Chesapeake Energy Corporation Reports Financial and Operational Results for the 2011 First Quarter

Chesapeake Energy Corporation (NYSE:CHK) today announced its 2011 first quarter financial and operational results. For the quarter, Chesapeake reported a net loss to common stockholders of $205 million ($0.32 per fully diluted common share), operating cash flow of $1.404 billion (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $167 million (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization) on revenue of $1.612 billion and production of 280 billion cubic feet of natural gas equivalent (bcfe).

The company’s 2011 first quarter results 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 first quarter, Chesapeake reported adjusted net income to common stockholders of $518 million ($0.75 per fully diluted common share) and adjusted ebitda of $1.346 billion. The excluded items and their effects on the 2011 first quarter reported results are detailed as follows:

• a net unrealized after-tax mark-to-market loss of $725 million resulting from the company’s natural gas, oil and interest rate hedging programs;
• a net after-tax gain of $3 million related to the sale of certain of the company’s fixed assets; and
• an after-tax loss of $1 million related to the redemption of certain of the company's senior notes.

The various items described above do not materially affect the calculation of operating cash flow. 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 18 – 20 of this release.

Key Operational and Financial Statistics Summarized

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

				Three Months Ended
				3/31/11			12/31/10			3/31/10
Average daily production (in mmcfe)				3,107			2,920			2,586
Natural gas as % of total production				87			88			90
Natural gas production (in bcf)				243.3			235.3			209.6
Average realized natural gas price ($/mcf)(a)				5.31			5.22			6.31
Oil and NGL production (in mbbls)				6,048			5,562			3,871
Average realized oil and NGL price ($/bbl)(a)				63.20			62.62			67.70
Natural gas equivalent production (in bcfe)				279.6			268.7			232.8
Natural gas equivalent realized price ($/mcfe)(a)				5.99			5.87			6.80
Marketing, gathering and compression net margin ($/mcfe)(b)				.11			.13			.12
Service operations net margin ($/mcfe) (b)				.09			.05			.03
Production expenses ($/mcfe)				(.85	)		(.90	)		(.89	)
Production taxes ($/mcfe)				(.16	)		(.14	)		(.21	)
General and administrative costs ($/mcfe)(c)				(.38	)		(.34	)		(.38	)
Stock-based compensation ($/mcfe)				(.08	)		(.08	)		(.09	)
DD&A of natural gas and oil properties ($/mcfe)				(1.28	)		(1.37	)		(1.32	)
D&A of other assets ($/mcfe)				(.24	)		(.23	)		(.21	)
Interest (expense) income ($/mcfe)(a)				.00			.01			(.22	)
Operating cash flow ($ in millions)(d)				1,404			1,370			1,261
Operating cash flow ($/mcfe)				5.02			5.10			5.42
Adjusted ebitda ($ in millions)(e)				1,346			1,274			1,270
Adjusted ebitda ($/mcfe)				4.81			4.75			5.46
Net income (loss) to common stockholders ($ in millions)				(205	)		180			732
Earnings (loss) per share – assuming dilution ($)				(.32	)		.28			1.14
Adjusted net income to common stockholders ($ in millions)(f)				518			478			524
Adjusted earnings per share – assuming dilution ($)				.75			.70			.82

(a)		Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging.
(b)		Includes revenue and operating costs and excludes depreciation and amortization of other assets.
(c)		Excludes expenses associated with noncash stock-based compensation.
(d)		Defined as cash flow provided by operating activities before changes in assets and liabilities.
(e)		Defined as net income (loss) before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 19.
(f)		Defined as net income (loss) available to common stockholders, as adjusted to remove the effects of certain items detailed on page 20.

2011 First Quarter Average Daily Production of 3.107 Bcfe per Day Increases 20% over 2010 First Quarter Production and 6% over 2010 Fourth Quarter Production; 2011 First Quarter Liquids Production Increases 56% Compared to the 2010 First Quarter and 9% Compared to the 2010 Fourth Quarter; 2011 First Quarter Liquids Production Accounts for 13% of Total Production and 23% of Realized Natural Gas and Oil Revenue

Chesapeake’s daily production for the 2011 first quarter averaged 3.107 bcfe, an increase of 521 million cubic feet of natural gas equivalent (mmcfe), or 20%, over the 2.586 bcfe produced per day in the 2010 first quarter and an increase of 187 mmcfe, or 6%, over the 2.920 bcfe produced per day in the 2010 fourth quarter.

Chesapeake’s average daily production of 3.107 bcfe for the 2011 first quarter consisted of 2.704 billion cubic feet of natural gas (bcf) and 67,200 barrels (bbls) of oil and natural gas liquids (NGLs). The company’s 2011 first quarter production of 279.6 bcfe was comprised of 243.3 bcf (87% on a natural gas equivalent basis) and 6.0 million bbls of oil and NGLs (liquids) (13% on a natural gas equivalent basis). 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 56%. Sequential quarterly production growth was 3% for natural gas and 9% for liquids. The company’s percentage of revenue from liquids in the 2011 first quarter was 23% of realized natural gas and oil revenue compared to 17% in the 2010 first quarter. In affirmation of its 25/25 Plan discussed on page 8 of this release, Chesapeake anticipates delivering production growth of 25% for the two-year period ending December 31, 2012, net of property divestitures.

Chesapeake’s Proved Natural Gas and Oil Reserves Decrease by 1.5 Tcfe, or 9%, in the 2011 First Quarter to 15.6 Tcfe Following the Sale of 2.5 Tcfe of Proved Reserves; Company Adds New Net Proved Reserves of 1.3 Tcfe through the Drillbit at a Drilling and Completion Cost of $1.25 per Mcfe

During the 2011 first quarter, Chesapeake continued the industry’s most active drilling program, drilling 375 gross operated wells (234 net wells with an average working interest of 62%) and participating in another 430 gross non-operated wells (60 net wells with an average working interest of 14%). The company’s drilling success rate was 98% for company-operated wells and 99% for non-operated wells. During the 2011 first quarter, Chesapeake’s drilling and completion costs of $1.664 billion included the benefit of approximately $527 million of drilling and completion carries from its joint venture partners.

The following table compares Chesapeake’s March 31, 2011 proved reserves, the decrease versus its year-end 2010 proved reserves, estimated future net cash flows from proved reserves (discounted at an annual rate of 10% before income taxes (PV-10)), and proved developed percentage based on the trailing 12-month average price required by the reserve reporting rules of the Securities and Exchange Commission (SEC) and the 10-year average NYMEX strip prices at March 31, 2011.

Pricing Method		Natural Gas Price ($/mcf)		Oil Price ($/bbl)		Proved Reserves (tcfe)(a)		Proved Reserves Decrease (tcfe)(b)		Proved Reserves Decrease %(b)		PV-10 (billions)		Proved Developed Percentage
Trailing 12-month average (SEC)(c)		$4.10		$83.34		15.6		1.5		9%		$14.3		55%
3/31/11 10-year average NYMEX strip(d)		$6.17		$103.13		16.5		1.1		7%		$28.1		55%

(a)		After sales of proved reserves of approximately 2.5 tcfe during the 2011 first quarter.
(b)		Compares proved reserve growth for the 2011 first quarter 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 at 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 March 31, 2011. This pricing yields estimated "proved reserves" for SEC reporting purposes. Natural gas and oil volumes estimated under any alternative pricing scenario reflect 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 development costs for the 2011 first quarter using the two pricing methods described above.

Development Cost Category		Trailing 12-Month Average (SEC) Pricing ($/mcfe)		3/31/11 10-year Average NYMEX Strip Pricing ($/mcfe)
Drilling and completion costs(a)		$1.25		$1.16
Drilling and completion costs, net of proved property divestitures(a)		$0.08		$0.08

(a)		Includes performance-related revisions and excludes price-related revisions. Costs are net of drilling and completion carries paid by the company’s joint venture partners.

A complete reconciliation of proved reserves based on these two alternative pricing methods, along with total costs, is presented on pages 14 and 15 of this release.

At the end of the 2011 first quarter, Chesapeake closed the sale of its upstream and midstream assets in the Fayetteville Shale to BHP Billiton Petroleum, a wholly owned subsidiary of BHP Billiton Limited (NYSE:BHP; ASX:BHP), for net proceeds of approximately $4.65 billion in cash. The sale included approximately 2.4 trillion cubic feet of natural gas equivalent (tcfe) of proved reserves, which resulted in the decline in proved reserves for the 2011 first quarter. Excluding this sale, Chesapeake’s proved reserves would have been 18.0 tcfe, an increase of 0.9 tcfe, or 5%, over the 2010 year-end proved reserves of 17.1 tcfe.

In addition to the PV-10 value of its proved reserves, the company also has substantial value in its undeveloped leasehold, particularly its unconventional natural gas shale plays in the Marcellus, Haynesville, Bossier, Pearsall and Barnett and its unconventional liquids-rich plays in the Granite Wash, Cleveland, Tonkawa and Mississippian plays of the Anadarko Basin; the Eagle Ford Shale in South Texas; the Niobrara Shale in the Powder River and DJ basins; the Bone Spring, Avalon, Wolfcamp and Wolfberry plays of the Permian Basin; the Three Forks/Bakken play in the Williston Basin; and the Utica Shale in the Appalachian Basin.

Additionally, the net book value of the company’s other assets (including gathering systems, compressors, land and buildings, investments and other non-current assets) was $6.1 billion as of March 31, 2011 and December 31, 2010.

Chesapeake’s Leasehold and 3-D Seismic Inventories Total 14.3 Million Net Acres and 28.3 Million Acres, Respectively; Risked Unproved Resources in the Company’s Inventory Total 107 Tcfe; Company’s Leasehold Reaches 1.2 Million Net Acres in the Utica Shale Play in the Appalachian Basin and 1.1 Million Net Acres in the Mississippian Carbonate Play in Northern Oklahoma and Southern Kansas; Company Expects to Commence JV Process for Each Play in the 2011 Second Half

Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (14.3 million net acres) and 3-D seismic (28.3 million acres) in the U.S. The company has accumulated the largest inventory of U.S. natural gas shale play leasehold (2.5 million net acres) and now owns a leading position in 12 of the Top 13 unconventional liquids-rich plays in the U.S. – the Granite Wash, Cleveland, Tonkawa and Mississippian plays of the Anadarko Basin; the Avalon, Bone Spring, Wolfcamp and Wolfberry plays of the Permian Basin; the Eagle Ford Shale of South Texas; the Niobrara Shale in the Powder River and DJ basins; the Three Forks/Bakken in the Williston Basin; and the Utica Shale of the Appalachian Basin.

On its total leasehold inventory, Chesapeake has identified an estimated 16.5 tcfe of proved reserves (using volume estimates based on the 10-year average NYMEX strip prices at March 31, 2011), 107 tcfe of risked unproved resources and 289 tcfe of unrisked unproved resources. The company is currently using 156 operated drilling rigs to further develop its inventory of approximately 39,000 net drillsites. Of Chesapeake’s 156 operated rigs, 88 are drilling wells primarily focused on unconventional natural gas plays (including 53 operated rigs utilizing drilling carries) and 65 are drilling wells primarily focused on unconventional liquids-rich plays (including 23 operated rigs utilizing drilling carries). In addition, 151 of the company’s 156 operated rigs are drilling horizontal wells.

In recognition of the value gap between oil and natural gas prices, Chesapeake has directed a significant portion of its technological and leasehold acquisition expertise during the past two years to identify, secure and commercialize new unconventional liquids-rich plays. To date, Chesapeake has built leasehold positions and established production in multiple liquids-rich plays on approximately 5.1 million net leasehold acres with 5.6 billion bbls of oil equivalent (bboe) (34 tcfe) of risked unproved resources and 17.5 bboe (105 tcfe) of unrisked unproved resources. As a result of its success to date, Chesapeake expects to increase its oil and natural gas liquids production through its drilling activities to more than 150,000 bbls per day, or 20%-25% of total production, by year-end 2012 and to more than 250,000 bbls per day, or 30%-35% of total production, through organic growth by year-end 2015.

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

				Est.				Risked		Total		Risked		Unrisked		Apr-11		Apr-11
		CHK		Drilling				Net		Proved		Unproved		Unproved		Daily Net		Operated
		Net		Density		Risk		Undrilled		Reserves		Resources		Resources		Production		Rig
Play Type/Area		Acreage(1)		(Acres)		Factor		Wells		(bcfe)(1)(2)		(bcfe)(1)		(bcfe)(1)		(mmcfe)		Count
Unconventional Natural Gas Plays:
Marcellus		1,730,000		80		60%		8,610		956		38,100		95,900		290		33
Haynesville		515,000		80		30%		4,280		3,987		18,000		26,900		1,000		33
Bossier(3)		200,000		80		60%		970		14		4,000		10,000		15		2
Barnett		220,000		60		25%		1,700		3,469		3,100		4,100		370		18
Pearsall(4)		350,000		160		75%		550		2		2,500		9,800		ND		2
Subtotal		2,465,000						16,110		8,428		65,700		146,700		1,675		88
Unconventional Liquids Plays:
Anadarko Basin(5)		1,990,000		155		70%		4,240		2,184		12,900		33,500		505		31
Eagle Ford		450,000		80		50%		2,810		203		9,000		18,100		25		17
Permian Basin(6)		670,000		160		67%		1,360		262		3,200		9,900		95		8
Powder River and DJ Basins(7)		570,000		ND		ND		ND		ND		ND		ND		ND		6
Utica		1,200,000		ND		ND		ND		ND		ND		ND		ND		3
Other		190,000		ND		ND		ND		ND		ND		ND		ND		0
Subtotal		5,070,000						12,780		2,662		33,900		104,800		625		65
Other Conventional and
Unconventional Plays:		6,745,000		Various		Various		10,110		5,369		7,300		37,400		720		3
Total		14,280,000						39,000		16,459		106,900		288,900		3,020		156

Note: ND denotes "not disclosed”
(1)		As of March 31, 2011, pro forma for recent leasehold transactions
(2)		Based on 10-year average NYMEX strip prices at March 31, 2011
(3)		Bossier Shale acreage overlaps with Haynesville Shale acreage and is excluded from the play sub-total to avoid double counting of acreage
(4)		Pearsall Shale acreage overlaps with Eagle Ford Shale acreage and is excluded from the play sub-total to avoid double counting of acreage
(5)		Includes Granite Wash, Cleveland, Tonkawa and Mississippian plays
(6)		Includes only Delaware and Midland Basin plays
(7)		Includes Niobrara, Frontier and Codell plays

In 2007, the company was the first to initiate large-scale horizontal drilling in the Mississippian Carbonate play in northern Oklahoma and southern Kansas. To date, Chesapeake has drilled 53 operated Mississippian horizontal wells and has participated in the drilling of 36 non-operated Mississippian horizontal wells on its inventory of approximately 1.1 million net acres. Chesapeake is currently drilling with five operated rigs in the Mississippian play and plans to increase its operated drilling activity in the Mississippian to seven rigs by the 2011 fourth quarter.

In 2010, the company was the first to identify the potential of the Utica Shale and to initiate large scale leasing efforts in Ohio and western Pennsylvania for the Utica. To date, the company has drilled nine operated Utica wells and is currently drilling with three operated rigs. Chesapeake plans to increase its operated drilling activity in the Utica to six rigs by the end of the 2011 third quarter. The company expects to initiate a joint venture process in the 2011 second half for both the Mississippian and Utica plays.

2011 First Quarter Average Realized Prices Benefit from Realized Hedging Gains of $488 Million, or $1.74 per Mcfe; Company Provides Update on Hedging Positions

Average prices realized during the 2011 first quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.31 per thousand cubic feet (mcf) and $63.20 per bbl, for a realized natural gas equivalent price of $5.99 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains from natural gas hedging activities during the 2011 first quarter generated a $2.07 gain per mcf, while realized losses from oil hedging activities generated a $2.88 loss per bbl, for 2011 first quarter net realized hedging gains of $488 million, or $1.74 per mcfe.

By comparison, average prices realized during the 2010 first quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $6.31 per mcf and $67.70 per bbl, for a realized natural gas equivalent price of $6.80 per mcfe. Realized gains from natural gas and oil hedging activities during the 2010 first quarter generated a $1.81 gain per mcf and a $5.11 gain per bbl, for 2010 first quarter realized hedging gains of $399 million, or $1.71 per mcfe. The company’s realized cash hedging gains since January 1, 2001 have been $7.0 billion, or $1.20 per mcfe, on average, for every mcfe produced during the past ten years.

To provide protection against potentially weak natural gas prices in 2011 and the first half of 2012, Chesapeake has entered into hedges for a portion of its production in those two years. 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. The following table summarizes Chesapeake’s 2011 and 2012 open swap positions as of May 2, 2011.

			Natural Gas							Oil
Year			% of Forecasted Production				$ NYMEX			% of Forecasted Production				$ NYMEX
2Q – Q4 2011			88	%			$5.03			18	%			$102.96
2012			19	%			$6.17			10	%			$104.78

In addition to the open hedging positions disclosed above, as of May 2, 2011 (as detailed below), the company had an additional $725 million and $42 million of net hedging gains on closed contracts and premiums collected on call options that will be realized in 2011 and 2012, respectively.

			Natural Gas									Oil
Year			Forecasted Production (bcf)			Gains (Losses) ($ in millions)			Gains (Losses) ($/mcf)			Forecasted Production (mbbls)			Gains (Losses) ($ in millions)			Gains (Losses) ($/bbl)
2Q – Q4 2011			675			$687			$1.02			28,000			$38			$1.37
2012			980			$(9)			$(0.01)			54,000			$51			$0.94

Assuming future NYMEX natural gas settlement prices average $4.50 and $5.50 per mcf for 2011 and 2012, respectively, and including the effect of the company’s open hedges, closed contracts and previously collected call premiums, the company estimates its average NYMEX natural gas prices will be $5.98 and $5.60 per mcf for 2011 and 2012, respectively. Additionally, assuming future NYMEX oil settlement prices average $100 per bbl for 2011 and 2012, the company estimates its average NYMEX oil prices will be $96.22 and $95.80 per bbl for 2011 and 2012, respectively. These estimates do not include the effect of gathering costs and basis differentials, which include the effect of lower-priced NGLs on the company’s reported realized liquids prices.

Details of the company’s quarter-end hedging positions, including sold call options, are provided in the company’s Form 10-Q and Form 10-K filings with the SEC and current positions are disclosed in summary format in the company’s Outlook. The company’s updated forecasts for 2011 and 2012 are attached to this release in the Outlook dated May 2, 2011, labeled as Schedule "A,” which begins on page 21. The Outlook has been changed from the Outlook dated February 22, 2011, attached as Schedule "B,” which begins on page 25, to reflect various updated information.

Chesapeake Provides Update on 25/25 Plan; Company Agrees to Monetize Certain Mid-Continent Assets through its Ninth Volumetric Production Payment

On January 6, 2011, Chesapeake announced its 25/25 Plan, which outlined the company’s plan to reduce its long-term debt by 25% during 2011-12 while also delivering natural gas and oil production growth of 25% during these two years. The company expects to achieve the reduction in debt primarily with proceeds from asset monetizations and from substantially reduced leasehold spending during this period.

Two recent transactions reflect the company’s substantial progress already made in implementing its 25/25 Plan. On February 11, 2011, the company closed its Niobrara Shale cooperation agreement through which CNOOC Limited (NYSE:CEO; SEHK:00883) purchased a 33.3% undivided interest in Chesapeake’s 800,000 net natural gas and oil leasehold acres in the DJ and Powder River Basins in Colorado and Wyoming for approximately $4,750 per net acre. The company received approximately $570 million in cash at closing, and CNOOC has agreed to fund 66.7% of Chesapeake’s share of drilling and completion costs until an additional $697 million has been paid, which Chesapeake expects to occur by year-end 2014.

In addition, on March 31, 2011, Chesapeake closed the sale of its upstream and midstream assets in the Fayetteville Shale to BHP Billiton, for net proceeds of approximately $4.65 billion in cash.

Proceeds from the transactions above will fund the purchase of approximately $1.865 billion of the company’s senior notes and contingent convertible senior notes in May 2011 pursuant to company tender offers for the notes. Combined with the $140 million of contingent convertible senior notes purchased by Chesapeake in privately negotiated transactions in the past 60 days, Chesapeake will have retired an aggregate principal amount of approximately $2.005 billion of senior notes and contingent convertible senior notes in 2011. The company may negotiate or tender for the acquisition of additional senior notes and contingent convertible senior notes later in 2011 or in 2012.

Moreover, through a recently disclosed planned recapitalization of Frac Tech Services, LLC, Chesapeake anticipates receiving a cash distribution of approximately $200 million and will increase its ownership of the company’s equity from 26% to 30%. The Frac Tech recapitalization transaction is expected to close in the 2011 second quarter and the company believes that by year-end 2011, the value of its equity in Frac Tech will be worth up to $1.5 billion.

Additionally, Chesapeake has agreed to monetize certain of its producing assets in the Mid-Continent through a ten-year volumetric production payment (VPP) to an affiliate of Barclays PLC (NYSE:BCS; LSE:BARC) for proceeds of approximately $850 million. The transaction includes approximately 180 bcfe of proved reserves and approximately 80 mmcfe per day of current net production. Chesapeake has retained drilling rights on the properties below currently producing intervals and outside of existing producing wellbores and the production "tail” beyond ten years. The transaction will be Chesapeake’s ninth VPP and is expected to close in the 2011 second quarter. Inclusive of the pending VPP sale and the company’s eight previously closed VPPs, the company will have sold 1.215 tcfe of proved reserves for total proceeds of $5.619 billion, for an average sales price of $4.62 per mcfe.

Chesapeake Highlights its Oilfield Service Vertical Integration Strategy and Estimates that its Oilfield Service Assets Are Worth Approximately $7.0 Billion

Chesapeake has built a large inventory of low-risk natural gas and oil resources which the company plans to develop aggressively in the decades ahead. As a result, the company will consistently utilize a large and growing amount of oilfield services for this resource development. In the next decade alone, Chesapeake’s gross drilling and completion expenditures may reach $100 billion. This high level of planned drilling activity will create considerable value for the providers of oilfield services and Chesapeake’s strategy is to capture a portion of this value for its shareholders rather than transfer it to third-party vendors. In addition, the company utilizes its service company operations as a hedge against oilfield service inflation.

To date, Chesapeake has invested in drilling rigs, compression equipment, rental tools, water management equipment, trucking, midstream services and most recently, fracture stimulation equipment. Chesapeake’s industry-leading drilling and completion activities require a high level of planning and project coordination that the company believes is best accomplished through vertical integration and ownership of a significant portion of the oilfield services it utilizes. This vertical integration approach also creates a multitude of cost savings, an alignment of interests, operational synergies, greater capacity of equipment, increased safety and better coordinated logistics. In addition, Chesapeake’s control of a large portion of the oilfield service equipment it utilizes provides unique advantages in accelerating the timing of its leasehold development and therefore accelerating the creation of present value from its vast inventory of undeveloped properties.

As an extension of this strategy, Chesapeake recently agreed to acquire and has now commenced a cash tender offer to purchase all of the outstanding shares of Bronco Drilling Company, Inc. (NASDAQ: BRNC) for $315 million, or $11 a share. The cash tender offer will expire on May 23, 2011. The acquisition includes 22 high-quality drilling rigs primarily operating in the Williston and Anadarko basins and has support from Bronco’s two largest shareholders, who collectively own 32% of Bronco’s stock.

Based on projected levels of Chesapeake’s oilfield service company unconsolidated cash flow from operations of approximately $1.0 billion in 2012, Chesapeake believes that the combined value of its oilfield service company assets, including the value of its investment in Frac Tech, is worth approximately $7.0 billion. The company is in the process of evaluating various alternatives to partially monetize its oilfield service assets and expects to achieve such a monetization in 2012.

Conference Call Information

A conference call to discuss this release has been scheduled for Tuesday, May 3, 2011, at 9:00 a.m. EDT. The telephone number to access the conference call is 913-981-5539 or toll-free 888-820-9417. The passcode for the call is 8789033. We encourage those who would like to participate in the call to dial the access number between 8:50 and 9:00 a.m. EDT. For those unable to participate in the conference call, a replay will be available for audio playback from 1:00 p.m. EDT on Tuesday, May 3, 2011 through midnight EDT on Tuesday, May 17, 2011. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 8789033. 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 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, anticipated asset sales, projected cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures of the estimated realized effects of our current hedging positions on future natural gas and oil sales are based upon market prices that 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 our 2010 Form 10-K filed with the U.S. Securities and Exchange Commission on March 1, 2011. 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 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; a reduced ability to borrow or raise additional capital as a result of lower natural gas and oil prices; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business; general economic conditions negatively impacting us and our business counterparties; transportation capacity constraints and interruptions that could adversely affect our cash flow; and adverse results in pending or future litigation.

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

The SEC requires natural gas and oil companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of natural gas and oil that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – 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.

The company calculates the standardized measure of future net cash flows of proved reserves only at year end because applicable income tax information on properties, including recently acquired natural gas and oil interests, is not readily available at other times during the year. As a result, the company is not able to reconcile interim period-end PV-10 values to the standardized measure at such dates. The only difference between the two measures is that PV-10 is calculated before considering the impact of future income tax expenses, while the standardized measure includes such effects. Year-end standardized measure calculations are provided in the financial statement notes in our annual reports on Form 10-K.

Chesapeake Energy Corporation 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, Mississippian, Bone Spring, Avalon, Wolfcamp, Wolfberry, Eagle Ford, Niobrara, Three Forks/Bakken and Utica unconventional liquids plays. The company has also vertically integrated its operations and owns substantial midstream, compression, drilling and oilfield service assets. Chesapeake’s stock is listed on the New York Stock Exchange under the symbol CHK. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and press releases.

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions, except per-share and unit data) (unaudited)
THREE MONTHS ENDED:		March 31,									March 31,
		2011									2010
		$				$/mcfe					$				$/mcfe
REVENUES:
Natural gas and oil sales			494				1.77					1,898				8.16
Marketing, gathering and compression sales			1,017				3.64					844				3.62
Service operations revenue			101				0.36					56				0.24
Total Revenues			1,612				5.77					2,798				12.02
OPERATING COSTS:
Production expenses			238				0.85					207				0.89
Production taxes			45				0.16					48				0.21
General and administrative expenses			130				0.46					109				0.47
Marketing, gathering and compression expenses			985				3.53					815				3.50
Service operations expense			77				0.28					49				0.21
Natural gas and oil depreciation, depletion and amortization			358				1.28					308				1.32
Depreciation and amortization of other assets			68				0.24					50				0.21
Gains on sales of other property and equipment			(5	)			(0.02	)				—				—
Total Operating Costs			1,896				6.78					1,586				6.81
INCOME (LOSS) FROM OPERATIONS			(284	)			(1.01	)				1,212				5.21
OTHER INCOME (EXPENSE):
Interest expense			(7	)			(0.03	)				(25	)			(0.11	)
Earnings from equity investees			25				0.09					13				0.06
Losses on redemptions or exchanges of debt			(2	)			(0.01	)				(2	)			(0.01	)
Other income			2				0.01					2				0.01
Total Other Income (Expense)			18				0.06					(12	)			(0.05	)
INCOME (LOSS) BEFORE INCOME TAXES			(266	)			(0.95	)				1,200				5.16
INCOME TAX EXPENSE (BENEFIT):
Current income taxes			6				0.02					—				—
Deferred income taxes			(110	)			(0.39	)				462				1.99
Total Income Tax Expense (Benefit)			(104	)			(0.37	)				462				1.99
NET INCOME (LOSS)			(162	)			(0.58	)				738				3.17
Preferred stock dividends			(43	)			(0.15	)				(6	)			(0.02	)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS			(205	)			(0.73	)				732				3.15
EARNINGS (LOSS) PER COMMON SHARE:
Basic		$	(0.32	)							$	1.17
Diluted		$	(0.32	)							$	1.14
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in millions)
Basic			634									630
Diluted			634									647

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS ($ in millions) (unaudited)
		March 31,				December 31,
		2011				2010
Cash and cash equivalents		$	849			$	102
Other current assets			2,695				3,164
Total Current Assets			3,544				3,266
Property and equipment (net)			29,709				32,378
Other assets			1,547				1,535
Total Assets		$	34,800			$	37,179
Current liabilities		$	4,669			$	4,490
Long-term debt, net of discounts (a)			9,915				12,640
Asset retirement obligations			302				301
Other long-term liabilities			2,804				2,100
Deferred tax liability			2,115				2,384
Total Liabilities			19,805				21,915
Stockholders’ Equity			14,995				15,264
Total Liabilities & Stockholders' Equity		$	34,800			$	37,179
Common Shares Outstanding (in millions)			658				654

CHESAPEAKE ENERGY CORPORATION CAPITALIZATION ($ in millions) (unaudited)
		March 31,				% of Total Book				December 31,				% of Total Book
		2011				Capitalization				2010				Capitalization
Total debt, net of cash(a)		$	9,066			38	%			$	12,538			45	%
Stockholders' equity			14,995			62	%				15,264			55	%
Total		$	24,061			100	%			$	27,802			100	%

(a)		At March 31, 2011, the company had no outstanding borrowings under its $4.0 billion corporate revolving bank credit facility and $300 million midstream revolving bank credit facility. At March 31, 2011, the company had $4.287 billion of borrowing capacity under these two revolving bank credit facilities.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF 2011 FIRST QUARTER ADDITIONS TO NATURAL GAS AND OIL PROPERTIES BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT MARCH 31, 2011 ($ in millions, except per-unit data) (unaudited)
		Proved Reserves
		Cost					Bcfe(a)				$/Mcfe
Drilling and completion costs(b)		$	1,664				1,334	(c)			1.25
Acquisition of proved properties			18				17				1.06
Sale of proved properties			(1,774	)			(2,536	)			0.70
Drilling and completion costs, net of proved property divestitures			(92	)			(1,185	)			0.08
Revisions – price			—				(33	)			—
Acquisition of unproved properties			883				—				—
Sale of unproved properties			(3,335	)			—				—
Net unproved properties acquisition			(2,452	)			—				—
Capitalized interest on unproved properties			203				—				—
Geological and geophysical costs			66				—				—
Capitalized interest and geological and geophysical costs			269				—				—
Subtotal			(2,275	)			(1,218	)			1.87
Asset retirement obligations and other			(3	)			—				—
Total costs		$	(2,278	)			(1,218	)			1.87

CHESAPEAKE ENERGY CORPORATION ROLL-FORWARD OF PROVED RESERVES THREE MONTHS ENDED MARCH 31, 2011 BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT MARCH 31, 2011 (unaudited)
					Bcfe(a)
Beginning balance, 01/01/11						17,096
Production						(280	)
Acquisitions						17
Divestitures						(2,536	)
Revisions – changes to previous estimates						322
Revisions – price						(33	)
Extensions and discoveries						1,012
Ending balance, 03/31/11						15,598
Proved reserves growth rate						(9	)%
Proved developed reserves						8,601
Proved developed reserves percentage						55	%
PV10 ($ in billions)(a)						14.3

(a)		Reserve volumes and PV10 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 March 31, 2011, of $4.10 per mcf of natural gas and $83.34 per bbl of oil, before field differential adjustments.
(b)		Net of drilling and completion carries of $527 million associated with the Statoil, Total, CNOOC-Eagle Ford and CNOOC-Niobrara industry participation agreements.
(c)		Includes 322 bcfe of positive revisions resulting from changes to previous estimates and excludes downward revisions of 33 bcfe resulting from lower natural gas prices using the average first-day-of-the-month price for the twelve months ended March 31, 2011, compared to the twelve months ended December 31, 2010.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF 2011 FIRST QUARTER ADDITIONS TO NATURAL GAS AND OIL PROPERTIES BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT MARCH 31, 2011 ($ in millions, except per-unit data) (unaudited)
		Proved Reserves
		Cost					Bcfe(a)					$/Mcfe
Drilling and completion costs(b)		$	1,664				1,429	(c)				1.16
Acquisition of proved properties			18				17					1.06
Sale of proved properties			(1,774	)			(2,536	)				0.70
Drilling and completion costs, net of proved property divestitures			(92	)			(1,090	)				0.08
Revisions – price			—				224					—
Acquisition of unproved properties			883				—					—
Sale of unproved properties			(3,335	)			—					—
Net unproved properties acquisition			(2,452	)			—					—
Capitalized interest on unproved properties			203				—					—
Geological and geophysical costs			66				—					—
Capitalized interest and geological and geophysical costs			269				—					—
Subtotal			(2,275	)			(866	)				2.63
Asset retirement obligations and other			(3	)			—					—
Total costs		$	(2,278	)			(866	)				2.63

CHESAPEAKE ENERGY CORPORATION ROLL-FORWARD OF PROVED RESERVES THREE MONTHS ENDED MARCH 31, 2011 BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT MARCH 31, 2011 (unaudited)
					Bcfe(a)
Beginning balance, 01/01/11						17,605
Production						(280	)
Acquisitions						17
Divestitures						(2,536	)
Revisions – changes to previous estimates						333
Revisions – price						224
Extensions and discoveries						1,096
Ending balance, 03/31/11						16,459
Proved reserves growth rate						(7	)%
Proved developed reserves						9,088
Proved developed reserves percentage						55	%
PV10 ($ in billions)(a)						28.1

(a)		Reserve volumes and PV10 value estimated using SEC reserve recognition standards and 10-year average NYMEX strip prices as of March 31, 2011 of $6.17 per mcf of natural gas and $103.13 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 drilling and completion carries of $527 million associated with the Statoil, Total, CNOOC-Eagle Ford and CNOOC-Niobrara industry participation agreements.
(c)		Includes 333 bcfe of positive revisions resulting from changes to previous estimates and excludes positive revisions of 224 bcfe resulting from higher natural gas and oil prices using 10-year average NYMEX strip prices as of March 31, 2011 compared to NYMEX strip prices as of December 31, 2010.

CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA – NATURAL GAS AND OIL SALES AND INTEREST EXPENSE (unaudited)
		March 31,					March 31,
		2011					2010
Natural Gas and Oil Sales ($ in millions):
Natural gas sales		$	788				$	942
Natural gas derivatives – realized gains (losses)			505					379
Natural gas derivatives – unrealized gains (losses)			(549	)				415
Total Natural Gas Sales			744					1,736
Oil sales(a)			400					242
Oil derivatives – realized gains (losses)			(17	)				20
Oil derivatives – unrealized gains (losses)			(633	)				(100	)
Total Oil Sales			(250	)				162
Total Natural Gas and Oil Sales		$	494				$	1,898
Average Sales Price – excluding gains (losses) on derivatives:
Natural gas ($ per mcf)		$	3.24				$	4.50
Oil ($ per bbl)		$	66.08				$	62.59
Natural gas equivalent ($ per mcfe)		$	4.25				$	5.09
Average Sales Price – excluding unrealized gains (losses) on derivatives:
Natural gas ($ per mcf)		$	5.31				$	6.31
Oil ($ per bbl)		$	63.20				$	67.70
Natural gas equivalent ($ per mcfe)		$	5.99				$	6.80
Interest Expense ($ in millions):
Interest(b)		$	8				$	55
Derivatives – realized (gains) losses			(7	)				(3	)
Derivatives – unrealized (gains) losses			6					(27	)
Total Interest Expense (Income)		$	7				$	25

(a)		Includes NGLs.
(b)		Net of amounts capitalized.

CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED CASH FLOW DATA ($ in millions) (unaudited)
THREE MONTHS ENDED:		March 31,					March 31,
		2011					2010
Beginning cash		$	102				$	307
Cash provided by operating activities		$	741				$	1,183
Cash provided by (used in) investing activities:
Exploration and development of natural gas and oil properties		$	(1,692	)			$	(1,020	)
Acquisitions of natural gas and oil proved and unproved properties			(1,281	)				(1,030	)
Divestitures of proved and unproved properties			5,182					1,224
Other property and equipment, net			(3	)				(223	)
Other			(3	)				35
Total cash provided by (used in) investing activities		$	2,203				$	(1,014	)
Cash provided by (used in) financing activities		$	(2,197	)			$	40
Ending cash		$	849				$	516

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF OPERATING CASH FLOW AND EBITDA ($ in millions) (unaudited)
THREE MONTHS ENDED:		March 31,					December 31,					March 31,
		2011					2010					2010
CASH PROVIDED BY OPERATING ACTIVITIES		$	741				$	1,145				$	1,183
Changes in assets and liabilities			663					225					78
OPERATING CASH FLOW(a)		$	1,404				$	1,370				$	1,261
THREE MONTHS ENDED:		March 31,					December 31,					March 31,
		2011					2010					2010
NET INCOME (LOSS)		$	(162	)			$	223				$	738
Income tax expense (benefit)			(104	)				140					462
Interest expense			7					7					25
Depreciation and amortization of other assets			68					61					50
Natural gas and oil depreciation, depletion and amortization			358					368					308
EBITDA (b)		$	167				$	799				$	1,583
THREE MONTHS ENDED:		March 31,					December 31,					March 31,
		2011					2010					2010
CASH PROVIDED BY OPERATING ACTIVITIES		$	741				$	1,145				$	1,183
Changes in assets and liabilities			663					225					78
Interest expense			7					7					25
Unrealized gains (losses) on natural gas and oil derivatives			(1,182	)				(628	)				315
Gains on sales of other property and equipment			5					154					—
Gains (losses) on equity investments			5					(13	)				13
Stock-based compensation			(40	)				(36	)				(32	)
Other items			(32	)				(55	)				1
EBITDA(b)		$	167				$	799				$	1,583

(a)		Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity.
(b)		Ebitda represents net income (loss) before income tax expense, interest expense and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED EBITDA ($ in millions) (unaudited)
		March 31,					December 31,					March 31,
THREE MONTHS ENDED:		2011					2010					2010
EBITDA		$	167				$	799				$	1,583
Adjustments:
Unrealized (gains) losses on natural gas and oil derivatives			1,182					628					(315	)
(Gains) losses on sales of other property and equipment			(5	)				(154	)				—
Other impairments			—					1					—
Losses on redemptions or exchanges of debt			2					—					2
Adjusted EBITDA(a)		$	1,346				$	1,274				$	1,270

(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)
		March 31,					December 31,					March 31,
THREE MONTHS ENDED:		2011					2010					2010
Net income available to common stockholders		$	(205	)			$	180				$	732
Adjustments:
Unrealized (gains) losses on derivatives, net of tax			725					392					(209	)
(Gain) losses on sales of other property and equipment, net of tax			(3	)				(95	)				—
Other impairments, net of tax			—					1					—
Losses on redemptions or exchanges of debt, net of tax			1					—					1
Adjusted net income available to common stockholders (a)			518					478					524
Preferred stock dividends			43					43					6
Total adjusted net income		$	561				$	521				$	530
Weighted average fully diluted shares outstanding(b)			750					746					647
Adjusted earnings per share assuming dilution(a)		$	0.75				$	0.70				$	0.82

(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 MAY 2, 2011

Years Ending December 31, 2011 and 2012

Our policy is to periodically provide guidance on certain factors that affect our future financial performance. As of May 2, 2011, we are using the following key assumptions in our projections for 2011 and 2012.

The primary changes from our February 22, 2011 Outlook are in italicized bold and are explained as follows:
1) Projected effects of changes in our hedging positions have been updated;
2) Our NYMEX oil price assumptions for gathering/marketing/transportation differentials have been updated;
3) Certain cost assumptions have been updated; and
4) Our cash flow projections have been updated, including increased drilling and completion costs.
Note: Projected production volumes have incorporated the loss of production volumes from the closed divestiture of the Fayetteville assets and the anticipated closing of VPP #9 in the 2011 second quarter.

		Year Ending 12/31/2011						Year Ending 12/31/2012
Estimated Production:
Natural gas – bcf		900 – 930						960 – 1,000
Oil – mbbls		32,000 – 36,000						51,000 – 57,000
Natural gas equivalent – bcfe		1,092 – 1,146						1,266 – 1,342
Daily natural gas equivalent midpoint – mmcfe		3,065						3,560
Year over year (YOY) estimated production increase		6 – 11%						13 - 20%
YOY estimated production increase excluding asset sales		17 – 22%						17 - 24%
NYMEX Price(a) (for calculation of realized hedging effects only):
Natural gas - $/mcf		$4.38						$5.50
Oil - $/bbl		$98.53						$100.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf		$1.60						$0.10
Oil - $/bbl		$(2.31)						$(4.20)
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
Natural gas - $/mcf		$0.90 – $1.10						$0.90 – $1.10
Oil - $/bbl(b)		$30.00 – $35.00						$30.00 – $35.00
Operating Costs per Mcfe of Projected Production:
Production expense		$0.90 – 1.00						$0.90 – 1.00
Production taxes (~ 5% of O&G revenues)		$0.25 – 0.30						$0.25 – 0.30
General and administrative(c)		$0.34 – 0.39						$0.34 – 0.39
Stock-based compensation (non-cash)		$0.07 – 0.09						$0.07 – 0.09
DD&A of natural gas and oil assets		$1.15 – 1.30						$1.15 – 1.30
Depreciation of other assets		$0.20 – 0.25						$0.20 – 0.25
Interest expense(d)		$0.05 – 0.10						$0.05 – 0.10
Other Income per Mcfe:
Marketing, gathering and compression net margin		$0.09 – 0.11						$0.09 – 0.11
Service operations net margin		$0.06 – 0.08						$0.08 – 0.10
Other income (including equity investments)		$0.06 – 0.08						$0.06 – 0.08
Book Tax Rate		39%						39%
Equivalent Shares Outstanding (in millions):
Basic		640 – 645						647 – 652
Diluted		750 – 755						760 – 765
Operating cash flow before changes in assets and liabilities(e)(f)		$5,000 – 5,100						$5,500 – 6,200
Drilling and completion costs, net of joint venture carries		($5,500 – 6,000)						($5,500 – 6,000)

Note: please refer to footnotes on following page
(a)		NYMEX natural gas prices have been updated for actual contract prices through April 2011 and NYMEX oil prices have been updated for actual contract prices through March 2011.
(b)		Differentials include effects of natural gas liquids.
(c)		Excludes expenses associated with noncash stock compensation.
(d)		Does not include gains or losses on interest rate derivatives.
(e)		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.
(f)		Assumes NYMEX prices of $4.00 to $5.00 per mcf and $100.00 per bbl in 2011 and $5.00 to $6.00 per mcf and $100.00 per bbl in 2012.

Commodity Hedging Activities

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

1)		Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.
2)		Call options: Chesapeake sells call options in exchange for a premium from the counterparty. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess and if the market price settles below the fixed price of the call option, no payment is due from either party.
3)		Put options: Chesapeake receives a premium from the counterparty in exchange for the sale of a put option. At the time of settlement, if the market prices falls below the fixed price of the put option, Chesapeake pays the counterparty such shortfall, and if the market price settles above the fixed price of the put option, no payment is due from either party.
4)		Knockout swaps: Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain pre-determined knockout prices.
5)		Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. For non-Appalachian Basin basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

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

Commodity markets are volatile, and as a result, Chesapeake’s hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction. Since the latter half of 2009 through May 2, 2011, the company has taken advantage of attractive strip prices in 2012 through 2017 and sold natural gas and oil call options to its counterparties in exchange for 2010, 2011 and 2012 natural gas swaps with strike prices above the then current market price. This effectively allowed the company to sell out-year volatility through call options at terms acceptable to Chesapeake in exchange for straight natural gas swaps with strike prices in excess of the market price for natural gas at that time.

Chesapeake enters into natural gas and oil derivative transactions in order to mitigate a portion of its exposure to adverse market changes in natural gas and oil prices. Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to natural gas and oil sales. All realized gains and losses from natural gas and oil derivatives are included in natural gas and oil sales in the month of related production. In accordance with generally accepted accounting principles, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in accumulated other comprehensive income until the hedged item is recognized in earnings as the physical transactions being hedged occur. Any change in fair value resulting from ineffectiveness is currently recognized in natural gas and oil sales as unrealized gains (losses). Realized gains (losses) are comprised of settled trades related to the production periods being reported. Unrealized gains (losses) are comprised of both temporary fluctuations in the mark-to-market values of non-qualifying trades and settled values of non-qualifying derivatives related to future production periods.

At May 2, 2011, the company has the following open natural gas swaps in place for 2011 and 2012, excluding contracts that will be novated with VPP #9. In addition, the company currently has $593 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 ($millions)				Total Gains (Losses) from Closed Trades and Collected Call Premiums per mcf of Forecasted Natural Gas Production
Q2 2011		203		$	5.20							$	276
Q3 2011		195		$	4.92							$	226
Q4 2011		198		$	4.97							$	185
Total 2011		596		$	5.03		675		88	%		$	687			$	1.02
Total 2012		188		$	6.17		980		19	%		$	(9	)		$	(0.01	)
Total 2013												$	11
Total 2014												$	(38	)
Total 2015												$	(43	)
Total 2016 – 2020												$	(15	)

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
Total 2011		—				—			675			0	%
Total 2012		161			$	6.54			980			16	%
Total 2013		436			$	6.44
Total 2014		330			$	6.43
Total 2015		226			$	6.31
Total 2016 – 2020		324			$	8.13

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		45				$	0.82					49				$	0.14
2012		51				$	0.78					—				$	—
2013 - 2022		29				$	0.69					—				$	—
Totals		125				$	0.77					49				$	0.14

At May 2, 2011, the company has the following open crude oil swaps in place for 2011 and 2012, excluding contracts that will be novated with VPP #9. In addition, the company has $4 million of net hedging losses 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 Oil Production (mbbls)			Open Swap Positions as a % of Forecasted Oil Production			Total Gains (Losses) from Closed Trades and Collected Call Premiums ($millions)			Total Gains from Closed Trades and Collected Call Premiums per bbl of Forecasted Oil Production
Q2 2011		1638			$	102.96			—			—			$	13
Q3 2011		1656			$	102.96			—			—			$	13
Q4 2011		1656			$	102.96			—			—			$	13
Total 2011(a)		4,950			$	102.96			28,000			18	%		$	39		$	1.37
Total 2012(a)		5,490			$	104.78			54,000			10	%		$	51		$	0.94
Total 2013															$	6
Total 2014															$	(198)
Total 2015															$	94
Total 2016 – 2020															$	4

(a)		Certain hedging contracts include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 1 mmbbls in each of 2011 and 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 Oil Production (mbbls)			Call Options as a % of Forecasted Oil Production
Q2 2011		1,820			$	85.44
Q3 2011		1,840			$	87.50
Q4 2011		1,840			$	87.50
Total 2011		5,500			$	86.82			28,000			20	%
Total 2012		22,139			$	87.93			54,000			41	%
Total 2013		14,564			$	87.20
Total 2014		8,707			$	87.72
Total 2015		8,233			$	87.27
Total 2016 – 2017		11,423			$	85.75

SCHEDULE "B”
CHESAPEAKE’S OUTLOOK AS OF FEBRUARY 22, 2011
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF MAY 2, 2011

Years Ending December 31, 2011 and 2012

Our policy is to periodically provide guidance on certain factors that affect our future financial performance. As of February 22, 2011, we are using the following key assumptions in our projections for 2011 and 2012.

The primary changes from our November 3, 2010 Outlook are in italicized bold and are explained as follows:
1) Our production guidance has been updated and reflects anticipated asset sales;
2) Projected effects of changes in our hedging positions have been updated;
3) Our NYMEX natural gas and oil price assumptions for gathering/marketing/transportation differentials have been updated;
4) Certain cost assumptions have been updated; and
5) Our cash flow projections have been updated, including increased drilling and completion costs.

		Year Ending 12/31/2011					Year Ending 12/31/2012
Estimated Production:
Natural gas – bcf		900 – 930					960 – 1,000
Oil – mbbls		32,000 – 36,000					51,000 – 57,000
Natural gas equivalent – bcfe		1,092 – 1,146					1,266 – 1,342
Daily natural gas equivalent midpoint – mmcfe		3,065					3,560
Year over year (YOY) estimated production increase		6 – 11%					13 - 20%
YOY estimated production increase excluding asset sales		17 – 22%					17 - 24%
NYMEX Price(a) (for calculation of realized hedging effects only):
Natural gas - $/mcf		$4.46					$5.50
Oil - $/bbl		$89.96					$90.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf		$1.52					$0.12
Oil - $/bbl		$(0.68)					$(0.40)
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices:
Natural gas - $/mcf		$0.90 – $1.10					$0.90 – $1.10
Oil - $/bbl(b)		$20.00 – $25.00					$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)		$0.25 – 0.30					$0.25 – 0.30
General and administrative(c)		$0.34 – 0.39					$0.34 – 0.39
Stock-based compensation (non-cash)		$0.07 – 0.09					$0.07 – 0.09
DD&A of natural gas and oil assets		$1.15 – 1.30					$1.15 – 1.30
Depreciation of other assets		$0.20 – 0.25					$0.20 – 0.25
Interest expense(d)		$0.05 – 0.10					$0.05 – 0.10
Other Income per Mcfe:
Marketing, gathering and compression net margin		$0.09 – 0.11					$0.09 – 0.11
Service operations net margin		$0.02 – 0.04					$0.02 – 0.04
Other income (including equity investments)		$0.06 – 0.08					$0.06 – 0.08
Book Tax Rate		39%					39%
Equivalent Shares Outstanding (in millions):
Basic		640 – 645					647 – 652
Diluted		750 – 755					760 – 765
Operating cash flow before changes in assets and liabilities(e)(f)		$5,000 – 5,100					$5,600 – 6,400
Drilling and completion costs, net of joint venture carries		($5,000 – 5,400)					($5,400 – 5,800)

Note: please refer to footnotes on following page
(a)		NYMEX natural gas prices have been updated for actual contract prices through February 2011 and NYMEX oil prices have been updated for actual contract prices through January 2011.
(b)		Differentials include effects of natural gas liquids.
(c)		Excludes expenses associated with noncash stock compensation.
(d)		Does not include gains or losses on interest rate derivatives.
(e)		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.
(f)		Assumes NYMEX prices of $4.00 to $5.00 per mcf and $90.00 per bbl in 2011 and $5.00 to $6.00 per mcf and $90.00 per bbl in 2012.

Commodity Hedging Activities

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

1)		Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.
2)		Call options: Chesapeake sells call options in exchange for a premium from the counterparty. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess and if the market price settles below the fixed price of the call option, no payment is due from either party.
3)		Put options: Chesapeake receives a premium from the counterparty in exchange for the sale of a put option. At the time of settlement, if the market prices falls below the fixed price of the put option, Chesapeake pays the counterparty such shortfall, and if the market price settles above the fixed price of the put option, no payment is due from either party.
4)		Knockout swaps: Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain pre-determined knockout prices.
5)		Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. For non-Appalachian Basin basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

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

Commodity markets are volatile, and as a result, Chesapeake’s hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction. Since the latter half of 2009 through February 22, 2011, the company has taken advantage of attractive strip prices in 2012 through 2017 and sold natural gas and oil call options to its counterparties in exchange for 2010, 2011 and 2012 natural gas swaps with strike prices above the then current market price. This effectively allowed the company to sell out-year volatility through call options at terms acceptable to Chesapeake in exchange for straight natural gas swaps with strike prices in excess of the market price for natural gas at that time.

Chesapeake enters into natural gas and oil derivative transactions in order to mitigate a portion of its exposure to adverse market changes in natural gas and oil prices. Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to natural gas and oil sales. All realized gains and losses from natural gas and oil derivatives are included in natural gas and oil sales in the month of related production. In accordance with generally accepted accounting principles, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in accumulated other comprehensive income until the hedged item is recognized in earnings as the physical transactions being hedged occur. Any change in fair value resulting from ineffectiveness is currently recognized in natural gas and oil sales as unrealized gains (losses). Realized gains (losses) are comprised of settled trades related to the production periods being reported. Unrealized gains (losses) are comprised of both temporary fluctuations in the mark-to-market values of non-qualifying trades and settled values of non-qualifying derivatives related to future production periods.

The company currently has the following open natural gas swaps in place for 2011 and 2012. In addition to the open swap positions disclosed below, at February 22, 2011, the company had $687 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 ($millions)			Total Gains (Losses) from Closed Trades and Collected Call Premiums per mcf of Forecasted Natural Gas Production
Q1 2011		226			$	5.72									$	155
Q2 2011		210			$	5.27									$	250
Q3 2011		205			$	5.02									$	200
Q4 2011		205			$	5.02									$	176
Total 2011		846			$	5.27			915			92	%		$	781		$	0.85
Total 2012		206			$	6.20			980			21	%		$	(9)		$	(0.01)
Total 2013															$	11
Total 2014															$	(38)
Total 2015															$	(43)
Total 2016 – 2020															$	(15)

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
Total 2011		—				—			915			0	%
Total 2012		161			$	6.54			980			16	%
Total 2013		436			$	6.44
Total 2014		330			$	6.43
Total 2015		226			$	6.31
Total 2016 – 2020		324			$	8.13

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		45				$	0.82					49				$	0.14
2012		51				$	0.78					—				$	—
2013 - 2022		29				$	0.69					—				$	—
Totals		125				$	0.77					49				$	0.14

The company has the following crude oil swaps in place for 2011 and 2012. In addition to the open swap positions disclosed below, at February 22, 2011, the company had $8 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 Oil Production (mbbls)			Open Swap Positions as a % of Forecasted Oil Production			Total Gains (Losses) from Closed Trades and Collected Call Premiums ($millions)			Total Gains from Closed Trades and Collected Call Premiums per bbl of Forecasted Oil Production
Q1 2011		450			$	99.39			—			—			$	12
Q2 2011		455			$	99.39			—			—			$	13
Q3 2011		460			$	99.39			—			—			$	13
Q4 2011		460			$	99.39			—			—			$	13
Total 2011(a)		1,825			$	99.39			34,000			5	%		$	51		$	1.49
Total 2012(a)		732			$	109.50			54,000			1	%		$	51		$	0.94
Total 2013															$	6
Total 2014															$	(198)
Total 2015															$	94
Total 2016 – 2020															$	4

(a)		Certain hedging contracts include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 1 mmbbls in each of 2011 and 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 Oil Production (mbbls)			Call Options as a % of Forecasted Oil Production
Q1 2011		1,800			$	81.25
Q2 2011		1,820			$	81.25
Q3 2011		1,840			$	81.25
Q4 2011		1,840			$	81.25
Total 2011		7,300			$	81.25			34,000			21	%
Total 2012		22,139			$	87.93			54,000			41	%
Total 2013		14,564			$	87.20
Total 2014		8,707			$	87.72
Total 2015		7,411			$	85.31
Total 2016 – 2017		10,600			$	84.25