Expand Energy (EXE) 8-K Operational Results for the 2012 Second Quarter

Exhibit 99.1

News Release
FOR IMMEDIATE RELEASE
AUGUST 6, 2012

CHESAPEAKE ENERGY CORPORATION REPORTS FINANCIAL AND

OPERATIONAL RESULTS FOR THE 2012 SECOND QUARTER

Company Reports 2012 Second Quarter Net Income to Common Stockholders of

$929 Million, or $1.29 per Fully Diluted Common Share, on Revenue of $3.4 Billion;

Company Reports Adjusted Net Income Available to Common Stockholders of

$3 Million, or $0.06 per Fully Diluted Common Share, Adjusted Ebitda of

$803 Million and Operating Cash Flow of $895 Million

2012 Second Quarter Average Daily Total Production of 3.808 Bcfe per Day

Increases 25% Year over Year and 4% Sequentially; 2012 Second Quarter

Daily Liquids Production Increases 65% Year over Year and 15%

Sequentially to 130,200 Bbls per Day, or 21% of Total Production

2013 Liquids Production Projected to Increase 32% and

2013 Natural Gas Production to Decrease 7%

Company Anticipates Entering into Sales of Approximately $7.0 Billion

in the 2012 Third Quarter, Bringing Expected 2012 Sales through

the Third Quarter to Approximately $11.7 Billion

Strong 2012 First Half Proved Reserve Additions of 4.2 Tcfe Exceeded by

Price-Related Downward Revisions of 4.6 Tcfe Largely Attributable to

Removing Barnett and Haynesville PUDs; Total Proved Reserves

Decrease 7% Year to Date to 17.4 Tcfe, or 2.9 Bboe

OKLAHOMA CITY, OKLAHOMA, AUGUST 6, 2012 – Chesapeake Energy Corporation (NYSE:CHK) today announced financial and operational results for the 2012 second quarter.  For the 2012 second quarter, Chesapeake reported net income to common stockholders of $929 million ($1.29 per fully diluted common share), ebitda of $2.385 billion (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization) and operating cash flow of $895 million (defined as cash flow from operating activities before changes in assets and liabilities) on revenue of $3.389 billion and production of 347 billion cubic feet of natural gas equivalent (bcfe).

The company’s 2012 second quarter results include various items that are typically not included in published estimates of the company’s financial results by certain securities analysts.  Excluding such items for the 2012 second quarter, Chesapeake reported adjusted net income to common stockholders of $3 million ($0.06 per fully diluted common share) and adjusted ebitda of $803 million.  The primary excluded items from the 2012 second quarter reported results are a net after-tax gain on investments of $584 million, primarily related to the sale of all of the company’s interests in Access Midstream Partners, L.P. (NYSE:ACMP; formerly named Chesapeake Midstream Partners, L.P.), unrealized noncash after-tax mark-to-market gains of

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

$490 million resulting from the company’s oil, natural gas liquids (NGL) and natural gas and interest rate hedging programs and a noncash after-tax charge of $148 million related to the impairment of certain of the company’s property and equipment.  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 20 – 24 of this release.

Key Operational and Financial Statistics Summarized

The table below summarizes Chesapeake’s key results during the 2012 second quarter and compares them to results during the 2012 first quarter and the 2011 second quarter.

	Three Months Ended
	6/30/12	3/31/12	6/30/11
Average daily production (in mmcfe)(a)	3,808	3,658	3,049
Natural gas equivalent production (in bcfe)	347	333	277
Natural gas equivalent realized price ($/mcfe)(b)	3.77	4.02	6.07
Oil production (in mbbls)	7,325	6,008	3,894
Average realized oil price ($/bbl)(b)	91.58	92.63	87.99
Oil as % of total production	13	11	9
NGL production (in mbbls)	4,525	4,326	3,298
Average realized NGL price ($/bbl)(b)	25.94	33.60	38.37
NGL as % of total production	8	8	7
Liquids as % of realized revenue(c)	60	52	28
Liquids as % of unhedged revenue(c)	70	61	40
Natural gas production (in bcf)	275	271	234
Average realized natural gas price ($/mcf)(b)	1.88	2.35	5.19
Natural gas as % of total production	79	81	84
Natural gas as % of realized revenue	40	48	72
Natural gas as % of unhedged revenue	30	39	60
Marketing, gathering and compression net margin ($/mcfe)(d)	0.05	0.06	0.14
Oilfield services net margin ($/mcfe)(d)	0.14	0.12	0.11
Production expenses ($/mcfe) (e)	(0.97)	(1.05)	(0.94)
Production taxes ($/mcfe)	(0.12)	(0.14)	(0.17)
General and administrative costs ($/mcfe)(f)	(0.39)	(0.35)	(0.38)
Stock-based compensation ($/mcfe)	(0.06)	(0.06)	(0.08)
DD&A of natural gas and liquids properties ($/mcfe)	(1.70)	(1.52)	(1.32)
D&A of other assets ($/mcfe)	(0.24)	(0.25)	(0.23)
Interest expense ($/mcfe)(b)	(0.06)	(0.02)	(0.07)
Operating cash flow ($ in millions)(g)	895	910	1,207
Operating cash flow ($/mcfe)	2.58	2.73	4.35
Adjusted ebitda ($ in millions)(h)	803	838	1,365
Adjusted ebitda ($/mcfe)	2.32	2.52	4.92
Net income (loss) to common stockholders ($ in millions)	929	(71)	467
Earnings (loss) per share – diluted ($)	1.29	(0.11)	0.68
Adjusted net income to common stockholders ($ in millions)(i)	3	94	528
Adjusted earnings per share – diluted ($)	0.06	0.18	0.76

(a)   Includes effect of VPP #9 sale in May 2011 (which had an average production loss impact of approximately 70 mmcfe per day in the 2012 second and first quarters and 40 mmcfe per day in the 2011 second quarter) and VPP #10 sale in March 2012 (which had an average production loss impact of approximately 115 mmcfe and 30 mmcfe per day in the 2012 second and first quarters, respectively).  Also includes the effect of net natural gas production curtailments of approximately 30 bcf in each of the 2012 second and first quarters, or an average of approximately 330 mmcf per day in each quarter.

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

(c)   “Liquids” includes both oil and natural gas liquids.

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

(e)   Includes one-time retroactive Pennsylvania natural gas impact fee in the 2012 first quarter of $0.04 per mcfe.

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

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

(h)   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 22.

(i)   Defined as net income (loss) available to common stockholders, as adjusted to remove the effects of certain items detailed on page 23.

2012 Second Quarter Average Daily Total Production of 3.808 Bcfe per Day Increases

25% Year over Year and 4% Sequentially; 2012 Second Quarter Daily Liquids Production

Increases 65% Year over Year and 15% Sequentially to 130,200 Bbls per Day

Chesapeake’s daily production for the 2012 second quarter averaged 3.808 bcfe, an increase of 25% from the average 3.049 bcfe produced per day in the 2011 second quarter and an increase of 4% from the average 3.658 bcfe produced per day in the 2012 first quarter.  Chesapeake’s average daily production of 3.808 bcfe for the 2012 second quarter consisted of approximately 3.027 billion cubic feet (bcf) of natural gas (79% on a natural gas equivalent basis) and approximately 130,200 barrels (bbls) of liquids, consisting of approximately 80,500 bbls of oil (13% on a natural gas equivalent basis) and approximately 49,700 bbls of NGL (8% on a natural gas equivalent basis) (oil and NGL collectively referred to as “liquids”).

For the 2012 second quarter, the company’s year-over-year growth rate of natural gas production was 18%, or approximately 450 million cubic feet (mmcf) per day, and its year-over-year growth rate of liquids production was 65%, or approximately 51,200 bbls per day.  Chesapeake’s year-over-year liquids production growth consisted of oil production growth of 88%, or approximately 37,700 bbls per day, and NGL production growth of 37%, or approximately 13,500 bbls per day.  Production amounts above were affected by curtailments of natural gas production, which averaged an estimated 330 mmcf of natural gas per day net to Chesapeake in both the 2012 second quarter and 2012 first quarter compared to no curtailments in the 2011 second quarter.  Had the company not curtailed a portion of its natural gas production, its year-over-year production growth rate in the 2012 second quarter would have been 36%. The company ended its natural gas production curtailment program at the end of the 2012 second quarter and does not anticipate needing to implement new material curtailments during the remainder of 2012.

As a result of reduced drilling activity currently planned by the company for 2012 and 2013 in its dry natural gas plays, Chesapeake is projecting an approximate 12% decline in its natural gas productive capacity in 2013 compared to 2012 after adjusting for estimated production curtailments of approximately 60 bcf in 2012.  Management expects the company’s absolute natural gas production to decline 7% in 2013 and expects its liquids production to increase 32% in 2013.  Management and the board of directors are currently reviewing operations for 2013 and beyond, which could result in changes to the company’s drilling activity and production levels in 2013.  This information is expected to be updated in connection with the 2012 third quarter earnings release.

Average Realized Prices and Hedging Results and Positions Detailed

Average prices realized during the 2012 second quarter (including realized gains or losses from oil, NGL and natural gas derivatives and excluding unrealized gains or losses on such derivatives) were $1.88 per thousand cubic feet (mcf) of natural gas, $91.58 per barrel (bbl) of oil and $25.94 per bbl of NGL, for a realized natural gas equivalent price of $3.77 per thousand cubic feet of natural gas equivalent (mcfe).  Realized gains from natural gas and liquids hedging activities during the 2012 second quarter generated a $0.66 gain per mcf of natural gas, a $2.09 gain per bbl of oil and a $0.46 loss per bbl of NGL for a 2012 second quarter realized hedging gain of $195 million, or $0.56 per mcfe.

By comparison, average prices realized during the 2011 second quarter (including realized gains or losses from oil, NGL and natural gas derivatives and excluding unrealized gains or losses on such derivatives) were $5.19 per mcf of natural gas, $87.99 per bbl of oil and $38.37

per bbl of NGL, for a realized natural gas equivalent price of $6.07 per mcfe.  Realized gains from natural gas and liquids hedging activities during the 2011 second quarter generated a $1.93 gain per mcf of natural gas, an $8.70 loss per bbl of oil and a $3.29 loss per bbl of NGL for a 2011 second quarter realized hedging gain of $407 million, or $1.46 per mcfe.  The company’s realized cash hedging gains since January 1, 2006 have been $8.7 billion, or $1.46 per mcfe.

The following table summarizes Chesapeake’s 2012 and 2013 open swap positions as of August 6, 2012.  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 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
3Q - 4Q 2012	64	%	$3.03	31	%	$101.34
2013	—		—	5	%	$94.06

Details of the company’s quarter-end hedging positions will be provided in the company’s Form 10-Q filing with the Securities and Exchange Commission (SEC), and current positions are disclosed in summary format in management’s Outlook dated August 6, 2012, which is attached to this release as Schedule “A,” beginning on page 25.  The Outlook has been changed from the Outlook dated May 1, 2012, attached as Schedule “B,” which begins on page 28, to reflect various updated information.  Management and the board of directors are currently reviewing operations for 2013 and beyond, which could result in changes to the Outlook attached as Schedule A.  This information is expected to be updated in connection with the 2012 third quarter earnings release.

Strong 2012 First Half Proved Reserve Additions of 4.2 Tcfe Exceeded by Price-Related

Downward Revisions of 4.6 Tcfe Largely Attributable to Removing Barnett and

Haynesville PUDs; Total Proved Reserves Decrease 7% to 17.4 Tcfe, or 2.9 Bboe

During the 2012 first half, Chesapeake developed 4.2 trillion cubic feet of natural gas equivalent (tcfe), or 690 million barrels of oil equivalent (mmboe), of new proved reserves through the drillbit at a drilling and completion cost of $1.14 per mcfe, or $6.84 per boe.

As a result of lower U.S. natural gas prices, the company recorded price-related downward revisions of 4.6 tcfe, or 760 mmboe, during the 2012 first half, primarily attributable to the removal of proved undeveloped reserves (PUD) in the company’s Barnett and Haynesville Shale plays.  The company's June 30, 2012 proved reserves were 17.4 tcfe, or 2.9 billion barrels of oil equivalent (bboe), a 7% decrease from year-end 2011.

The following table presents Chesapeake’s June 30, 2012 proved reserves, proved reserve changes, reserve replacement ratio, estimated future net cash flows from proved reserves (discounted at an annual rate of 10% before income taxes (PV-10)), proved developed percentage and 2012 first half proved well costs based on the trailing 12-month average price required under SEC rules and the 10-year average NYMEX strip prices as of June 30, 2012.  Additional information regarding the data in the table below is presented in pages 16 and 17.

Pricing Method	Natural Gas Price ($/mcf)	Oil Price ($/bbl)	Proved Reserves (tcfe)(a)	Proved Reserves Growth/ (Decrease) (tcfe)(b)	Proved Reserves Growth/ (Decrease) %(b)	Reserve Replacement Ratio	PV-10 (billions)	Proved Developed Percentage	Proved Well Costs ($/mcf)(c)
Trailing 12-month avg (SEC)(d)	$3.15	$95.79	17.4	(1.4)	(7)%	(106)%	$19.7	59%	$1.14
6/30/12 10-year avg NYMEX strip(e)	$4.33	$86.76	22.1	2.2	11%	427%	$25.1	52%	$1.24

(a)   After sales of proved reserves of approximately 319 bcfe during the 2012 first half.

(b)   Compares proved reserves and growth for the 2012 first half under comparable pricing methods.  As of year-end 2011, Chesapeake’s proved reserves were 18.8 tcfe using trailing 12-month average prices, which are required by SEC reporting rules, and 19.9 tcfe using the 10-year average NYMEX strip prices as of December 31, 2011.

(c)   Includes performance-related reserve revisions and excludes price-related revisions.  Costs are net of $518 million of well cost carries paid by the company’s joint venture partners.

(d)   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 June 30, 2012. ��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.

(e)   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.

Using SEC pricing, the PV-10 value of the added proved reserves was $10.2 billion ($2.43 per mcfe, or $14.57 per boe).  The difference between 2012 first half drilling and completion costs of $1.14 per mcfe and the $2.43 per mcfe PV-10 value of the proved reserves added provides evidence of the net asset value creation capability of the company’s drilling program.

Company Completes $4.7 Billion of Sales in the 2012 First Half and Anticipates

Sales of Approximately $7.0 Billion in the 2012 Third Quarter

In the 2012 first half, Chesapeake completed $4.7 billion of sales, including:  the sale of preferred shares of an unrestricted, nonguarantor consolidated subsidiary, CHK Cleveland Tonkawa, L.L.C., and an overriding royalty interest in the Cleveland and Tonkawa plays for proceeds of $1.25 billion; the sale of a 10-year volumetric production payment (VPP) for proceeds of $745 million for certain producing assets in its Anadarko Basin Granite Wash play; the sale of oil and natural gas assets in the Texoma Woodford play for approximately $575 million; the sale of all of CHK’s common and general partner interests in ACMP to Global Infrastructure Partners (GIP) for $2.0 billion; and other miscellaneous asset sales totaling approximately $100 million.

During the 2012 third quarter, Chesapeake expects to enter into agreements to sell three Permian Basin asset packages.  A Purchase and Sale Agreement (PSA) has been signed with affiliates of Houston-based EnerVest, Ltd. for the company’s producing assets in the Midland Basin portion of the Permian Basin.  Bids have also been received and accepted on two other packages in the Delaware Basin portion of the Permian Basin.  Chesapeake is currently negotiating PSAs for the two Delaware Basin packages with the goal of entering into PSAs in the next 30 days and closing the transactions in the 2012 third quarter.  Negotiations for the sale of substantially all of Chesapeake’s remaining midstream assets are also underway with GIP, which has an exclusive offer right until August 13, 2012.  Chesapeake also expects to close various other asset sales during the 2012 third quarter.

Chesapeake anticipates net proceeds of approximately $7.0 billion for asset sales in the 2012 third quarter, including those discussed above, which if successfully completed, would bring the company’s 2012 asset sales to approximately $11.7 billion.  For the full year, the company has previously discussed a range of $11.5-14.0 billion in sales and management has updated its range to $13.0-14.0 billion.  Assuming completion of its planned asset sales in the 2012 second half, Chesapeake plans to repay its $4.0 billion term loans and also achieve the 25% two-year debt reduction goal of the company’s 25/25 Plan, which was first announced on January 6, 2011.

Company Achieves Strong Operational Results in its Liquids-Rich Plays with Liquids

Production Increasing by 65% Year over Year and 15% Sequentially, Led by 745%

Year-over-Year and 71% Sequential Production Growth in its Eagle Ford Shale Play;

Oil Production Has Increased More Quickly than NGL Production and Comprised

62% of Total Liquids Production in the 2012 Second Quarter

Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (15.9 million net acres) and 3-D seismic (33.2 million acres) in the U.S. and owns a leading position in 10 of what Chesapeake believes are the Top 15 unconventional plays in the U.S. – the Eagle Ford Shale in South Texas; the Marcellus Shale in Pennsylvania and West Virginia; the Utica Shale in Ohio; the Granite Wash, Cleveland, Tonkawa and Mississippi Lime plays in the Anadarko Basin in Oklahoma and the Texas Panhandle; the Niobrara Shale in the Powder River Basin in Wyoming; the Haynesville/Bossier shales in western Louisiana and east Texas; and the Barnett Shale in north Texas.  These 10 plays represent Chesapeake’s core assets and will be the nearly exclusive focus of the company’s drilling efforts in the future.

In response to strong U.S. oil and NGL prices in comparison to weaker U.S. natural gas prices, during the past four years Chesapeake has substantially shifted its drilling and completion activity to liquids-rich plays.  During 2012 and 2013, the company projects that only approximately 16% and 8%, respectively, of its total drilling and completion capital expenditures will be invested in dry natural gas plays.  The company continues to achieve strong operational results in its liquids-rich plays, particularly in the key plays highlighted below.

Eagle Ford Shale (South Texas):Chesapeake’s activities in the Eagle Ford Shale in South Texas continue to drive strong results, yielding net production of 36,300 barrels of oil equivalent (boe) per day (gross 75,400 boe per day) for the 2012 second quarter, an increase of 615% year over year and 58% sequentially, which included an increase in liquids production of 745% year over year and 71% sequentially.  Approximately 66% of total Eagle Ford production during the 2012 second quarter was oil, 17% was NGL and 17% was natural gas.  Production growth in the play has been augmented by the continued build out of new compression facilities and new pipelines as well as securing additional short-term truck transportation for oil production.   Chesapeake expects price realizations for its Eagle Ford production to improve by approximately $5 per bbl beginning in October 2012 as new oil gathering pipelines and other infrastructure are completed.

As of June 30, 2012, Chesapeake had 337 producing wells in the Eagle Ford play, which included 121 wells that reached first production in the 2012 second quarter, compared to 62 in the 2012 first quarter and 27 in the 2011 second quarter.  Also, as of June 30, 2012, Chesapeake had approximately 220 Eagle Ford wells drilled, but not yet producing, that were in various stages of completion and/or waiting on pipeline connection.  Recent efficiency gains in drilling cycles of well spud to rig release and well spud to first sales, in addition to certain reductions in service costs, have resulted in cost savings of approximately 15% per well in the

Eagle Ford.  As a consequence of this greater drilling efficiency, the company is planning to reduce its drilling activity in the Eagle Ford from 28 rigs currently to 25 rigs by December 2012 and plans to average 22 rigs during 2013.

Of the 121 wells which commenced first production in the 2012 second quarter, 110 wells (or 91%) had peak production rates of more than 500 boe per day, including 37 wells (or 31%) with peak rates of more than 1,000 boe per day.  Three notable recent wells completed by Chesapeake in the Eagle Ford during the quarter are as follows:

·   The Gates 010-CHK-B TR1-D6H in Webb County, TX achieved a peak rate of approximately 2,070 boe per day, consisting of 710 bbls of oil, 665 bbls of NGL and 4.2 mmcf of natural gas per day;

·   The Holubar Dim C 2H in Dimmit County, TX achieved a peak rate of approximately 1,900 boe per day, consisting of 1,730 bbls of oil, 110 bbls of NGL and 0.4 mmcf of natural gas per day; and

·   The Foley MCM A 1H in McMullen County, TX achieved a peak rate of approximately 1,500 boe per day, consisting of 1,335 bbls of oil, 55 bbls of NGL and 0.6 mmcf of natural gas per day.

Hogshooter Wash (western Oklahoma, Texas Panhandle):On June 1, 2012, Chesapeake announced a significant new discovery in the Texas Panhandle portion of the Hogshooter Wash play, where the company owns approximately 30,000 net acres.  The company reported its Thurman Horn 406H well averaged approximately 7,350 boe per day (90% liquids) in its first eight days of stabilized production.   This well is currently flowing at a rate of approximately 5,100 boe per day (65% liquids).  In its first 60 days of production, the well has produced cumulative volumes of approximately 265,000 bbls of oil, 65,000 bbls of NGL and 350 mmcf of natural gas.  On July 13, 2012, Chesapeake placed the Zybach 6010H on production and this Hogshooter well is currently producing approximately 2,400 boe per day (85% liquids).  Chesapeake’s oldest operated well in the Hogshooter play, the Meek 41 9H, is currently producing approximately 720 boe per day (85% liquids) after more than 90 days on production.  

Chesapeake currently has two wells drilling in the Hogshooter play, the Meek 41 10H and the Thurman Horn 4010H, and is scheduled to spud another 11 Hogshooter wells before year-end 2012.  Chesapeake has identified approximately 60 potential drilling locations in the Hogshooter play.

Utica Shale (eastern Ohio):Chesapeake continues to focus on developing the wet gas and dry gas windows of the Utica Shale play in eastern Ohio, where the company holds approximately 1.3 million net acres of leasehold, the industry’s largest position.  As of June 30, 2012, Chesapeake had drilled a total of 87 wells in the Utica play and the company’s production techniques and geologic understanding of the Utica play are continuing to improve.  Of the 28 wells with production information in the focus area, on a post-processing basis, peak rates have averaged approximately 1,000 boe per day, consisting of approximately 205 bbls of oil, 150 bbls of NGL and 3.8 mmcf of natural gas per day.  As of June 30, 2012 there were 28 additional wells waiting on pipeline connection, with the others in various stages of completion.

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

·   The Brown 10H in Jefferson County, OH achieved a peak rate of approximately 1,445 boe per day, which included 8.7 mmcf of natural gas per day;

·   The Bailey 3H in Carroll County, OH achieved a peak rate of approximately 1,420 boe per day, which included 205 bbls of oil, 270 bbls of NGL and 5.7 mmcf of natural gas per day; and

·   The Snoddy 6H in Carroll County, OH achieved a peak rate of approximately 1,260 boe per day, which included 320 bbls of oil, 250 bbls of NGL and 4.2 mmcf of natural gas per day.

Chesapeake and its midstream partners are making substantial progress in the construction of gathering and processing systems that will be essential for accelerating production from this rapidly expanding and important play.  Chesapeake is currently operating 11 rigs in the Utica play and plans to exit 2012 with 16 operated rigs.  As of June 30, 2012, the company’s remaining drilling carry from Total was approximately $1.35 billion.  Chesapeake anticipates using 100% of the drilling carry by year-end 2014 and the carry will pay for 60% of Chesapeake’s drilling costs during that time.

Marcellus Shale (Pennsylvania, West Virginia):With approximately 1.8 million net acres, Chesapeake is the industry’s largest leasehold owner in the Marcellus Shale play that spans from northern West Virginia across much of Pennsylvania into southern New York.

During the 2012 second quarter, Chesapeake’s average daily net production in the northern dry gas portion of the Marcellus play was 495 mmcfe, an increase of 160% year over year and 19% sequentially.  Chesapeake is currently drilling with 10 operated rigs in the dry gas northern portion of the Marcellus and anticipates reducing its drilling activity to an average of approximately six rigs for the remainder of 2012.

Three notable recent wells completed by Chesapeake in the dry gas northern portion of the Marcellus are as follows:

·   The Stoorza 5H in Bradford County, PA achieved a peak rate of 9.4 mmcf of natural gas per day;

·   The McGavin 5H in Susquehanna County, PA achieved a peak rate of 8.7 mmcf of natural gas per day; and

·   The Redmond 2H in Wyoming County, PA achieved a peak rate of 8.7 mmcf of natural gas per day.

During the 2012 second quarter, Chesapeake’s average daily net production in the wet gas southern portion of the play was approximately 135 mmcfe.  Chesapeake is currently drilling with seven operated rigs in the wet gas southern portion of the Marcellus and anticipates reducing its drilling activity to an average of approximately six rigs for the remainder of 2012.

Three notable recent wells completed by Chesapeake in the wet gas southern portion of the Marcellus are as follows:

·   The O E Burge MSH 10H in Marshall County, WV achieved an initial test rate of approximately 1,650 boe per day, consisting of 7.2 mmcf of natural gas per day and 445 bbls of liquids;

·   The O E Burge 6H in Marshall County, WV achieved an initial test rate of approximately 1,480 boe per day, consisting of 6.8 mmcf of natural gas per day and 345 bbls of liquids; and

·   The O E Burge 8H in Marshall County, WV achieved an initial test rate of approximately 1,160 boe per day, consisting of 5.5 mmcf of natural gas per day and 240 bbls of liquids.

Mississippi Lime (northern Oklahoma, southern Kansas):  Chesapeake’s approximate 2.0 million net acres of leasehold is the industry’s largest position in the Mississippi Lime play in northern Oklahoma and southern Kansas.  Production for the 2012 second quarter averaged 20,000 boe per day, up 198% year over year and 56% sequentially.  Approximately 39% of total Mississippi Lime production during the 2012 second quarter was oil, 12% was NGL and 49% was natural gas.  Since 2009, the company has drilled 158 horizontal producing wells in the Mississippi Lime play with attractive overall results and is currently operating 18 rigs in the play.  The company continues to pursue a joint venture and/or sale of a portion of its Mississippi Lime leasehold and expects to announce a transaction in the next few months.

Three notable recent wells completed by Chesapeake in the Mississippi Lime during the quarter are as follows:

·   The Smith 27-28-9 1H in Alfalfa County, OK achieved a peak rate of approximately 2,190 boe per day, which included 1,655 bbls of oil, 70 bbls of NGL and 2.8 mmcf of natural gas per day;

·   The Loy Puffinbarger 29-28-9 1H in Alfalfa County, OK achieved a peak rate of approximately 1,630 boe per day, which included 1,100 bbls of oil, 80 bbls of NGL and 2.7 mmcf of natural gas per day; and

·   MWK 16-27-12 1H in Alfalfa County, OK achieved a peak rate of approximately 1,290 boe per day, which included 800 bbls of oil, 90 bbls of NGL and 2.4 mmcf of natural gas per day.

Cleveland and Tonkawa Tight Sand (western Oklahoma, Texas Panhandle):Chesapeake owns approximately 525,000 net acres of leasehold in the Cleveland play and 285,000 net acres in the Tonkawa play in western Oklahoma and the Texas Panhandle, which it believes is the industry’s largest position in the combined plays.  Production for the 2012 second quarter averaged 21,400 boe per day, up 109% year over year and 14% sequentially.  Approximately 45% of total Cleveland and Tonkawa production during the quarter was oil, 20% was NGL and 35% was natural gas.  The company is currently operating 13 rigs in the two plays and plans to exit 2012 with 13 operated rigs.

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

·   The Big Lake 1022H in Hemphill County, TX achieved a peak rate of approximately 3,960 boe per day, which included 730 bbls of oil, 1,190 bbls of NGL and 12.2 mmcf of natural gas per day;

·   The Betty 1H in Ellis County, OK achieved a peak rate of approximately 1,435 boe per day, which included 1,000 bbls of oil, 215 bbls of NGL and 1.3 mmcf of natural gas per day; and

·   The Andrew 1H in Ellis County, OK achieved a peak rate of approximately 1,160 boe per day, which included 905 bbls of oil, 130 bbls of NGL and 0.8 mmcf of natural gas per day.

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

·   The Ireton 1H in Dewey County, OK achieved a peak rate of approximately 775 boe per day, which included 525 bbls of oil, 45 bbls of NGL and 1.2 mmcf of natural gas per day;

·   The Little 1H in Roger Mills County, OK achieved a peak rate of approximately 660 boe per day, which included 605 bbls of oil, 20 bbls of NGL and 0.2 mmcf of natural gas per day; and

·   The Vessels 1H in Roger Mills County, OK achieved a peak rate of approximately 680 boe per day, which included 555 bbls of oil, 50 bbls of NGL and 0.5 mmcf of natural gas per day.

Powder River Basin Niobrara (Wyoming):  Chesapeake owns approximately 350,000 net acres in the Powder River Basin Niobrara play in Wyoming.  The company has drilled 44 horizontal wells in the play to date and results continue to improve steadily with an increasing focus on a newly-identified core area that has much higher pressures and hydrocarbons in place than in other portions of the play.  Chesapeake has drilled 18 wells in the identified core area of the play and believes it has the ability to drill more than 1,000 wells in this focus area in the years to come.  Chesapeake is currently operating eight rigs in the play and plans to exit 2012 with 11 operated rigs.

Three notable recent wells completed by Chesapeake in the Powder River Basin Niobrara are as follows:

·   The Combs Ranch 1-H in Converse County, WY achieved a peak rate of approximately 2,460 boe per day, which included 1,120 bbls of oil, 575 bbls of NGL and 4.6 mmcf of natural gas per day;

·   The York Ranch 1H in Converse County, WY achieved a peak rate of approximately 1,950 boe per day, which included 1,020 bbls of oil, 370 bbls of NGL and 3.4 mmcf of natural gas per day; and

·   The Northwest Fetter 1H in Converse County, WY achieved a peak rate of approximately 1,460 boe per day, which included 1,150 bbls of oil, 125 bbls of NGL and 1.1 mmcf of natural gas per day.

As of June 30, 2012, the company’s remaining drilling carry from CNOOC was approximately $520 million.  Chesapeake anticipates using 100% of the carry by year-end 2014 and the carry will pay for 67% of Chesapeake’s drilling costs during that time.

Management Comments

Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, said, “We are taking aggressive and focused actions to increase cash flow and net asset value per share while also reducing long-term debt as we continue our ongoing transformation to a more balanced asset base between higher-margin liquids and lower-margin natural gas.  We are prudently deploying our capital as we focus on developing and harvesting the 10 core plays in which Chesapeake has built a #1 or #2 position.

“As importantly, we continue to execute on our asset sale process.  In the 2012 third quarter, we anticipate entering into approximately $7.0 billion of asset sales, including the sale of Permian Basin and midstream assets. These transactions will be in addition to the $4.7 billion of asset sales completed in the 2012 first half.  In combination with further asset sales planned for the 2012 fourth quarter, we have increased our plans for asset sales this year to a range of $13.0 to $14.0 billion, which will enable us to accomplish our planned 25% long-term debt reduction to $9.5 billion by year-end 2012 in accordance with our 25/25 Plan we announced in January 2011.

“Finally, as a result of Chesapeake’s strong operational performance, ongoing drilling efficiency gains and an increased focus on optimal asset development, we have increased our production guidance for 2013 despite a $750 million decrease in our drilling and completion capital expenditure plans for next year.”

2012 Second Quarter Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled for Tuesday, August 7, 2012 at 9:00 am EDT.  The telephone number to access the conference call is 913-312-1296 or toll-free 800-239-9838.  The passcode for the call is 4584085.  We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EDT. For those unable to participate in the conference call, a replay will be available for audio playback at 1:00 pm EDT on Tuesday, August 7, 2012 and will run through midnight Monday, August 20, 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 4584085.  The conference call will also be webcast live on Chesapeake’s website at www.chk.com in the “Events” subsection of the “Investors” section of the company’s website.  The webcast of the conference will be available on the company’s website for one year.

This news release and the accompanying Outlooks include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  Forward-looking statements are statements other than statements of historical fact and give our current expectations or forecasts of future events.  They include estimates of natural gas and oil reserves, projected production, planned development drilling, projected drilling and completion expenditures and leasehold investment, anticipated asset sales and related proceeds, 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 “Risk Factors” in Item 1A of our 2011 annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on February 29, 2012.  These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; the availability of capital on an economic basis, including through planned asset sales, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the amount and timing of development expenditures; inability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas and oil sales; the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their

obligations; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing; general economic conditions negatively impacting us and our business counterparties; oilfield services shortages and transportation capacity constraints and interruptions that could adversely affect our cash flow; and losses possible from pending or future litigation.  We do not have binding agreements for all of the asset sales we expect to complete in 2012, multiple Permian sales transactions, the sale of our remaining midstream assets and other miscellaneous asset sales. Our ability to consummate each of these transactions is subject to changes in market conditions and other factors. To the extent one or more of the transactions is not completed in the anticipated time frame or at all or for less proceeds than anticipated, we may not be able to reduce our indebtedness as planned.

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

Chesapeake Energy Corporation (NYSE:CHK) is the second-largest producer of natural gas, a Top 15 producer of oil and natural gas liquids and the most active driller of new wells in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S. Chesapeake owns leading positions in the Eagle Ford, Utica, Granite Wash, Cleveland, Tonkawa, Mississippi Lime and Niobrara unconventional liquids plays and in the Marcellus, Haynesville/Bossier and Barnett unconventional natural gas shale plays. The company has also vertically integrated its operations and owns substantial marketing, midstream and oilfield services businesses directly and indirectly through its subsidiaries Chesapeake Energy Marketing, Inc., Chesapeake Midstream Development, L.P. and COS Holdings, L.L.C.  Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)

THREE MONTHS ENDED:	June 30,				June 30,
	2012				2011
	$		$/mcfe		$		$/mcfe
REVENUES:
Natural gas, oil and NGL		2,117		6.11		1,792		6.46
Marketing, gathering and compression		1,113		3.21		1,404		5.06
Oilfield services		159		0.46		122		0.44
Total Revenues		3,389		9.78		3,318		11.96
OPERATING EXPENSES:
Natural gas, oil and NGL production		335		0.97		262		0.94
Production taxes		41		0.12		46		0.17
Marketing, gathering and compression		1,096		3.16		1,366		4.92
Oilfield services		109		0.31		92		0.33
General and administrative		156		0.45		130		0.46
Natural gas , oil and NGL depreciation, depletion and amortization		588		1.70		366		1.32
Depreciation and amortization of other assets		83		0.24		63		0.23
Losses on sales and impairments of fixed assets		243		0.70		8		0.04
Total Operating Expenses		2,651		7.65		2,333		8.41
INCOME (LOSS) FROM OPERATIONS		738		2.13		985		3.55
OTHER INCOME (EXPENSE):
Interest expense		(14)		(0.04)		(25)		(0.09)
Earnings (losses) on investments		(59)		(0.17)		47		0.17
Gain on sale of investment		1,030		2.97		—		—
Losses on purchases or exchanges of debt		—		—		(174)		(0.63)
Other income		5		0.01		2		0.01
Total Other Income (Expense)		962		2.77		(150)		(0.54)
INCOME (LOSS) BEFORE INCOME TAXES		1,700		4.90		835		3.01
INCOME TAX EXPENSE (BENEFIT):
Current income taxes		2		—		6		0.02
Deferred income taxes		661		1.91		319		1.15
Total Income Tax Expense (Benefit)		663		1.91		325		1.17
NET INCOME (LOSS)		1,037		2.99		510		1.84
Net income attributable to noncontrolling interests		(65)		(0.19)		—		—
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE		972		2.80		510		1.84
Preferred stock dividends		(43)		(0.12)		(43)		(0.16)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS		929		2.68		467		1.68
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	1.45			$	0.74
Diluted	$	1.29			$	0.68
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
Basic		642				635
Diluted		751				751

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

(unaudited)

SIX MONTHS ENDED:	June 30,				June 30,
	2012				2011
	$		$/mcfe		$		$/mcfe
REVENUES:
Natural gas, oil and NGL		3,185		4.69		2,286		4.10
Marketing, gathering and compression		2,328		3.43		2,421		4.35
Oilfield services		294		0.43		223		0.40
Total Revenues		5,807		8.55		4,930		8.85
OPERATING EXPENSES:
Natural gas, oil and NGL production		685		1.01		500		0.90
Production taxes		89		0.13		91		0.16
Marketing, gathering and compression		2,292		3.37		2,352		4.22
Oilfield services		205		0.30		169		0.30
General and administrative		292		0.43		259		0.46
Natural gas, oil and NGL depreciation, depletion and amortization		1,094		1.61		724		1.30
Depreciation and amortization of other assets		166		0.25		131		0.24
Losses on sales and impairments of fixed assets		241		0.36		3		0.01
Total Operating Expenses		5,064		7.46		4,229		7.59
INCOME (LOSS) FROM OPERATIONS		743		1.09		701		1.26
OTHER INCOME (EXPENSE):
Int)erest expense		(26)		(0.04)		(33)		(0.06)
Earnings (losses) on investments		(64)		(0.09)		72		0.13
Gain on sale of investment		1,030		1.51		—		—
Losses on purchases or exchanges of debt		—		—		(176)		(0.32)
Other income		11		0.02		5		0.01
Total Other Income (Expense)		951		1.40		(132)		(0.24)
INCOME (LOSS) BEFORE INCOME TAXES		1,694		2.49		569		1.02
INCOME TAX EXPENSE (BENEFIT):
Current income taxes		2		—		12		0.02
Deferred income taxes		659		0.97		210		0.38
Total Income Tax Expense (Benefit)		661		0.97		222		0.40
NET INCOME (LOSS)		1,033		1.52		347		0.62
Net income attributable to noncontrolling interests		(89)		(0.13)		—		—
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE		944		1.39		347		0.62
Preferred stock dividends		(86)		(0.13)		(85)		(0.15)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS		858		1.26		262		0.47
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	1.34			$	0.41
Diluted	$	1.25			$	0.41
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions):
Basic		642				635
Diluted		752				645

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)

	June 30,		December 31,
	2012		2011
Cash and cash equivalents	$	1,024	$	351
Other current assets		3,492		2,826
Total Current Assets		4,516		3,177
Property and equipment (net)		41,874		36,739
Other assets		1,136		1,919
Total Assets	$	47,526	$	41,835
Current liabilities	$	6,259	$	7,082
Long-term debt, net of discounts		14,329		10,626
Other long-term liabilities		2,367		2,682
Deferred tax liabilities		4,783		3,484
Total Liabilities		27,738		23,874
Chesapeake stockholders’ equity		17,427		16,624
Noncontrolling interests		2,361		1,337
Total Equity		19,788		17,961
Total Liabilities and Equity	$	47,526	$	41,835
Common Shares Outstanding (in millions)		662		659

CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

($ in millions)

(unaudited)

	June 30,				December 31,
	2012				2011
Total debt, net of unrestricted cash		$	13,305			$	10,275
Chesapeake stockholders' equity			17,427				16,624
Noncontrolling interests(a)			2,361				1,337
Total		$	33,093			$	28,236
Debt to capitalization ratio			40	%			36	%

(a)   Includes third-party ownership as follows:

CHK Cleveland Tonkawa, L.L.C.	$	1,015	$	—
CHK Utica, L.L.C.		950		950
Chesapeake Granite Wash Trust		376		380
Cardinal Gas Services, L.L.C.		20		7
Total	$	2,361	$	1,337

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2012 FIRST HALF ADDITIONS TO NATURAL GAS AND OIL PROPERTIES

BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AS OF JUNE 30, 2012

 ($ in millions, except per-unit data)

(unaudited)

	Proved Reserves
	Cost		Bcfe(a)			$/Mcfe
PROVED PROPERTIES:
Well costs on proved properties(b)	$	4,736		4,157	(c)	1.14
Acquisition of proved properties		17		9		1.97
Sale of proved properties		(774)		(319)		2.42
Total net proved properties		3,979		3,847		1.03
Revisions – price		—		(4,565)		—
UNPROVED PROPERTIES:
Well costs on unproved properties		224		—		—
Acquisition of unproved properties, net		1,309		—		—
Sale of unproved properties		(666)		—		—
Total net unproved properties		867		—		—
OTHER:
Capitalized interest on unproved properties		469		—		—
Geological and geophysical costs		103		—		—
Asset retirement obligations		10		—		—
Total other		582		—		—
Total	$	5,428		(718)		—

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

SIX MONTHS ENDED JUNE 30, 2012

BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AS OF JUNE 30, 2012

(unaudited)

	Bcfe(a)
Beginning balance, January 1, 2012	18,789
Production	(679)
Acquisitions	9
Divestitures	(319)
Revisions – changes to previous estimates	462
Revisions – price	(4,565)
Extensions and discoveries	3,695
Ending balance, June 30, 2012	17,392
Proved reserves growth rate before acquisitions and divestitures	(6)		%
Proved reserves growth rate after acquisitions and divestitures	(7)		%
Proved developed reserves	10,281
Proved developed reserves percentage	59		%
PV-10 ($ in billions)(a)	$	19.729

(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 June 30, 2012 of $3.15 per mcf of natural gas and $95.79 per bbl of oil, before field differential adjustments.
(b)	Net of well cost carries of $518 million associated with the Statoil-Marcellus, CNOOC-Eagle Ford, CNOOC-Niobrara and Total-Utica joint ventures.
(c)	Includes 462 bcfe of positive revisions resulting from changes to previous estimates and excludes downward revisions of 4.565 tcfe resulting from lower natural gas prices using the average first-day-of-the-month price for the twelve months ended June 30, 2012, compared to the twelve months ended December 31, 2011.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2012 FIRST HALF ADDITIONS TO NATURAL GAS AND OIL PROPERTIES

BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AS OF JUNE 30, 2012

 ($ in millions, except per-unit data)

 (unaudited)

	Proved Reserves
	Cost		Bcfe(a)			$/Mcfe
PROVED PROPERTIES:
Well costs on proved properties(b)	$	4,736		3,827	(c)	1.24
Acquisition of proved properties		17		9		1.91
Sale of proved properties		(774)		(319)		2.42
Total net proved properties		3,979		3,517		1.13
Revisions – price		—		(615)		—
UNPROVED PROPERTIES:
Well costs on unproved properties		224		—		—
Acquisition of unproved properties, net		1,309		—		—
Sale of unproved properties		(666)		—		—
Total net unproved properties		867		—		—
OTHER:
Capitalized interest on unproved properties		469		—		—
Geological and geophysical costs		103		—		—
Asset retirement obligations		10		—		—
Total other		582		—		—
Total	$	5,428		2,902		—

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

SIX MONTHS ENDED JUNE 30, 2012

BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AS OF JUNE 30, 2012

 (unaudited)

	Bcfe(a)
Beginning balance, January 1, 2012	19,887
Production	(679)
Acquisitions	9
Divestitures	(319)
Revisions – changes to previous estimates	(62)
Revisions – price	(615)
Extensions and discoveries	3,890
Ending balance, June 30, 2012	22,111
Proved reserves growth rate before acquisitions and divestitures	13		%
Proved reserves growth rate after acquisitions and divestitures	11		%
Proved developed reserves	11,383
Proved developed reserves percentage	52		%
PV-10 ($ in billions)(a)	$	25.125

(a)	Reserve volumes and PV-10 value estimated using SEC reserve recognition standards and 10-year average NYMEX strip prices as of June 30, 2012 of $4.33 per mcf of natural gas and $86.76 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 $518 million associated with the Statoil-Marcellus, CNOOC-Eagle Ford, CNOOC-Niobrara and Total-Utica joint ventures.
(c)	Includes 62 bcfe of downward revisions resulting from changes to previous estimates and excludes downward revisions of 615 bcfe resulting from lower natural gas and oil prices using 10-year average NYMEX strip prices as of June 30, 2012, compared to December 31, 2011.

CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA – NATURAL GAS, OIL AND NGL SALES AND INTEREST EXPENSE

 (unaudited)

	Three Months Ended				Six Months Ended
	June 30,		June 30,		June 30,		June 30,
	2012		2011		2012		2011
Natural Gas, Oil and NGL Sales ($ in millions):
Natural gas sales	$	336	$	764	$	815	$	1,552
Natural gas derivatives – realized gains (losses)		182		452		339		958
Natural gas derivatives – unrealized gains (losses)		(164)		(115)		(311)		(665)
Total Natural Gas Sales		354		1,101		843		1,845
Oil sales		656		377		1,247		661
Oil derivatives – realized gains (losses)		15		(34)		(19)		(42)
Oil derivatives – unrealized gains (losses)		955		219		817		(398)
Total Oil Sales		1,626		562		2,045		221
NGL sales		120		137		272		252
NGL derivatives – realized gains (losses)		(2)		(11)		(9)		(20)
NGL derivatives – unrealized gains (losses)		19		3		34		(12)
Total NGL Sales		137		129		297		220
Total Natural Gas, Oil and NGL Sales	$	2,117	$	1,792	$	3,185	$	2,286
Average Sales Price – excluding gains (losses) on derivatives:
Natural gas ($ per mcf)	$	1.22	$	3.26	$	1.49	$	3.25
Oil ($ per bbl)	$	89.49	$	96.69	$	93.49	$	93.40
NGL ($ per bbl)	$	26.40	$	41.66	$	30.68	$	40.93
Natural gas equivalent ($ per mcfe)	$	3.21	$	4.61	$	3.43	$	4.43
Average Sales Price – excluding unrealized gains (losses) on derivatives:
Natural gas ($ per mcf)	$	1.88	$	5.19	$	2.11	$	5.25
Oil ($ per bbl)	$	91.58	$	87.99	$	92.06	$	87.39
NGL ($ per bbl)	$	25.94	$	38.37	$	29.68	$	37.74
Natural gas equivalent ($ per mcfe)	$	3.77	$	6.07	$	3.89	$	6.03
Interest Expense (Income) ($ in millions):
Interest (a)	$	21	$	6	$	28	$	15
Derivatives – realized (gains) losses		(1)		13		—		6
Derivatives – unrealized (gains) losses		(6)		6		(2)		12
Total Interest Expense	$	14	$	25	$	26	$	33

(a) Net of amounts capitalized.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

($ in millions)

(unaudited)

THREE MONTHS ENDED:	June 30,		June 30,
	2012		2011
Beginning cash	$	438	$	849
Cash provided by operating activities		755		1,375
Cash flows from investing activities:
Well costs on proved and unproved properties		(2,504)		(1,661)
Acquisition of proved and unproved properties(a)		(540)		(1,150)
Sale of proved and unproved properties		615		870
Geological and geophysical costs		(42)		(42)
Investments, net		1,945		208
Other property and equipment, net		(590)		(673)
Other		(155)		(18)
Total cash provided by (used in) investing activities		(1,271)		(2,466)
Cash provided by (used in) financing activities		1,109		351
Cash and cash equivalents classified in current assets held for sale		(7)		—
Ending cash	$	1,024	$	109

(a) Includes capitalized interest of $164 million and $129 million for the current quarter and prior quarter, respectively.

SIX MONTHS ENDED:	June 30,		June 30,
	2012		2011
Beginning cash	$	351	$	102
Cash provided by operating activities		1,029		2,093
Cash flows from investing activities:
Well costs on proved and unproved properties		(5,007)		(3,282)
Acquisition of proved and unproved properties(b)		(1,657)		(2,184)
Sale of proved and unproved properties		1,418		5,828
Geological and geophysical costs		(113)		(113)
Investments, net		1,872		212
Other property and equipment, net		(1,232)		(676)
Other		(202)		(25)
Total cash provided by (used in) investing activities		(4,921)		(240)
Cash provided by (used in) financing activities		4,572		(1,846)
Cash and cash equivalents classified in current assets held for sale		(7)		—
Ending cash	$	1,024	$	109

(b) Includes capitalized interest of $326 million and $327 million for the current period and prior period, respectively.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)

THREE MONTHS ENDED:	June 30,		March 31,		June 30,
	2012		2012		2011
CASH PROVIDED BY OPERATING ACTIVITIES	$	755	$	274	$	1,375
Changes in assets and liabilities		140		636		(168)
OPERATING CASH FLOW(a)	$	895	$	910	$	1,207

THREE MONTHS ENDED:	June 30,		March 31,			June 30,
	2012		2012			2011
NET INCOME (LOSS)	$	1,037	$	(3	)	$	510
Income tax expense (benefit)		663		(2	)		325
Interest expense		14		12			25
Depreciation and amortization of other assets		83		84			63
Natural gas, oil and NGL depreciation, depletion and amortization		588		506			366
EBITDA(b)	$	2,385	$	597		$	1,289

THREE MONTHS ENDED:	June 30,		March 31,		June 30,
	2012		2012		2011
CASH PROVIDED BY OPERATING ACTIVITIES	$	755	$	274	$	1,375
Changes in assets and liabilities		140		636		(168)
Interest expense		14		12		25
Unrealized gains (losses) on natural gas, oil and NGL derivatives		810		(270)		106
Gains (losses) on sales and impairments of fixed assets		(243)		2		(8)
Gains (losses) on investments		943		(33)		19
Stock-based compensation		(31)		(32)		(39)
Other items		(3)		8		(21)
EBITDA(b)	$	2,385	$	597	$	1,289

(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)

SIX MONTHS ENDED:	June 30,		June 30,
	2012		2011
CASH PROVIDED BY OPERATING ACTIVITIES	$	1,029	$	2,093
Changes in assets and liabilities		776		495
OPERATING CASH FLOW(a)	$	1,805	$	2,588

SIX MONTHS ENDED:	June 30,		June 30,
	2012		2011
NET INCOME (LOSS)	$	1,033	$	347
Income tax expense (benefit)		661		222
Interest expense		26		33
Depreciation and amortization of other assets		166		131
Natural gas, oil and NGL depreciation, depletion and amortization		1,094		724
EBITDA(b)	$	2,980	$	1,457

SIX MONTHS ENDED:	June 30,		June 30,
	2012		2011
CASH PROVIDED BY OPERATING ACTIVITIES	$	1,029	$	2,093
Changes in assets and liabilities		776		495
Interest expense		26		33
Unrealized gains (losses) on natural gas, oil and NGL derivatives		540		(1,075)
Gains (losses) on sales and impairments of fixed assets		(241)		(3)
Gains (losses) on investments		910		24
Stock-based compensation		(63)		(79)
Other items		3		(31)
EBITDA(b)	$	2,980	$	1,457

(a)

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

(b)

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

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED EBITDA

($ in millions)

(unaudited)

	June 30,		March 31,		June 30,
THREE MONTHS ENDED:	2012		2012		2011
EBITDA	$	2,385	$	597	$	1,289
Adjustments:
Unrealized (gains) losses on natural gas, oil and NGL derivatives		(810)		270		(106)
(Gains) losses on sales and impairments of fixed assets		243		(2)		8
Net income attributable to noncontrolling interests		(65)		(25)		—
Losses on purchases or exchanges of debt		—		—		174
Gains on investments		(957)		—		—
Other		7		(2)		—
Adjusted EBITDA(a)	$	803	$	838	$	1,365

(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.

	June 30,		June 30,
SIX MONTHS ENDED:	2012		2011
EBITDA	$	2,980	$	1,457
Adjustments:
Unrealized (gains) losses on natural gas, oil and NGL derivatives		(540)		1,075
(Gains) losses on sales and impairments of fixed assets		241		3
Net income attributable to noncontrolling interests		(89)		—
Losses on purchases or exchanges of debt		—		176
Gains on investments		(957)		—
Other		6		—
Adjusted EBITDA(a)	$	1,641	$	2,711

(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)

	June 30,		March 31,		June 30,
THREE MONTHS ENDED:	2012		2012		2011
Net income (loss) available to common stockholders	$	929	$	(71)	$	467
Adjustments, net of tax:
Unrealized (gains) losses on derivatives		(490)		167		(61)
(Gains) losses on sales and impairments of fixed assets		148		(1)		5
Losses on purchases or exchanges of debt		—		—		106
Gains on investments		(584)		—		—
Other		—		(1)		11
Adjusted net income available to common stockholders(a)		3		94		528
Preferred stock dividends		43		43		43
Total adjusted net income	$	46	$	137	$	571
Weighted average fully diluted shares outstanding(b)		751		752		751
Adjusted earnings per share assuming dilution(a)	$	0.06	$	0.18	$	0.76

(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)

	June 30,		June 30,
SIX MONTHS ENDED:	2012		2011
Net income (loss) available to common stockholders	$	858	$	262
Adjustments, net of tax:
Unrealized (gains) losses on derivatives		(323)		663
(Gains) losses on sales and impairments of fixed assets		147		2
Losses on purchases or exchanges of debt		—		107
Gains on investments		(584)		—
Other		(1)		11
Adjusted net income available to common stockholders(a)		97		1,045
Preferred stock dividends		86		85
Total adjusted net income	$	183	$	1,130
Weighted average fully diluted shares outstanding(b)		752		751
Adjusted earnings per share assuming dilution(a)	$	0.24	$	1.51

(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”

MANAGEMENT’S OUTLOOK AS OF AUGUST 6, 2012

Chesapeake periodically provides management guidance on certain factors that affect its future financial performance.  The primary changes from the company’s May 1, 2012 Outlook are in italicized bold and reflect estimated natural gas curtailments of approximately 60 bcf in the 2012 first half and also include estimated future production decreases of approximately 45 bcfe in 2012 and 140 bcfe in 2013 associated with the company’s planned Permian Basin, Mississippi Lime and other asset sales.  Management and the board of directors are currently reviewing operations for 2013 and beyond which could result in changes to this Outlook.  This Outlook is expected to be updated in connection with the company’s 2012 third quarter earnings release.

Chesapeake Energy Corporation Consolidated Projections

For Years Ending December 31, 2012 and 2013

	Year Ending 12/31/12	Year Ending 12/31/13
Estimated Production:
Natural gas – bcf	1,120 – 1,140	1,030 – 1,070
Oil – mbbls	29,000 – 30,000	36,000 – 38,000
NGL – mbbls	17,000 – 18,000	24,000 – 26,000
Natural gas equivalent – bcfe	1,396 – 1,428	1,390 – 1,454
Daily natural gas equivalent midpoint – mmcfe	3,855	3,895
YOY estimated production increase including asset sales	18%	1%
NYMEX Price(a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$2.79	$3.75
Oil - $/bbl	$93.93	$90.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$0.29	$0.01
Oil - $/bbl	$0.81	$0.48
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
Natural gas - $/mcf	$1.00 –1.10	$1.15 – 1.25
Oil - $/bbl	$4.50 – 6.50	$4.50 – 6.50
NGL - $/bbl	$67.00 – 70.00	$63.00 – 67.00
Operating Costs per Mcfe of Projected Production:
Production expense	$0.95 – 1.05	$0.95 – 1.05
Production taxes (~5% of O&G revenues)	$0.15 – 0.20	$0.25 – 0.30
General and administrative(b)	$0.39 – 0.44	$0.39 – 0.44
Stock-based compensation (noncash)	$0.04 – 0.06	$0.04 – 0.06
DD&A of natural gas and liquids assets	$1.40 – 1.60	$1.50 – 1.70
Depreciation of other assets	$0.22 – 0.27	$0.25 – 0.30
Interest expense(c)	$0.05 – 0.10	$0.05 – 0.10
Other ($ millions):
Marketing, gathering and compression net margin(d)	$70 – 80	$50 – 75
Oilfield services net margin(d)	$175 – 200	$200 – 250
Other income (including certain equity investments)	$25	–
Net income attributable to noncontrolling interest(e)	($180) – (200)	($200) – (240)
Book Tax Rate	39%	39%
Weighted average shares outstanding (in millions):
Basic	640 – 645	645 – 650
Diluted	753 – 758	758 – 763

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

	($ millions)
Operating cash flow before changes in assets and liabilities(f)(g)	$3,200 – 3,250	$3,750 – 4,750
Well costs on proved and unproved properties	($8,000 – 8,500)	($5,750 – 6,250)
Acquisition of unproved properties, net	($2,000)	($400)
Investment in oilfield services, midstream and other	($2,800 – 3,100)	($850 – 1,100)
Subtotal of net investment	($12,800 – 13,600)	($7,000 – 7,750)
Asset sales and other transactions	$13,000 – 14,000	$4,250 – 5,000
Interest, dividends and cash taxes	($1,100 –1,350)	($1,000 – 1,250)
Total budgeted cash flow surplus	$2,300	$0 – 750

(a)   NYMEX natural gas prices and NYMEX oil prices have been updated for actual contract prices through August and July, respectively.

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

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

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

(e)   Net income attributable to noncontrolling interests of Chesapeake Granite Wash Trust, CHK Utica, L.L.C., CHK Cleveland Tonkawa, L.L.C. and Cardinal Gas Services, L.L.C.

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

(g)   Assumes NYMEX prices on open contracts of $3.00 to $3.25 per mcf and $90.00 per bbl in 2012 and $3.25 to $4.25 per mcf and $90.00 per bbl in 2013.

Oil, NGL and Natural Gas Hedging Activities

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

As of August 6, 2012, the company has the following open natural gas swaps in place through 2012.  The company currently has $212 million of net hedging losses related to closed natural gas contracts and premiums for call options for future production periods.

	Open Swaps (bcf)	Avg. NYMEX Price of Open Swaps		Forecasted Natural Gas Production (bcf)	Open Swap Positions as a % of Forecasted Natural Gas Production		Total Gains (Losses) from Closed Trades and Premiums for Call Options ($ in millions)			Total Gains from Closed Trades and Premiums for Call Options per mcf of Forecasted Natural Gas Production
Q3 2012	167	$	3.02				$	32
Q4 2012	204	$	3.04					15
Q3-Q4 2012	371	$	3.03	584	64	%	$	47		$	0.08
Total 2013	0	$	0.00	1,050	0	%	$	16		$	0.01
Total 2014	0						$	(34	)
Total 2015	0						$	(110	)
Total 2016 – 2022	0						$	(131	)

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

	Call Options (bcf)	Avg. NYMEX Strike Price		Forecasted Natural Gas Production (bcf)	Call Options as a % of Forecasted Natural Gas Production
Q3 2012	40	$	3.25
Q4 2012	41		3.25
Q3-Q4 2012	81	$	3.25	584	14	%
Total 2013	251	$	6.31	1,050	24	%
Total 2014	330	$	6.43
Total 2015	116	$	6.45
Total 2016 – 2020	349	$	8.18

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

	Volume (Bcf)	Avg. NYMEX less
2012	29	$	0.78
2013	44	$	0.21
2014 - 2022	67	$	0.42
Totals	140	$	0.43

As of August 6, 2012, the company has the following open crude oil swaps in place for 2012 and through 2015.  In addition, the company has $193 million of net hedging gains related to closed crude oil contracts and premiums for call options for future production periods.

	Open Swaps (mbbls)	Avg. NYMEX Price of Open Swaps		Forecasted Liquids Production (mbbls)	Open Swap Positions as a % of Forecasted Liquids Production	Total Gains (Losses) from Closed Trades and Premiums for Call Options ($millions)		Total Gains (Losses) from Closed Trades and Premiums for Call Options per bbl of Forecasted Liquids Production
Q3 2012	3,754	$	101.56			$	(11)
Q4 2012	3,841		101.12				(33)
Q3-Q4 2012	7,595	$	101.34	24,816	31%	$	(44)	$	(1.78)
Total 2013	3,122	$	94.06	62,000	5%	$	6	$	0.10
Total 2014	902	$	90.72			$	(151)
Total 2015	500	$	88.75			$	265
Total 2016 – 2021						$	117

The company currently has the following crude oil written call options in place for 2012 through 2017:

	Call Options (mbbls)	Avg. NYMEX Strike Price		Forecasted Liquids Production (mbbls)	Call Options as a % of Forecasted Liquids Production
Q3 2012	0	$	--
Q4 2012	460		106.72
Q3-Q4 2012	460	$	106.72	24,816	2%
Total 2013	15,633	$	100.50	62,000	25%
Total 2014	17,612	$	98.79
Total 2015	27,048	$	100.99
Total 2016 – 2017	24,220	$	100.07

SCHEDULE “B”

MANAGEMENT’S OUTLOOK AS OF MAY 1, 2012

(PROVIDED FOR REFERENCE ONLY)

NOW SUPERSEDED BY OUTLOOK AS OF AUGUST 6, 2012

Below is the company’s previous Outlook, as provided on May 1, 2012, which reflected projected voluntary natural gas curtailments of 60-100 bcf in 2012 and included estimated production decreases of approximately 60 bcfe in 2012 and 90 bcfe in 2013 associated with potential Permian Basin, Mississippi Lime, VPP and other monetization 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	1,040 – 1,060	970 – 1,010
Liquids – mbbls	41,000 – 43,000	55,000 – 59,000
Natural gas equivalent – bcfe	1,286 – 1,318	1,300 – 1,364
Daily natural gas equivalent midpoint – mmcfe	3,555	3,650
Year over year (YOY) estimated production increase excluding asset sales	17%	7%
YOY estimated production increase	9%	2%
NYMEX Price(a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$2.50	$3.50
Oil - $/bbl	$100.73	$100.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$0.35	$0.02
Liquids - $/bbl	($4.69)	($1.03)
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
Natural gas - $/mcf	$0.90 – $1.00	$0.90 – $1.00
Liquids - $/bbl(b)	$30.00 – $35.00	$25.00 – $30.00
Operating Costs per Mcfe of Projected Production:
Production expense	$0.95 – 1.05	$0.95 – 1.05
Production taxes (~ 5% of O&G revenues)	$0.15 – 0.20	$0.25 – 0.30
General and administrative(c)	$0.39 – 0.44	$0.39 – 0.44
Stock-based compensation (noncash)	$0.04 – 0.06	$0.04 – 0.06
DD&A of natural gas and liquids assets	$1.40 – 1.60	$1.50 – 1.70
Depreciation of other assets	$0.25 – 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)	$70 – 80	$85 – 95
Oilfield services net margin(e)	$200 – 250	$300 – 400
Other income (including certain equity investments)	$75 – 100	$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

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

	($ millions)
Operating cash flow before changes in assets and liabilities(g)(h)	$2,700 – 3,000	$4,400 – 5,300
Well costs on proved properties	($6,500 – 7,000)	($5,500 – 6,000)
Well costs on unproved properties	($1,000)	($1,000)
Acquisition of unproved properties, net	($1,600)	($500)
Sale of proved and unproved properties	$9,500 – 11,000	$4,500 – 5,000
Subtotal of net investment in proved and unproved properties	$400 – 1,400	($2,500)
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 – 3,000	$1,000 – 1,500
Subtotal of net investment in oilfield services, midstream and other	($500)	($1,000)
Interest, dividends and cash taxes	($1,000 –1,250)	($1,000 – 1,250)
Total budgeted cash flow surplus (deficit)	$1,600 – 2,650	($100) – $550

a)   NYMEX natural gas prices have been updated for actual contract prices through May 2012 and NYMEX oil prices have been updated for actual contract prices through March 2012.

b)   Differentials include effects of natural gas liquids.

c)   Excludes expenses associated with noncash 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 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 $2.25 to $2.75 per mcf and $100.00 per bbl in 2012 and $3.00 to $4.00 per mcf and $100.00 per bbl in 2013.

Oil, NGL and Natural Gas Hedging Activities

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

At May 1, 2012, the company does not have any open natural gas swaps in place.  The company currently has $13 million of net hedging losses related to closed natural gas contracts and premiums for call options for future production periods.

	Open Swaps (bcf)	Avg. NYMEX Price of Open Swaps		Forecasted Natural Gas Production (bcf)	Open Swap Positions as a % of Forecasted Natural Gas Production		Total Gains (Losses) from Closed Trades and Premiums for Call Options ($ in millions)			Total Gains from Closed Trades and Premiums for Call Options per mcf of Forecasted Natural Gas Production
Q2 2012							$	195
Q3 2012								32
Q4 2012								15
Q2-Q4 2012	0	$	0.00	779	0	%	$	242		$	0.31
Total 2013	0	$	0.00	990	0	%	$	20		$	0.02
Total 2014	0						$	(34	)
Total 2015	0						$	(110	)
Total 2016 – 2022	0						$	(131	)

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

	Call Options (bcf)	Avg. NYMEX Strike Price		Forecasted Natural Gas Production (bcf)	Call Options as a % of Forecasted Natural Gas Production
Q2 2012	13	$	6.54
Q3 2012	40		6.54
Q4 2012	41		6.54
Q2-Q4 2012	94	$	6.54	779	12	%
Total 2013	415	$	6.44	990	42	%
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	49	$	0.79
2013	44	$	0.21
2014 - 2022	67	$	0.42
Totals	160	$	0.47

At May 1, 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
Q2 2012	7,285	$	102.58			$	(52	)
Q3 2012	6,178		103.45				(67	)
Q4 2012	5,680		103.13				(75	)
Q2-Q4 2012(a)	19,143	$	103.02	31,666	60%	$	(194	)	$	(6.14)
Total 2013	4,947	$	102.86	57,000	9%	$	24		$	0.41
Total 2014	902	$	90.72			$	(106	)
Total 2015	500	$	88.75			$	265
Total 2016 – 2021						$	116

(a) Certain hedging contracts include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 550 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
Q2 2012	-		-
Q3 2012	1,840	$	106.38
Q4 2012	2,300		106.45
Q2-Q4 2012	4,140	$	106.42	31,666	13%
Total 2013	24,953	$	96.88	57,000	44%
Total 2014	23,620	$	98.62
Total 2015	27,048	$	100.99
Total 2016 – 2017	24,220	$	100.07