe) (or 50 tcfe) of risked unproved resources and 31 bboe (or 187 tcfe) of unrisked unproved resources based on the company’s internal estimates.

Curtailments of Natural Gas Reach Approximately 1.0 Bcf per Day

of Gross Operated Production

In response to continued low natural gas prices and as an effort to help bring U.S. natural gas supply and demand into better balance, Chesapeake has demonstrated industry leadership by curtailing natural gas production to the upper level indicated in the company’s announcement on January 23, 2012. The company has now curtailed approximately 1.0 bcf per day of gross operated natural gas production, or approximately 1.5% of U.S. Lower 48 natural gas production. The curtailed volumes are located primarily in the Haynesville and Barnett shale plays. In addition, wherever possible, the company is deferring completions of dry gas wells that have been drilled, but not yet completed, and is also deferring pipeline connections of dry gas wells that have already been completed.

Company is Reducing 2012 Operated Drilling Capital Expenditures in Dry Gas Plays by

Approximately 70% from 2011 Levels, Lowest Level Since 2005; 2012 Average Net

Natural Gas Production Projected to Decrease 4% Year Over Year

The company continues to substantially reduce its operated dry gas drilling activity. By the 2012 second quarter, the company expects that its dry gas rig count will be reduced from an average of approximately 75 dry gas rigs used during 2011 to approximately 24 rigs, including 12 rigs in the northeastern portion of the Marcellus Shale, six rigs in the Haynesville Shale and six rigs in the Barnett Shale. Chesapeake’s operated dry gas drilling capital expenditures in 2012, net of drilling carries, are expected to decrease to $0.9 billion, a decrease of approximately 70% from similar expenditures of $3.1 billion in 2011 and the company’s lowest expenditures on dry gas plays since 2005.

As a result of production curtailments and reduced drilling and completion activity, partially offset by growth in associated natural gas production in liquids-rich plays, Chesapeake projects that its 2012 net natural gas production will average approximately 2.65 bcf per day, a decrease of 100 mmcf per day, or 4%, compared to the company’s 2011 average net natural gas production of 2.75 bcf per day.

Chesapeake to Double 2012 Operated Drilling Capital Expenditures in Liquids-Rich

Plays; 2012 Average Net Liquids Production Projected to Increase More than 70% Year

Over Year to Approximately 150,000 Barrels per Day

Chesapeake has reallocated capital from reduced dry gas drilling and deferred well completion and pipeline connection activities to its liquids-rich plays that offer superior returns in the current strong liquids price environment. This reallocation will result in a doubling of operated drilling capital expenditures compared to 2011 activities in Chesapeake’s liquids-rich plays, which include the Eagle Ford Shale, Utica Shale, Mississippi Lime, Granite Wash, Cleveland, Tonkawa, Niobrara, Bone Spring, Avalon, Wolfcamp, and Wolfberry. Chesapeake is increasing its operated drilling activity in liquids-rich plays by approximately 45% from an average of approximately 92 rigs used in liquids-rich plays during 2011 to an average of approximately 133 rigs in 2012. The company estimates that approximately 85% of its 2012 total net operated drilling capital expenditures will be invested in its liquids-rich plays.

As a result of continued strong operational results and increased drilling activity in liquids-rich plays, Chesapeake has increased its current liquids production to more than 110,000 bbls per day. The company projects that its 2012 net liquids production will increase by approximately 63,000 bbls per day, or more than 70% year over year, to an average of approximately 150,000 bbls per day. Additionally, Chesapeake projects that its liquids production will average more than 200,000 bbls per day in 2013 and 250,000 bbls per day in 2015. Relative to its liquids production rate of approximately 32,000 bbls per day in 2009, Chesapeake believes that its liquids production growth of approximately 220,000 bbls per day from 2009-2015 will represent the best track record of liquids production growth in the U.S. and one of the best track records of liquids production growth in the world during this period.

Chesapeake’s projected drilling activity and production in liquids-rich plays discussed above excludes the potential effects of planned 2012 asset monetization transactions associated with the company’s Mississippi Lime and Permian Basin assets discussed below.

As Previously Disclosed, Chesapeake Plans to Reduce 2012 Net Leasehold

Expenditures by Approximately 60% Year Over Year

Having captured the largest U.S. oil and natural gas resource base during the past six years of new unconventional play identification and opportunity capture, Chesapeake is reducing its undeveloped leasehold expenditures. The company is now targeting to invest approximately $1.4 billion in net undeveloped leasehold expenditures in 2012, of which approximately 90% will target liquids-rich plays and 100% will be in plays where the company is already active. This compares to net undeveloped leasehold expenditures of approximately $3.5 billion and $5.8 billion in 2011 and 2010, respectively.

Company Provides Details on its Financial Plan for 2012

Chesapeake’s primary business goal is to continue creating at least $10 billion of shareholder net asset value each year through a strategy dedicated to growing its reserves and production and transitioning to a more balanced mix of liquids and natural gas production. As a result of this strategy, the company plans to make capital expenditures in 2012 and 2013 that will exceed its projected cash flow from operations. As previously disclosed in its press release dated February 13, 2012, Chesapeake is pursuing a financial plan to fully fund its anticipated capital expenditures during 2012 and provide additional liquidity for 2013. Furthermore, the company is also projecting that its rapidly increasing liquids production will enable it in 2014 to reach equilibrium between its cash flow from operations and its planned drilling and completion capital expenditures.

Chesapeake anticipates receiving total proceeds in March 2012 of approximately $2 billion in two separate transactions – a volumetric production payment on its Texas Panhandle Granite Wash assets and a financial transaction (similar to the company’s recent CHK Utica financial transaction) involving a new unrestricted subsidiary formed to hold a portion of Chesapeake’s assets in Ellis and Roger Mills counties, Oklahoma, in the Cleveland and Tonkawa plays.

In addition, the company is pursuing joint venture transactions in its Mississippi Lime and Permian Basin plays where it owns 1.8 million and 1.5 million net acres of leasehold, respectively. Chesapeake has also recently received industry inquiries about a complete exit from the Permian Basin and may consider a 100% sale of its Permian Basin assets if it receives a compelling offer. Chesapeake’s position in the Permian Basin is one of the largest in the basin, with leading positions in the Bone Spring, Avalon, Wolfcamp and Wolfberry plays. Chesapeake’s assets in the Permian Basin represent approximately 5% of the company’s total net proved reserves and current production. Chesapeake believes the Mississippi Lime joint venture, a Permian Basin transaction and various other minor asset sales could result in cash proceeds to Chesapeake of approximately $6-8 billion in 2012. The company is targeting completion of these transactions by the end of the 2012 third quarter.

Furthermore, Chesapeake anticipates monetization proceeds of approximately $2 billion during 2012 involving a portion of its midstream assets, oilfield services assets and miscellaneous investments, bringing estimated total monetization cash proceeds in 2012 to $10-12 billion. These proceeds are substantially in excess of the difference between the company’s expected cash flow from operations and its planned capital expenditures and would allow the company to achieve its previously announced debt reduction goals while providing additional financial strength during this current period of low U.S. natural gas prices.

Company Returns to its Original 25/25 Plan

As a result of reducing its projected natural gas production through production curtailments and reduced natural gas drilling, Chesapeake is returning to its original 25/25 Plan announced in January 2011 that outlined the company’s plan to increase its production and reduce its total long-term debt by 25% each during 2011-12. During 2011, the company achieved 60% of its two-year production growth goal and 72% of its two-year long-term debt reduction goal. The company projects 2012 average daily production of 3.550 bcfe per day, a 25% increase from its 2010 average daily production of 2.836 bcfe per day. Chesapeake continues to affirm its plan to reduce its long-term debt to no more than $9.5 billion at December 31, 2012 and achieving its 25/25 Plan objectives regardless of the level of natural gas prices during 2012.

2011 Fourth Quarter and Full Year Financial and Operational Results

Conference Call Information

A conference call to discuss this release has been scheduled for Wednesday, February 22, 2012 at 9:00 am EST. The telephone number to access the conference call is 913-312-0684 or toll-free 800-289-0546. The passcode for the call is 4996325. We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EST. For those unable to participate in the conference call, a replay will be available for audio playback at 1:00 pm EST on Wednesday, February 22, 2012 and will run through midnight Wednesday, March 7, 2012. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 4996325. The conference call will also be webcast live on Chesapeake’s website at www.chk.com in the “Events” subsection of the “Investors” section of the website. The webcast of the conference call will be available on Chesapeake’s website for one year.

This news release and the accompanying Outlooks include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact and give our current expectations or forecasts of future events. They include estimates of natural gas and oil reserves and resources, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, planned drilling activity, drilling and completion costs and anticipated asset 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 news release, and we undertake no obligation to update this information.

Factors that could cause actual results to differ materially from expected results are described under “Risks Related to Our Business” in our Prospectus Supplement filed with the U.S. Securities and Exchange Commission on February 14, 2012. These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; the availability of capital on an economic basis, including through planned asset 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; inability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas and oil sales; the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; general economic conditions negatively impacting us and our business counterparties; oilfield services shortages and transportation capacity constraints and interruptions that could adversely affect our cash flow; and losses possible from pending or future litigation.

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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. In this news release, we use the terms “risked and unrisked unproved resources” to describe Chesapeake’s internal estimates of volumes of natural gas and oil that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques. These are broader descriptions of potentially recoverable volumes than probable and possible reserves, as defined by SEC regulations. Estimates of unproved resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the company. We believe our estimates of unproved resources are reasonable, but such estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.

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

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)

THREE MONTHS ENDED:	December 31,				December 31,
THREE MONTHS ENDED:	2011				2010
	$		$/mcfe		$		$/mcfe
REVENUES:
Natural gas and liquids		1,336		4.03		949		3.53
Marketing, gathering and compression		1,246		3.77		959		3.57
Oilfield services		145		0.44		67		0.25
Total Revenues		2,727		8.24		1,975		7.35

OPERATING EXPENSES:
Natural gas and oil production		292		0.88		241		0.90
Production taxes		51		0.15		38		0.14
Marketing, gathering and compression		1,223		3.70		923		3.44
Oilfield services		115		0.35		55		0.20
General and administrative		138		0.42		114		0.42
Natural gas and liquids depreciation, depletion and amortization		484		1.46		368		1.37
Depreciation and amortization of other assets		85		0.26		61		0.23
(Gains) losses on sales and impairments of fixed assets		(397)		(1.20)		(153)		(0.57)
Total Operating Expenses		1,991		6.02		1,647		6.13

INCOME FROM OPERATIONS		736		2.22		328		1.22

OTHER INCOME (EXPENSE):
Interest expense		(7)		(0.02)		(7)		(0.03)
Earnings on investments		56		0.17		37		0.14
Other income		14		0.04		5		0.02
Total Other Income		63		0.19		35		0.13

INCOME BEFORE INCOME TAXES		799		2.41		363		1.35

INCOME TAX EXPENSE (BENEFIT):
Current income taxes		2		—		(4)		(0.02)
Deferred income taxes		310		0.94		144		0.54
Total Income Tax Expense		312		0.94		140		0.52

NET INCOME		487		1.47		223		0.83

Net income attributable to noncontrolling interests		(15)		(0.04)		—		—

NET INCOME ATTRIBUTABLE TO CHESAPEAKE		472		1.43		223		0.83

Preferred stock dividends		(43)		(0.13)		(43)		(0.16)

NET INCOME AVAILABLE TO COMMON STOCKHOLDERS		429		1.30		180		0.67

EARNINGS PER COMMON SHARE:
Basic	$	0.67			$	0.29
Diluted	$	0.63			$	0.28

WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
Basic		640				632
Diluted		750				639

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)

TWELVE MONTHS ENDED:	December 31,				December 31,
TWELVE MONTHS ENDED:	2011				2010
	$		$/mcfe		$			$/mcfe
REVENUES:
Natural gas and liquids		6,024		5.04		5,647			5.46
Marketing, gathering and compression		5,090		4.26		3,479			3.36
Oilfield services		521		0.44		240			0.23
Total Revenues		11,635		9.74		9,366			9.05

OPERATING EXPENSES:
Natural gas and oil production		1,073		0.90		893			0.86
Production taxes		192		0.16		157			0.15
Marketing, gathering and compression		4,967		4.16		3,352			3.24
Oilfield services		402		0.34		208			0.20
General and administrative		548		0.46		453			0.44
Natural gas and liquids depreciation, depletion and amortization		1,632		1.37		1,394			1.35
Depreciation and amortization of other assets		291		0.24		220			0.21
(Gains) losses on sales and impairments of fixed assets		(391)		(0.34)		(116	)		(0.11)
Total Operating Expenses		8,714		7.29		6,561			6.34

INCOME FROM OPERATIONS		2,921		2.45		2,805			2.71

OTHER INCOME (EXPENSE):
Interest expense		(44)		(0.04)		(19)			(0.02)
Earnings on investments		156		0.13		227			0.22
Losses on purchases or exchanges of debt		(176)		(0.15)		(129)			(0.12)
Impairment of investments		—		—		(16)			(0.02)
Other income		23		0.02		16			0.02
Total Other Income (Expense)		(41)		(0.04)		79			0.08

INCOME BEFORE INCOME TAXES		2,880		2.41		2,884			2.79

INCOME TAX EXPENSE:
Current income taxes		13		0.01		—			—
Deferred income taxes		1,110		0.93		1,110			1.07
Total Income Tax Expense		1,123		0.94		1,110			1.07

NET INCOME		1,757		1.47		1,774			1.72

Net income attributable to noncontrolling interests		(15)		(0.01)		—			—

NET INCOME ATTRIBUTABLE TO CHESAPEAKE		1,742		1.46		1,774			1.72

Preferred stock dividends		(172)		(0.15)		(111)			(0.11)

NET INCOME AVAILABLE TO COMMON STOCKHOLDERS		1,570		1.31		1,663			1.61

EARNINGS PER COMMON SHARE:
Basic	$	2.47			$	2.63
Diluted	$	2.32			$	2.51

WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
Basic		637				631
Diluted		752				706

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)

	December 31,		December 31,
	2011		2010

Cash and cash equivalents	$	351	$	102
Other current assets		2,826		3,164
Total Current Assets		3,177		3,266

Property and equipment (net)		36,739		32,378
Other assets		1,919		1,535
Total Assets	$	41,835	$	37,179

Current liabilities	$	7,082	$	4,490
Long-term debt, net of discounts		10,626		12,640
Other long-term liabilities		2,682		2,401
Deferred tax liability		3,484		2,384
Total Liabilities		23,874		21,915

Chesapeake stockholders’ equity		16,624		15,264
Noncontrolling interests		1,337		—
Total Equity		17,961		15,264

Total Liabilities and Equity	$	41,835	$	37,179

Common Shares Outstanding (in millions)		659		654

CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

($ in millions)

(unaudited)

	December 31,				December 31,
	2011				2010

Total debt, net of unrestricted cash		$	10,275			$	12,538
Chesapeake stockholders' equity			16,624				15,264
Noncontrolling interests(a)			1,337				—
Total		$	28,236			$	27,802

Debt to capitalization ratio(b)			38	%			45	%

(a)	Includes $380 million in connection with third-party ownership in the Chesapeake Granite Wash Trust and $950 million in connection with third-party ownership of the preferred shares of CHK Utica, L.L.C.

(b)	Represents total net debt as a percentage of total book capitalization excluding equity of noncontrolling interests.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2011 ADDITIONS TO NATURAL GAS AND OIL PROPERTIES

BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT DECEMBER 31, 2011

($ in millions, except per-unit data)

(unaudited)

	Proved Reserves
	Cost		Bcfe(a)			$/Mcfe
PROVED PROPERTIES:
Well costs on proved properties(b)	$	6,080		5,619	(c)		1.08
Acquisition of proved properties		48		30			1.61
Sale of proved properties		(2,612)		(2,776)			0.94
Total net proved properties		3,516		2,873			1.22

Revisions – price		—		14			—

UNPROVED PROPERTIES:
Well costs on unproved properties		1,465		—			—
Acquisition of unproved properties, net		3,516		—			—
Sale of unproved properties		(4,432)		—			—
Total net unproved properties		549		—			—

OTHER: Capitalized interest on unproved properties		727		—			—
Geological and geophysical costs		192		—			—
Asset retirement obligations		3		—			—
Total other		922		—			—

Total	$	4,987		2,887			1.73

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

TWELVE MONTHS ENDED DECEMBER 31, 2011

BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT DECEMBER 31, 2011

(unaudited)

	Bcfe(a)
Beginning balance, January 1, 2011	17,096
Production	(1,194)
Acquisitions	30
Divestitures	(2,776)
Revisions – changes to previous estimates	(64)
Revisions – price	14
Extensions and discoveries	5,683
Ending balance, December 31, 2011	18,789

Proved reserves growth rate before acquisitions and divestitures	26		%
Proved reserves growth rate after acquisitions and divestitures	10		%

Proved developed reserves	10,106
Proved developed reserves percentage	54		%

PV-10 ($ in billions)(a)	$	19.9

(a)	Reserve volumes and PV-10 value estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of December 31, 2011 of $4.12 per mcf of natural gas and $95.97 per bbl of oil, before field differential adjustments.
(b)	Net of well cost carries of $2.570 billion associated with the Statoil-Marcellus, Total-Barnett, CNOOC-Eagle Ford and CNOOC-Niobrara joint ventures.
(c)	Includes 64 bcfe of downward revisions resulting from changes to previous estimates and excludes positive revisions of 14 bcfe resulting from higher oil prices using the average first-day-of-the-month price for the twelve months ended December 31, 2011, compared to the twelve months ended December 31, 2010.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2011 ADDITIONS TO NATURAL GAS AND OIL PROPERTIES

BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT DECEMBER 31, 2011

($ in millions, except per-unit data)

(unaudited)

	Proved Reserves
	Cost		Bcfe(a)			$/Mcfe
PROVED PROPERTIES:
Well costs on proved properties(b)	$	6,080		6,123	(c)		0.99
Acquisition of proved properties		48		30			1.61
Sale of proved properties		(2,612)		(2,776)			0.94
Total net proved properties		3,516		3,377			1.04

Revisions – price		—		99			—

UNPROVED PROPERTIES:
Well costs on unproved properties		1,465		—			—
Acquisition of unproved properties, net		3,516		—			—
Sale of unproved properties		(4,432)		—			—
Total net unproved properties		549		—			—

OTHER:
Capitalized interest on unproved properties		727		—			—
Geological and geophysical costs		192		—			—
Asset retirement obligations		3		—			—
Total other		922		—			—

Total	$	4,987		3,476			1.43

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

TWELVE MONTHS ENDED DECEMBER 31, 2011

BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT DECEMBER 31, 2011

(unaudited)

	Bcfe(a)
Beginning balance, January 1, 2011	17,605
Production	(1,194)
Acquisitions	30
Divestitures	(2,776)
Revisions – changes to previous estimates	(64)
Revisions – price	99
Extensions and discoveries	6,187
Ending balance, December 31, 2011	19,887

Proved reserves growth rate before acquisitions and divestitures	29		%
Proved reserves growth rate after acquisitions and divestitures	13		%

Proved developed reserves	10,557
Proved developed reserves percentage	53		%

PV-10 ($ in billions)(a)	$	23.8

(a)	Reserve volumes and PV-10 value estimated using SEC reserve recognition standards and 10-year average NYMEX strip prices as of December 31, 2011 of $4.92 per mcf of natural gas and $92.61 per bbl of oil, before field differential adjustments. Futures prices, such as the 10-year average NYMEX strip prices, represent an unbiased consensus estimate by market participants about the likely prices to be received for our future production. Chesapeake uses such forward-looking market-based data in developing its drilling plans, assessing its capital expenditure needs and projecting future cash flows. Chesapeake believes these prices are better indicators of the likely economic producibility of proved reserves than the trailing 12-month average price required by the SEC's reporting rule.
(b)	Net of well cost carries of $2.570 billion associated with the Statoil-Marcellus, Total-Barnett, CNOOC-Eagle Ford and CNOOC-Niobrara joint ventures.
(c)	Includes 64 bcfe of downward revisions resulting from changes to previous estimates and excludes positive revisions of 99 bcfe resulting from higher natural gas and oil prices using 10-year average NYMEX strip prices as of December 31, 2011, compared to December 31, 2010.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF PV-10

($ in millions)

(unaudited)

	December 31,		December 31,
	2011		2010

Standardized measure of discounted future net cash flows	$	15,630	$	13,183

Discounted future cash flows for income taxes		4,247		1,963

Discounted future net cash flows before income taxes (PV-10)	$	19,877	$	15,146

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 Accounting Standards Topic 932. Management uses PV-10 as one measure of the value of the company's current proved reserves and to compare relative values among peer companies without regard to income taxes. 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 dependent on the unique tax situation of each individual company. The company’s December 31, 2011 PV-10 and standardized measure were calculated using the trailing 12-month average first-day-of-the-month prices as of December 31, 2011 of $4.12 per mcf and $95.97 per bbl. The company’s December 31, 2010 PV-10 and standardized measure were calculated using the trailing 12-month average first day-of-the-month prices as of December 31, 2010 of $4.38 per mcf and $79.42 per bbl.

CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA – NATURAL GAS AND LIQUIDS SALES AND INTEREST EXPENSE

(unaudited)

	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2011		2010		2011		2010

Natural Gas and Liquids Sales ($ in millions):
Natural gas sales	$	720	$	666	$	3,133	$	3,169
Natural gas derivatives – realized gains (losses)		335		563		1,656		1,982
Natural gas derivatives – unrealized gains (losses)		24		(109)		(669)		425

Total Natural Gas Sales		1,079		1,120		4,120		5,576

Liquids sales		646		340		2,126		1,079
Oil derivatives – realized gains (losses)		(20)		8		(102)		74
Oil derivatives – unrealized gains (losses)		(369)		(519)		(120)		(1,082)

Total Liquids Sales		257		(171)		1,904		71

Total Natural Gas and Liquids Sales	$	1,336	$	949	$	6,024	$	5,647

Average Sales Price – excluding gains (losses) on derivatives:
Natural gas ($ per mcf)	$	2.64	$	2.83	$	3.12	$	3.43
Liquids ($ per bbl)	$	66.18	$	61.19	$	67.11	$	58.67
Natural gas equivalent ($ per mcfe)	$	4.13	$	3.74	$	4.40	$	4.10

Average Sales Price – excluding unrealized gains (losses) on derivatives:
Natural gas ($ per mcf)	$	3.87	$	5.22	$	4.77	$	5.57
Liquids ($ per bbl)	$	64.12	$	62.62	$	63.90	$	62.71
Natural gas equivalent ($ per mcfe)	$	5.08	$	5.87	$	5.70	$	6.09

Interest Expense (Income) ($ in millions):
Interest (a)	$	11	$	6	$	30	$	99
Derivatives – realized (gains) losses		1		(8)		7		(14)
Derivatives – unrealized (gains) losses		(5)		9		7		(66)
Total Interest Expense	$	7	$	7	$	44	$	19

(a)	Net of amounts capitalized.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

($ in millions)

(unaudited)

THREE MONTHS ENDED:	December 31,		December 31,
THREE MONTHS ENDED:	2011		2010

Beginning cash	$	111	$	609

Cash provided by operating activities		2,179		1,145

Cash flows from investing activities:
Well costs on proved properties		(1,532)		(1,502)
Well costs on unproved properties		(590)		(22)
Acquisition of proved properties		(2)		(104)
Sale of proved properties		—		31
Acquisition of unproved properties, net		(1,161)		(2,499)
Sale of unproved properties		1,256		1,081
Investments, net		(25)		(21)
Other property and equipment, net		37		198
Other		(80)		1
Total cash used in investing activities		(2,097)		(2,837)

Cash provided by financing activities		158		1,185

Ending cash	$	351	$	102

TWELVE MONTHS ENDED:	December 31,		December 31,
TWELVE MONTHS ENDED:	2011		2010

Beginning cash	$	102	$	307

Cash provided by operating activities		5,903		5,117

Cash flows from investing activities:
Well costs on proved properties		(6,002)		(5,117)
Well costs on unproved properties		(1,465)		(125)
Acquisition of proved properties		(48)		(243)
Sale of proved properties		2,678		2,863
Acquisition of unproved properties, net		(4,415)		(6,258)
Sale of unproved properties		4,462		985
Investments, net		101		(134)
Other property and equipment, net		(1,036)		(443)
Other		(87)		(31)
Total cash used in investing activities		(5,812)		(8,503)

Cash provided by financing activities		158		3,181

Ending cash	$	351	$	102

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)

THREE MONTHS ENDED:	December 31,		September 30,		December 31,
THREE MONTHS ENDED:	2011		2011		2010

CASH PROVIDED BY OPERATING ACTIVITIES	$	2,179	$	1,631	$	1,145

Changes in assets and liabilities		(868)		(222)		225

OPERATING CASH FLOW(a)	$	1,311	$	1,409	$	1,370

THREE MONTHS ENDED:	December 31,		September 30,		December 31,
THREE MONTHS ENDED:	2011		2011		2010

NET INCOME	$	487	$	922	$	223

Income tax expense		312		589		140
Interest expense		7		4		7
Depreciation and amortization of other assets		85		75		61
Natural gas and liquids depreciation, depletion and amortization		484		423		368

EBITDA(b)	$	1,375	$	2,013	$	799

THREE MONTHS ENDED:	December 31,		September 30,		December 31,
THREE MONTHS ENDED:	2011		2011		2010

CASH PROVIDED BY OPERATING ACTIVITIES	$	2,179	$	1,631	$	1,145

Changes in assets and liabilities		(868)		(222)		225
Interest expense		7		4		7
Unrealized gains (losses) on natural gas and oil derivatives		(345)		631		(628)
Gains (losses) on sales and impairments of fixed assets		397		(3)		153
Gains (losses) on investments		22		(4)		(13)
Stock-based compensation		(34)		(40)		(36)
Other items		17		16		(54)

EBITDA(b)	$	1,375	$	2,013	$	799

(a)

Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity.

(b)

Ebitda represents net income before income tax expense, interest expense and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)

TWELVE MONTHS ENDED:	December 31,		December 31,
TWELVE MONTHS ENDED:	2011		2010

CASH PROVIDED BY OPERATING ACTIVITIES	$	5,903	$	5,117

Changes in assets and liabilities		(594)		51

OPERATING CASH FLOW(a)	$	5,309	$	5,168

TWELVE MONTHS ENDED:	December 31,		December 31,
TWELVE MONTHS ENDED:	2011		2010

NET INCOME	$	1,757	$	1,774

Income tax expense		1,123		1,110
Interest expense		44		19
Depreciation and amortization of other assets		291		220
Natural gas and liquids depreciation, depletion and amortization		1,632		1,394

EBITDA(b)	$	4,847	$	4,517

TWELVE MONTHS ENDED:	December 31,		December 31,
TWELVE MONTHS ENDED:	2011		2010

CASH PROVIDED BY OPERATING ACTIVITIES	$	5,903	$	5,117

Changes in assets and liabilities		(594)		51
Interest expense		44		19
Unrealized gains (losses) on natural gas and oil derivatives		(789)		(658)
Gains (losses) on sales and impairments of fixed assets		391		116
Gains on investments		41		107
Stock-based compensation		(153)		(147)
Other items		4		(88)

EBITDA(b)	$	4,847	$	4,517

(a)

(b)

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED EBITDA

($ in millions)

(unaudited)

	December 31,		September 30,		December 31,
THREE MONTHS ENDED:	2011		2011		2010

EBITDA	$	1,375	$	2,013	$	799

Adjustments:
Unrealized (gains) losses on natural gas and oil derivatives		345		(631)		628
(Gains) losses on sales and impairments of fixed assets		(397)		3		(153)
Net income attributable to noncontrolling interests		(15)		—		—

Adjusted EBITDA(a)	$	1,308	$	1,385	$	1,274

	December 31,		December 31,
TWELVE MONTHS ENDED:	2011		2010

EBITDA	$	4,847	$	4,517

Adjustments:
Unrealized (gains) losses on natural gas and oil derivatives		789		658
(Gains) losses on sales and impairments of fixed assets		(391)		(116)
Losses on purchases or exchanges of debt		176		129
Gains on investment activity, net		—		(105)
Net income attributable to noncontrolling interests		(15)		—

Adjusted EBITDA(a)	$	5,406	$	5,083

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

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS

($ in millions, except per-share data)

(unaudited)

	December 31,		September 30,		December 31,
THREE MONTHS ENDED:	2011		2011		2010

Net income available to common stockholders	$	429	$	879	$	180

Adjustments, net of tax:
Unrealized (gains) losses on derivatives		207		(385)		392
(Gains) losses on sales and impairments of fixed assets		(242)		2		(94)

Adjusted net income available to common stockholders(a)		394		496		478
Preferred stock dividends		43		43		43
Total adjusted net income	$	437	$	539	$	521

Weighted average fully diluted shares outstanding(b)		750		753		746

Adjusted earnings per share assuming dilution(a)	$	0.58	$	0.72	$	0.70

(a)	Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:
	i.	Management uses adjusted net income available to common stockholders to evaluate the company’s operational trends and performance relative to other natural gas and oil producing companies.
	ii.	Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts.
	iii.	Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.
(b)	Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS

($ in millions, except per-share data)

(unaudited)

	December 31,		December 31,
TWELVE MONTHS ENDED:	2011		2010

Net income available to common stockholders	$	1,570	$	1,663

Adjustments, net of tax:
Unrealized (gains) losses on derivatives		486		364
(Gains) losses on sales and impairments of fixed assets		(238)		(71)
Losses on purchases or exchanges of debt		107		80
Gains on investment activity, net		—		(65)
(Gain) loss on foreign currency derivatives		11		—

Adjusted net income available to common stockholders(a)		1,936		1,971
Preferred stock dividends		172		111
Total adjusted net income	$	2,108	$	2,082

Weighted average fully diluted shares outstanding(b)		752		706

Adjusted earnings per share assuming dilution(a)	$	2.80	$	2.95

(a)	Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:
	i.	Management uses adjusted net income available to common stockholders to evaluate the company’s operational trends and performance relative to other natural gas and oil producing companies.
	ii.	Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts.
	iii.	Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.
(b)	Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

SCHEDULE “A”

CHESAPEAKE’S OUTLOOK AS OF FEBRUARY 21, 2012

Our policy is to periodically provide guidance on certain factors that affect our future financial performance. The primary changes from our November 3, 2011 Outlook are in italicized bold and reflect projected natural gas curtailments of approximately 130 bcf in 2012 and exclude the production effects of potential Mississippi Lime and Permian Basin transactions.

Chesapeake Energy Corporation Consolidated Projections

For Years Ending December 31, 2012 and 2013

	Year Ending 12/31/12	Year Ending 12/31/13
Estimated Production:
Natural gas – bcf	950 – 990	1,020 – 1,060
Liquids – mbbls	53,000 – 57,000	74,000 – 78,000
Natural gas equivalent – bcfe	1,268 – 1,332	1,464 – 1,528

Daily natural gas equivalent midpoint – mmcfe	3,550	4,100

Year over year (YOY) estimated production increase excluding asset sales	12%	20%
YOY estimated production increase	9%	15%

NYMEX Price(a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$3.40	$5.00
Oil - $/bbl	$100.03	$100.00

Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$0.37	$0.02
Liquids - $/bbl	$(2.99)	$(0.76)

Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
Natural gas - $/mcf	$0.90 – $1.00	$0.90 – $1.00
Liquids - $/bbl(b)	$25.00 – $30.00	$20.00 – $25.00

Operating Costs per Mcfe of Projected Production:
Production expense	$0.90 – 1.00	$0.90 – 1.00
Production taxes (~ 5% of O&G revenues)	$0.20 – 0.25	$0.30 – 0.35
General and administrative(c)	$0.39 – 0.44	$0.39 – 0.44
Stock-based compensation (non-cash)	$0.04 – 0.06	$0.04 – 0.06
DD&A of natural gas and liquids assets	$1.40 – 1.60	$1.50 – 1.70
Depreciation of other assets	$0.25 – 0.30	$0.30 – 0.35
Interest expense(d)	$0.05 – 0.10	$0.05 – 0.10

Other ($ millions):
Marketing, gathering and compression net margin(e)	$100 – 110	$125 – 135
Oilfield services net margin(e)	$200 – 250	$300 – 400
Other income (including equity investments)	$125 – 175	$125 – 175
Net income attributable to noncontrolling interest(f)	$(180) – (200)	$(200) – (240)

Book Tax Rate	39%	39%

Weighted average shares outstanding (in millions):
Basic	640 – 645	645 – 650
Diluted	753 – 758	758 – 763

	($ millions)
Operating cash flow before changes in assets and liabilities(g)(h)	$4,500 – 5,200	$7,500 – 8,500

Well costs on proved properties	($6,000 – 6,500)	($6,500 – 7,500)
Well costs on unproved properties	($1,000)	($1,000)
Acquisition of unproved properties, net	($1,400)	($1,000 – 1,250)
Sale of proved and unproved properties	$8,000 – 10,000	$3,000 – 4,000
Subtotal of net investment in proved and unproved properties	($400) – 1,100	($5,500 – 5,750)

Investment in oilfield services, midstream and other	($2,500 – 3,500)	($2,000 – 2,500)
Monetization of oilfield services, midstream and other assets	$2,000	$1,000 – 1,500
Subtotal of net investment in oilfield services, midstream and other	($500 – 1,500)	($1,000)

Interest and dividends	($1,000 –1,250)	($1,000 – 1,250)

Total budgeted cash flow surplus (deficit)	$2,600 – 3,550	$0 – 500

(a)	NYMEX natural gas prices have been updated for actual contract prices through February 2012 and NYMEX oil prices have been updated for actual contract prices through January 2012.

(b)	Differentials include effects of natural gas liquids.

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

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

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

(f)	Net income attributable to noncontrolling interests of Chesapeake Granite Wash Trust, CHK Utica Preferred Interest and potential Cleveland/Tonkawa Preferred Interest.

(g)	A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.

(h)	Assumes NYMEX prices on open contracts of $3.00 to $4.00 per mcf and $100.00 per bbl in 2012 and $4.50 to $5.50 per mcf and $100.00 per bbl in 2013.

Commodity Hedging Activities

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

At February 21, 2012, the company does not have any open natural gas swaps in place. The company currently has $176 million of net hedging gains related to closed natural gas contracts and premiums for call options for future production periods.

	Open Swaps (bcf)	Avg. NYMEX Price of Open Swaps		Forecasted Natural Gas Production (bcf)	Open Swap Positions as a % of Forecasted Natural Gas Production		Total Gains (Losses) from Closed Trades and Premiums for Call Options ($ in millions)			Total Gains from Closed Trades and Premiums for Call Options per mcf of Forecasted Natural Gas Production
Q1 2012								158
Q2 2012								195
Q3 2012								32
Q4 2012								15
Total 2012	0	$	0.00	970	0	%	$	400		$	0.41

Total 2013	0	$	0.00	1,040	0	%	$	21		$	0.02
Total 2014	0						$	(32	)
Total 2015	0						$	(103	)
Total 2016 – 2022	0						$	(110	)

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

	Call Options (bcf)	Avg. NYMEX Strike Price		Forecasted Natural Gas Production (bcf)	Call Options as a % of Forecasted Natural Gas Production
Q1 2012	40		6.54
Q2 2012	40		6.54
Q3 2012	40		6.54
Q4 2012	41		6.54
Total 2012	161	$	6.54	970	17	%
Total 2013	415	$	6.44	1,040	40	%
Total 2014	330	$	6.43
Total 2015	116	$	6.45
Total 2016 – 2020	349	$	8.18

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


	Volume (Bcf)	Avg. NYMEX less
2012	51	$	0.78
2013	44	$	0.21
2014 - 2022	67	$	0.42
Totals	162	$	0.47

At February 21, 2012, the company has the following open crude oil swaps in place for 2012 and through 2015. In addition, the company has $105 million of net hedging gains related to closed crude oil contracts and premiums for call options for future production periods.

	Open Swaps (mbbls)	Avg. NYMEX Price of Open Swaps		Forecasted Liquids Production (mbbls)	Open Swap Positions as a % of Forecasted Liquids Production		Total Gains (Losses) from Closed Trades and Premiums for Call Options ($millions)			Total Gains (Losses) from Closed Trades and Premiums for Call Options per bbl of Forecasted Liquids Production
Q1 2012	5,829		101.70					(26	)
Q2 2012	6,871		102.27					(51	)
Q3 2012	5,835		103.16					(65	)
Q4 2012	5,383		102.85					(74	)
Total 2012(a)	23,918	$	102.48	55,000	43	%	$	(216	)	$	(3.93)

Total 2013	4,024	$	102.59	76,000	5	%	$	26		$	0.35
Total 2014	713	$	88.27				$	(104	)
Total 2015	500	$	88.75				$	267
Total 2016 – 2021							$	132

(a)	Certain hedging contracts include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 732 mbbls in 2012.

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

	Call Options (mbbls)	Avg. NYMEX Strike Price		Forecasted Liquids Production (mbbls)	Call Options as a % of Forecasted Liquids Production
Q1 2012	1,224		100.00
Q2 2012	-		-
Q3 2012	1,840		106.38
Q4 2012	2,300		106.45
Total 2012	5,364	$	104.95	55,000	10	%

Total 2013	24,953	$	96.88	76,000	33	%
Total 2014	23,620	$	98.62
Total 2015	27,048	$	100.99
Total 2016 – 2017	24,220	$	100.07

SCHEDULE “B”

CHESAPEAKE’S OUTLOOK AS OF NOVEMBER 3, 2011

(PROVIDED FOR REFERENCE ONLY)

NOW SUPERSEDED BY OUTLOOK AS OF FEBRUARY 21, 2012

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

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

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

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

3)	Certain cost assumptions have been updated;

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

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

Chesapeake Energy Corporation Consolidated Projections

For Years Ending December 31, 2011, 2012 and 2013

	Year Ending 12/31/11	Year Ending 12/31/12	Year Ending 12/31/13
Estimated Production:
Natural gas – bcf	970 – 990	1,000 – 1,040	1,020 – 1,060
Liquids – mbbls	31,000 – 33,000	53,000 – 57,000	72,000 – 76,000
Natural gas equivalent – bcfe	1,156 – 1,188	1,318 – 1,382	1,452 – 1,516

Daily natural gas equivalent midpoint – mmcfe	3,200	3,700	4,060

Year over year (YOY) estimated production increase	13%	15%	10%
YOY estimated production increase excluding asset sales	24%	16%	11%
NYMEX Price(a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$4.14	$5.00	$6.00
Oil - $/bbl	$92.84	$100.00	$100.00

Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$1.68	$0.37	$0.02
Liquids - $/bbl	$(3.07)	$(2.60)	$(1.05)

Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
Natural gas - $/mcf	$0.90 – $1.10	$0.90 – $1.10	$0.90 – $1.10
Liquids - $/bbl(b)	$30.00 – $35.00	$25.00 – $30.00	$20.00 – $25.00

Operating Costs per Mcfe of Projected Production:
Production expense	$0.90 – 1.00	$0.90 – 1.00	$0.90 – 1.00
Production taxes (~ 5% of O&G revenues)	$0.25 – 0.30	$0.25 – 0.30	$0.30 – 0.35
General and administrative(c)	$0.36 – 0.41	$0.39 – 0.44	$0.39 – 0.44
Stock-based compensation (non-cash)	$0.07 – 0.09	$0.04 – 0.06	$0.04 – 0.06
DD&A of natural gas and liquids assets	$1.25 – 1.40	$1.40 – 1.60	$1.40 – 1.60
Depreciation of other assets	$0.20 – 0.25	$0.25 – 0.30	$0.25 – 0.30
Interest expense(d)	$0.05 – 0.10	$0.05 – 0.10	$0.05 – 0.10

Other ($ millions):
Marketing, gathering and compression net margin(e)	$120 – 130	$130 – 140	$140 – 150
Oilfield services net margin(e)	$120 – 140	$250 – 300	$350 – 450
Other income (including equity investments)	$100 – 150	$100 – 150	$100 – 150
Net income attributable to noncontrolling interest(f)	$(3) – (5)	$(35) – (40)	$(40) – (45)

Book Tax Rate	39%	39%	39%

Weighted average shares outstanding (in millions):
Basic	635 – 640	640 – 645	645 – 650
Diluted	748 – 753	753 – 758	758 – 763

Operating cash flow before changes in assets and liabilities(g)(h) ($ millions)	$5,100 – 5,200	$6,000 – 6,800	$8,000 – 9,000
Proved well costs, net of JV carries ($ millions)	($6,000 – 6,500)	($6,200 – 6,800)	($7,000 – 8,000)

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

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

($ in millions)

	Year Ending 12/31/11	Year Ending 12/31/12	Year Ending 12/31/13

Revenue	$1,200 – 1,300	$2,000 – 2,500	$3,100 – 3,600
Operating expense	$900 – 1,000	$1,400 – 1,700	$2,100 – 2,500
Depreciation and amortization	$155 – 165	$210 – 270	$330 – 390
Interest expense	$40 – 50	$60 – 70	$50 – 60

Operating cash flow before changes in assets and liabilities(g)	$200 – 250	$600 – 700	$900 – 1,000
Capital expenditures	($800 – 900)	($800 – 900)	($800 – 900)

Chesapeake Midstream Development, L.P. Projections

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

($ in millions)

	Year Ending 12/31/11	Year Ending 12/31/12	Year Ending 12/31/13

Revenue	$200 – 220	$250 – 300	$350 – 400
Operating expense	$150 – 160	$140 – 170	$170 – 200
Depreciation and amortization	$50 – 60	$100 – 120	$150 – 170
Interest expense	$10 – 15	$10 – 15	$15 – 25
Earnings from equity investments	$75 – 100	$75 – 100	$75 – 100

Operating cash flow before changes in assets and liabilities(g)	$130 – 150	$175 – 225	$225 – 275
Capital expenditures (net of dropdowns)	($50 – 100)	($800 – 900)	($800 – 900)

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

(b)	Differentials include effects of natural gas liquids.

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

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

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

(f)	Net income attributable to noncontrolling interest of Chesapeake Granite Wash Trust.

(g)	A non-GAAP financial measure. We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.

(h)	Assumes NYMEX prices of $4.00 to $5.00 per mcf and $85.00 per bbl in 2011, $4.50 to $5.50 per mcf and $100.00 per bbl in 2012, and $5.50 to $6.50 per mcf and $100.00 per bbl in 2013.

(i)	Excludes investment in FTS International, LLC.

Commodity Hedging Activities

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

	Open Swaps (bcf)	Avg. NYMEX Price of Open Swaps		Forecasted Natural Gas Production (bcf)	Open Swap Positions as a % of Forecasted Natural Gas Production		Total Gains (Losses) from Closed Trades and Collected Call Premiums ($ in millions)			Total Gains from Closed Trades and Collected Call Premiums per mcf of Forecasted Natural Gas Production
Q4 2011	0	$	0.00	250	0	%	$	369		$	1.48
Q1 2012								158
Q2 2012								195
Q3 2012								32
Q4 2012								15
Total 2012	0	$	0.00	1,020	0	%	$	400		$	0.39

Total 2013	0	$	0.00	1,040	0	%	$	21		$	0.02
Total 2014	0						$	(32	)
Total 2015	0						$	(46	)
Total 2016 – 2022	0						$	(96	)

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

	Call Options (bcf)	Avg. NYMEX Strike Price		Forecasted Natural Gas Production (bcf)	Call Options as a % of Forecasted Natural Gas Production
Q4 2011	11		4.13	250	4	%

Q1 2012	40		6.54
Q2 2012	40		6.54
Q3 2012	40		6.54
Q4 2012	41		6.54
Total 2012	161	$	6.54	1,020	16	%

Total 2013	415	$	6.44	1,040	40	%
Total 2014	330	$	6.43
Total 2015	138	$	6.41
Total 2016 – 2020	393	$	7.93

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

	Non-Appalachia			Appalachia
	Volume (Bcf)	Avg. NYMEX less		Volume (Bcf)	Avg. NYMEX plus
2011	7	$	0.82	12	$	0.14
2012	51	$	0.78	—	$	—
2013 - 2022	29	$	0.69	—	$	—
Totals	87	$	0.75	12	$	0.14

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

	Open Swaps (mbbls)	Avg. NYMEX Price of Open Swaps		Forecasted Liquids Production (mbbls)	Open Swap Positions as a % of Forecasted Liquids Production		Total Gains (Losses) from Closed Trades and Collected Call Premiums ($millions)			Total Gains (Losses) from Closed Trades and Collected Call Premiums per bbl of Forecasted Liquids Production
Q4 2011(a)	440	$	97.17	10,000	4	%	$	(11	)	$	(1.11	)

Q1 2012	346		97.89					(19	)
Q2 2012	349		98.12					(25	)
Q3 2012	361		98.19					(29	)
Q4 2012	369		98.20					(33	)
Total 2012(a)	1,425	$	98.10	55,000	3	%	$	(106	)	$	(1.92	)
Total 2013	739	$	87.69	74,000	1	%	$	26		$	0.36
Total 2014	713	$	88.27				$	(159	)
Total 2015	500	$	88.75				$	211
Total 2016 – 2021							$	132

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

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

	Call Options (mbbls)	Avg. NYMEX Strike Price		Forecasted Liquids Production (mbbls)	Call Options as a % of Forecasted Liquids Production
Q4 2011	1,840	$	110.00	10,000	18	%

Q1 2012	4,047		100.00
Q2 2012	4,047		100.00
Q3 2012	4,091		100.00
Q4 2012	4,092		100.00
Total 2012	16,277	$	100.00	55,000	30	%

Total 2013	21,245	$	95.19	74,000	29	%
Total 2014	15,379	$	96.61
Total 2015	19,360	$	100.57
Total 2016 – 2017	24,220	$	100.07

CHESAPEAKE ENERGY CORP - FORM 8-K - EX-99.1 - PRESS RELEASE - February 21, 2012

Attached files

CHESAPEAKE ENERGY CORP Reports