a5484417ex99

N e w s R e l e a s e

Chesapeake Energy Corporation

P. O. Box 18496

Oklahoma City, OK 73154

FOR IMMEDIATE RELEASE

SEPTEMBER 4, 2007

CONTACTS:

JEFFREY L. MOBLEY, CFA

SENIOR VICE PRESIDENT –

INVESTOR RELATIONS AND RESEARCH

(405) 767-4763

MARC ROWLAND

EXECUTIVE VICE PRESIDENT

AND CHIEF FINANCIAL OFFICER

(405) 879-9232

CHESAPEAKE ANNOUNCES 2008-2009 FINANCIAL PLAN, PROVIDES INITIAL

2009 PRODUCTION AND BUDGET FORECASTS, INITIATES PROCESS TO

SELL CERTAIN PRODUCING ASSETS AND ANNOUNCES PLAN TO FORM

PRIVATE MLP FOR COMPANY’S MIDSTREAM GAS ASSETS

Company Curtails September 2007 Natural Gas Production and Decreases

Drilling Activity in Response to Lower Natural Gas Prices; However,

Reaffirms Previous Production Guidance for Full-Years 2007 and 2008

OKLAHOMA CITY, OKLAHOMA, SEPTEMBER 4, 2007 – Chesapeake Energy Corporation (NYSE:CHK) today announced an enhanced financial plan for 2008-2009 and its initial production and budget forecasts for 2009. Key elements of the financial plan include taking advantage of the favorable master limited partnership (MLP) and financial markets that exist for low decline-rate producing natural gas assets and for midstream gas assets in order to capture latent balance sheet value and to fully fund its planned capital expenditures.

During the next four months, the company anticipates completing its first two transactions associated with the new plan. For the first transaction, Chesapeake has retained Jefferies Randall & Dewey to assist in selling a non-operated minority interest in certain Chesapeake-operated producing assets in Kentucky and West Virginia representing approximately 145 bcfe of proved reserves and 30 mmcfe net per day of production, or approximately 1.5% of the company’s current proved reserves and net production. Chesapeake believes these assets will be attractive to both the MLP and financial markets due to the low-risk, long reserve-life and low decline-rate profiles of the properties. The company intends to retain drilling rights on the properties below currently producing intervals and outside of existing producing wellbores. Chesapeake expects to receive proceeds of approximately $550 million from the Appalachian asset sale, which is anticipated to close by year-end 2007. Additionally, Chesapeake plans to pursue the sale of four similar packages of mature properties approximately every six months in 2008 and 2009 for further proceeds of approximately $2 billion.

For the second transaction, Chesapeake has retained UBS Investment Bank to assist in forming a private MLP or an alternative financial structure to own a non-operating majority interest in its midstream natural gas assets, which consist primarily of gas gathering systems and processing assets. These assets, which are expected to grow substantially in future years, currently generate annualized cash flow from operating activities of approximately $100 million. The company believes this transaction will be valued in excess of $1 billion.

As a result of these planned transactions during the next nine quarters, Chesapeake believes the MLP and financial markets will allow it to monetize approximately $3.5 billion of assets that, in management's opinion, are not adequately reflected in Chesapeake’s current market valuation.

Chesapeake Elects to Curtail Production and Defer Drilling Activity

in Response to Lower Natural Gas Prices; However, Reaffirms

Previous Production Growth Forecasts for 2007 and 2008 and

Projects Further Production Growth in 2009

In response to currently low natural gas prices, Chesapeake has elected to temporarily reduce its gross daily natural gas production by approximately 200 million cubic feet (mmcf) through a combination of production curtailments and deferred pipeline hook-ups. This production reduction will amount to roughly 125 mmcf per day net to Chesapeake, or about 6% of the company’s current net production, and will be focused in the Fort Worth Barnett Shale, South Texas, Deep Haley and the Anadarko Basin areas where many of the company’s most prolific wells are located. Similar to its voluntary natural gas production curtailments in October 2006, the company plans to continue monitoring the natural gas markets and adjust production rates accordingly as market conditions dictate.

Chesapeake has also elected to reduce its operated drilling rig count from current levels of 155-160 rigs to 140-145 rigs by the end of 2007. This reduction in drilling activity will lower the company’s previously budgeted capital expenditures by approximately 10% in each of 2008 and 2009, or a combined $1 billion.

However, because Chesapeake’s production growth during most of 2007 has exceeded internal projections, the company expects to meet its previously released production guidance of August 2, 2007, which projected an 18-22% production increase for the full-year 2007 and a 14-18% production increase for full-year 2008, despite the asset sales, production curtailments and reduced drilling activity described above. Further, the company’s initial projection for 2009 production growth is 12-16%.

The company’s updated forecasts for 2007, 2008 and 2009 are attached to this release in an Outlook dated September 4, 2007, labeled as Schedule “A,” which begins on page 6. This Outlook has been changed from the Outlook dated August 2, 2007, (attached as Schedule “B,” which begins on page 10) to reflect various updated information.

Management Comments

Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, “Our announcement addresses two important topics in our industry today: low natural gas prices and attractive asset values for sellers of natural gas assets into the MLP and financial markets. First, we believe that current low natural gas prices are temporary and result from a modest oversupply of natural gas in the U.S. This oversupply has largely been caused by two consecutive mild winters in the U.S., increases in imports of liquefied natural gas resulting from an exceptionally warm European winter last season and increased production from domestic producers through higher drilling activity levels.

Chesapeake has been the leading contributor to these domestic natural gas production increases. Over the past year, the U.S. rig count has increased by approximately 70 rigs to around 1,800 rigs while Chesapeake’s operated rig count has increased by approximately 50 rigs, representing about 70% of the nation’s overall increase in drilling activity. As a consequence of Chesapeake’s drilling success, the company’s gross natural gas production has grown by approximately 550 mmcf per day during the past year, accounting for approximately 50% of the total increase in U.S. natural gas production while using only about 9% of the nation’s rigs.

To protect the company’s long-term shareholder value, we believe Chesapeake needs to respond to the current oversupply of natural gas and defer natural gas production and drilling activity until natural gas supply and demand come into better balance. We will continue monitoring the natural gas markets and adjust our production volumes and drilling activity as market conditions dictate.

We would also like to highlight Chesapeake’s proactive approach to revenue management. So far this year, we have realized approximately $630 million in gains from our natural gas hedges and, as of the middle of last week, the mark-to-market gain on our remaining 2007 through 2009 natural gas hedges was approximately $1.5 billion. We have hedged approximately 60% of our 2007 second half natural gas production through swaps at a weighted average price of $8.47 per mcf, approximately 70% of our 2008 natural gas production at an average price of $9.18 per mcf and approximately 27% of our 2009 natural gas production at an average price of $8.98 per mcf. Additionally, we have hedged approximately 12% of our 2007 second half natural gas production through collars at a weighted average floor of $6.94 per mcf, approximately 4% of our 2008 natural gas production at a weighted average floor of $7.41 per mcf and approximately 2% of our 2009 natural gas production at a weighted average floor of $7.50 per mcf. The swap amounts above include certain knockout swaps that may or may not be effective hedges at contract settlement dates depending on future natural gas prices.

Secondly, we are excited to announce our enhanced financial plan for 2008-2009. This plan will enable us to realize approximately $3.5 billion in cash from the MLP and financial markets for assets that we believe are not adequately reflected in the company’s current market valuation. Furthermore, we have lowered our planned total capital expenditures for 2008 and 2009 by approximately $1 billion. In combination with the $3.5 billion in planned asset monetizations, we believe that our shareholders and debtholders will be pleased that Chesapeake will be cash self-sufficient for the foreseeable future and yet can still meet its previously announced production and reserve growth forecasts. Importantly, we believe that by year-end 2009, the company's production will be nearly 40% higher than at June 30, 2007, and its proved reserves will be nearly 30% higher. We believe the market will recognize the substantial value creation potential of this enhanced financial plan”.

Conference Call Information

A conference call to discuss this release has been scheduled for Wednesday morning, September 5, 2007, at 9:00 a.m. EDT. The telephone number to access the conference call is 913-312-1271 and the confirmation code is 1929342. We encourage those who would like to participate in the call to dial the access number between 8:50 and 8:55 a.m. EDT. For those unable to participate in the conference call, a replay will be available for audio playback from noon EDT, September 5, 2007, through midnight EDT on September 19, 2007. The number to access the conference call replay is 719-457-0820 and the passcode for the replay is 1929342. The conference call will also be webcast live on the Internet and can be accessed by going to Chesapeake’s website at www.chkenergy.com and selecting the “News & Events” section. The webcast of the conference call will be available on our website for one year.

This press release and the accompanying Outlooks include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of oil and natural gas reserves, expected oil and natural gas production and future expenses, projections of future oil and natural gas prices, planned capital expenditures for drilling, leasehold acquisitions and seismic data, and statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures concerning the fair value of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.

Factors that could cause actual results to differ materially from expected results are described in “Risks Related to our Business” under “Risk Factors” in the prospectus supplement we filed with the Securities and Exchange Commission on August 9, 2007. These risk factors include the volatility of oil and natural gas prices; the limitations our level of indebtedness may have on our financial flexibility; our ability to compete effectively against strong independent oil and natural gas companies and majors; the availability of capital on an economic basis to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and the amount and timing of development expenditures; uncertainties in evaluating oil and natural gas reserves of acquired properties and associated potential liabilities; our ability to effectively consolidate and integrate acquired properties and operations; unsuccessful exploration and development drilling; declines in the values of our oil and natural gas properties resulting in ceiling test write-downs; lower prices realized on oil and natural gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; the negative impact lower oil and natural gas prices could have on our ability to borrow; drilling and operating risks, including potential environmental liabilities; production interruptions that could adversely affect our cash flow; and pending or future litigation.

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

Chesapeake Energy Corporation is the largest independent producer and third-largest overall producer of natural gas in the United States. Headquartered in Oklahoma City, the company’s operations are focused on exploratory and developmental drilling and corporate and property acquisitions in the Mid-Continent, Fort Worth Barnett Shale, Fayetteville Shale, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast, Ark-La-Tex and Appalachian Basin regions of the United States.

SCHEDULE “A”

CHESAPEAKE’S OUTLOOK AS OF SEPTEMBER 4, 2007

Quarters Ending September 30, 2007 and December 31, 2007; Years Ending December 31, 2007, 2008 and 2009.

We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance. As of September 4, 2007, we are using the following key assumptions in our projections for the third quarter of 2007, the fourth quarter of 2007 and the full-years 2007, 2008 and 2009.

The primary changes from our August 2, 2007 Outlook are in italicized bold and are explained as follows:

1)	We are increasing our prior production guidance for the quarter ending September 30, 2007;

2)	Guidance for the quarter ending December 31, 2007 has been provided for the first time;

3)	Guidance for the year ending December 31, 2009 has been provided for the first time;

4)	Production assumptions have been updated, including assumed assets sales with production losses of 30 mmcf/d in 2007 and 60 mmcf/d in 2008 and 2009;

5)	Certain cost assumptions have been updated;

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

7)	Budgeted capital expenditure assumptions have been updated.

Quarter Ending

9/30/2007

Quarter Ending

12/31/2007

Year Ending

12/31/2007

Year Ending

12/31/2008

Year Ending

12/31/2009

Estimated Production

Oil – mbbls

2,500

9,500

10,800

11,300

Natural gas – bcf

165.5 – 167.5

171.5 – 173.5

632 – 640

729.5 – 739.5

830 – 840

Natural gas equivalent – bcfe

180.5 – 182.5

186.5 – 188.5

688 – 698

794.5 – 804.5

898 – 908

Daily natural gas equivalent midpoint – in mmcfe

1,975

2,040

1,900

2,185

2,475

NYMEX Prices^(a) (for calculation of realized hedging effects only):

Oil - $/bbl

$69.72

$67.50

$65.10

$67.50

Natural gas - $/mcf

$6.17

$7.50

$7.00

$7.50

$7.50

Estimated Realized Hedging Effects (based on assumed NYMEX prices above):

Oil - $/bbl

$2.07

$3.50

$4.64

$4.66

$4.04

Natural gas - $/mcf

$1.81

$1.85

$1.92

$1.53

$0.56

Estimated Differentials to NYMEX Prices:

Oil - $/bbl

7–9%

7–9%

7–9%

7–9%

Natural gas - $/mcf

10–14%

10–14%

10–14%

10–14%

Operating Costs per Mcfe of Projected Production:

Production expense

$0.90 – 1.00

$0.90 – 1.00

$0.90 – 1.00

$0.90 – 1.00

Production taxes (generally 5.5% of O&G revenues)^(b)

$0.35 – 0.40

$0.35 – 0.40

$0.35 – 0.40

$0.35 – 0.40

General and administrative

$0.25 – 0.30

$0.25 – 0.30

$0.25 – 0.30

$0.25 – 0.30

Stock-based compensation (non-cash)

$0.09 – 0.11

$0.08 – 0.10

$0.08 – 0.10

$0.10 – 0.12

$0.10 – 0.12

DD&A of oil and natural gas assets

$2.55 – 2.65

$2.60 – 2.70

$2.50 – 2.70

$2.50 – 2.70

$2.50 – 2.70

Depreciation of other assets

$0.24 – 0.28

$0.20 – 0.25

$0.24 – 0.28

$0.24 – 0.28

Interest expense^(c)

$0.55 – 0.60

$0.55 – 0.60

$0.55 – 0.60

$0.55 – 0.60

Other Income per Mcfe:

Oil and natural gas marketing income

$0.08 – 0.10

$0.08 – 0.10

$0.08 – 0.10

$0.02 – 0.04

Service operations income

$0.06 – 0.08

$0.04 – 0.06

$0.05 – 0.07

Book Tax Rate (≈ 97% deferred)

38%

38%

38%

38%

Equivalent Shares Outstanding – in millions:

Basic

454

454

453

458

463

Diluted

520

520

519

524

529

Budgeted Capital Expenditures – in millions:

Drilling

$1,050 – 1,150

$1,000 – 1,100

$4,250 – 4,450

$4,000 – 4,200

Leasehold acquisition costs

$100 – 200

$100 – 200

$600 – 800

$500 – 600

Geological and geophysical costs

$50 – 75

$50 – 75

$250– 300

$200

Total budgeted capital expenditures

$1,200 – 1,425

$1,150 – 1,375

$5,100 – 5,550

$4,700 – $5,000

(a)	Oil NYMEX prices have been updated for actual contract prices through July 2007 and natural gas NYMEX prices have been updated for actual contract prices through September 2007.

(b)

Severance tax per mcfe is based on NYMEX prices of: $69.72 per bbl of oil and $6.80 to $7.95 per mcf of natural gas during Q3 2007; $67.50 per bbl of oil and $6.85 to $7.95 per mcf of natural gas during Q4 2007;$65.10 per bbl of oil and $6.85 to $8.00 per mcf of natural gas during calendar 2007; and $67.50 per bbl of oil and $6.85 to $8.00 per mcf of natural gas during calendar 2008 and 2009.

(c)	Does not include gains or losses on interest rate derivatives (SFAS 133).

Commodity Hedging Activities

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

(i)	For swap instruments, Chesapeake receives a fixed price and pays a floating market price, as defined in each instrument, to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

(ii)

For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a "cap" limiting the counterparty's exposure. In other words, there is no limit to Chesapeake's exposure but there is a limit to the downside exposure of the counterparty.

(iii)

For 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.

(iv)

For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake.

(v)

Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

(vi)

A three-way collar contract consists of a standard collar contract plus a written put option with a strike price below the floor price of the collar. In addition to the settlement of the collar, the put option requires Chesapeake to make a payment to the counterparty equal to the difference between the put option price and the settlement price if the settlement price for any settlement period is below the put option strike price.

(vii)

Basis protection swaps are arrangements that guarantee a price differential of oil or natural gas from a specified delivery point. 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.

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

Chesapeake enters into oil and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and natural gas prices. Accordingly, associated gains or loses from the derivative transactions are reflected as adjustments to oil and natural gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and natural gas sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., because of temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within oil and natural gas sales.

Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and natural gas sales.

Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas swaps:

Open Swaps

in Bcf’s

Avg. NYMEX

Strike Price

of Open Swaps

Assuming

Natural Gas

Production

in Bcf’s of:

Open Swap

Positions as a

% of Estimated

Total Natural

Gas Production

Total Gains

from Lifted

Swaps

($ millions)

Total Lifted Gain

per Mcf of

Estimated

Total Natural Gas Production

2007:

72.6

$7.87

166.5

44%

$113.8

$0.68

110.9

$8.82

172.5

64%

$116.8

$0.68

Q3-Q4 2007⁽¹⁾

183.5

$8.44

339.0

54%

$230.6

$0.68

Total 2008⁽¹⁾

475.3

$9.27

734.5

65%

$105.0

$0.14

Total 2009⁽¹⁾

208.0

$9.12

835.0

25%

$3.9

$0.01

(1)	Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $5.75 to $6.50 covering 88 bcf in Q3-Q4 2007, $5.25 to $6.50 covering 225 bcf in 2008 and $5.90 to $6.50 covering 152 bcf in 2009.

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

	Open Collars in Bcf’s		Avg. NYMEX Floor Price		Avg. NYMEX Ceiling Price		Assuming Natural Gas Production in Bcf’s of:		Open Collars as a % of Estimated Total Natural Gas Production
2007:
Q3		22.1		$6.76		$8.20		*166.5*		13%
Q4		19.6		$7.13		$8.88		*172.5*		11%
Q3-Q4 2007⁽¹⁾		41.7		$6.94		$8.52		*339.0*		12%

Total 2008⁽¹⁾		26.8		$7.41		$9.40		*734.5*		4%

Total 2009⁽¹⁾		18.3		$7.50		$10.72		*835.0*		2%

(1)	Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 33 bcf in Q3-Q4 2007, $5.00 to $6.00 covering 11 bcf in 2008 and $6.00 covering 18 bcf in 2009.

Note: Not shown above are written call options covering 46 bcf of production in Q3-Q4 2007 at a weighted average price of $10.49 for a weighted average premium of $0.61, 110 bcf of production in 2008 at a weighed average price of $10.41 for a weighted average premium of $0.67 and 119 bcf of production in 2009 at a weighed average price of $11.12 for a weighted average premium of $0.61.

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

	Mid-Continent				Appalachia
	Volume in Bcf’s		NYMEX less*:		Volume in Bcf’s		NYMEX plus*:
Q3-Q4 2007		*74.6*		*0.34*		18.4		0.35
2008		118.6		0.27		43.9		0.35
2009		86.6		0.29		36.5		0.31
2010		—		—		29.2		0.31
2011		—		—		29.2		0.32
2012		10.7		0.34		—		—
Totals		*290.5*		$0.30		157.2		$0.33

* weighted average

We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition in November 2005. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($255 million as of June 30, 2007). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.

Pursuant to SFAS 149 “Amendment of SFAS 133 on Derivative Instruments and Hedging Activities”, the assumed CNR derivative instruments are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows.

The following details the CNR derivatives (natural gas swaps) we have assumed:

	Open Swaps in Bcf’s		Avg. NYMEX Strike Price Of Open Swaps (per Mcf)		Avg. Fair Value Upon Acquisition of Open Swaps (per Mcf)		Initial Liability Acquired (per Mcf)		Assuming Natural Gas Production in Bcf’s of:		Open Swap Positions as a % of Estimated Total Natural Gas Production
2007:
Q3		10.6		$4.82		$8.45		($3.63)		*166.5*		6%
Q4		10.6		$4.82		$8.87		($4.05)		*172.5*		6%
Q3-Q4 2007		21.2		$4.82		$8.66		($3.84)		*339.0*		6%

Total 2008		38.4		$4.68		$8.02		($3.34)		*734.5*		5%

Total 2009		18.3		$5.18		$7.28		($2.10)		*835.0*		2%

Note: Not shown above are collars covering 3.7 bcf of production in 2009 at an average floor and ceiling of $4.50 and $6.00.

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

Open Swaps

in mbbls

Avg. NYMEX

Strike Price

Assuming Oil

Production in

mbbls of:

Open Swap

Positions as a %

of Estimated Total

Oil Production

Total Gains

from Lifted

Swaps

($ millions)

Total Lifted

Gain per bbl

of Estimated

Total Oil

Production

2007:

1,656

$71.61

2,500

66%

$2.1

$0.84

1,656

$71.57

2,500

66%

$2.1

$0.84

Q3-Q4 2007⁽¹⁾

3,312

$71.59

5,000

66%

$4.2

$0.84

Total 2008⁽¹⁾

7,502

$72.77

10,800

69%

$4.8

$0.45

Total 2009⁽¹⁾

3,650

$76.75

11,300

32%

—

(1)	Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $45.00 to $60.00 covering 1,472 mbbls in Q3-Q4 2007 and 3,478 mbbls in 2008 and from $52.50 to $60.00 covering 3,103 mbbls in 2009.

Note: Not shown above are written call options covering 1,282 mbbls of production in 2008 at a weighted average price of $75.00 for a weighted average premium of $4.72 and 2,190 mbbls of production in 2009 at a weighed average price of $75.00 for a weighted average premium of $5.47.

SCHEDULE “B”

CHESAPEAKE’S PREVIOUS OUTLOOK AS OF AUGUST 2, 2007

(PROVIDED FOR REFERENCE ONLY)

NOW SUPERSEDED BY OUTLOOK AS OF SEPTEMBER 4, 2007

Quarter Ending September 30, 2007; Year Ending December 31, 2007; and Year Ending December 31, 2008.

We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of August 2, 2007, we are using the following key assumptions in our projections for the third quarter of 2007, the full-year 2007 and the full-year 2008.

The primary changes from our May 3, 2007 Outlook are in italicized bold in the table and are explained as follows:

1)	We have provided our first guidance for the quarter ending September 30, 2007;

2)	We have updated the projected effect of changes in our hedging positions;

3)	Production and certain cost assumptions have been updated; and

4)	Capital expenditure assumptions have been updated and specific detail has been provided by type of budgeted capital expenditure.

	*Quarter Ending* *9/30/2007*	Year Ending 12/31/2007	Year Ending 12/31/2008
Estimated Production
Oil – mbbls	*2,200*	*9,000*	*9,000*
Natural gas – bcf	*166.5 – 170.5*	*634 – 644*	*740.5 – 750.5*
Natural gas equivalent – bcfe	*179.5 – 183.5*	*688 – 698*	*794.5 – 804.5*
Daily natural gas equivalent midpoint – in mmcfe	*1,975*	*1,900*	*2,185*
NYMEX Prices^(a) (for calculation of realized hedging effects only):
Oil - $/bbl	*$65.00*	*$63.30*	*$65.00*
Natural gas - $/mcf	*$7.31*	*$7.28*	$7.50
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Oil - $/bbl	*$5.85*	*$6.24*	*$6.81*
Natural gas - $/mcf	*$1.42*	*$1.81*	*$1.46*
Estimated Differentials to NYMEX Prices:
Oil - $/bbl	*7 – 9%*	*7 – 9%*	*7 – 9%*
Natural gas - $/mcf	*10 – 14%*	*10 – 14%*	*10 – 14%*
Operating Costs per Mcfe of Projected Production:
Production expense	*$0.90 – 1.00*	$0.90 – 1.00	$0.90 – 1.00
Production taxes (generally *5.5%* of O&G revenues)^(b)	*$0.35 – 0.40*	*$0.35 – 0.40*	*$0.35 – 0.40*
General and administrative	*$0.25 – 0.30*	$0.25 – 0.30	$0.25 – 0.30
Stock-based compensation (non-cash)	*$0.09 – 0.11*	$0.08 – 0.10	$0.10 – 0.12
DD&A of oil and natural gas assets	*$2.55 – 2.65*	$2.40 – 2.60	$2.50 – 2.70
Depreciation of other assets	*$0.24 – 0.28*	$0.24 – 0.28	*$0.24 – 0.28*
Interest expense^(c)	*$0.55 – 0.60*	$0.60 – 0.65	*$0.55 – 0.60*
Other Income per Mcfe:
Oil and natural gas marketing income	*$0.08 – 0.10*	*$0.08 – 0.10*	*$0.08 – 0.10*
Service operations income	*$0.06 – 0.08*	*$0.07 – 0.10*	*$0.07 – 0.10*
Book Tax Rate (≈ 97%* deferred)*	*38%*	38%	38%
Equivalent Shares Outstanding – in millions:
Basic	*454*	453	458
Diluted	*520*	519	524
Budgeted Capital Expenditures – in millions:
Drilling	*$1,050 – 1,150*	*$4,300 – 4,500*	*$4,300 – 4,500*
Leasehold acquisition costs	*$100 – 200*	*$600 – 800*	*$600 – 800*
Geological and geophysical costs	*$50 – 75*	*$200 – 300*	*$200 – 300*
Total budgeted capital expenditures	*$1,200 – 1,425*	*$5,100 – 5,600*	*$5,100 – $5,600*

(a)	Oil NYMEX prices have been updated for actual contract prices through June 2007 and natural gas NYMEX prices have been updated for actual contract prices through July 2007.

(b)

Severance tax per mcfe is based on NYMEX prices of $65.00 per bbl of oil and $6.90 to $8.00 per mcf of natural gas during Q3 2007, $63.30 per bbl of oil and $6.90 to $8.00 per mcf of natural gas during calendar 2007 and $65.00 per bbl of oil and $6.90 to $8.00 per mcf of natural gas during calendar 2008.

(c)	Does not include gains or losses on interest rate derivatives (SFAS 133).

Commodity Hedging Activities

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

(i)	For swap instruments, Chesapeake receives a fixed price and pays a floating market price, as defined in each instrument, to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

(ii)

(iii)

(iv)	For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake.

(v)

(vi)

(vii)

Open Swaps

in Bcf’s

Avg. NYMEX

Strike Price

of Open Swaps

Assuming

Natural Gas

Production

in Bcf’s of:

Open Swap

Positions as a

% of Estimated

Total Natural

Gas Production

Total Gains

from Lifted

Swaps

($ millions)

Total Lifted Gain

per Mcf of

Estimated

Total Natural Gas Production

2007:

85.9

$8.27

168.5

51%

$111.2

$0.66

95.2

$9.01

173.5

55%

$116.8

$0.67

Q3-Q4 2007⁽¹⁾

181.1

$8.66

342.0

53%

$228.0

$0.67

Total 2008⁽¹⁾

441.7

$9.33

745.5

59%

$105.0

$0.14

Total 2009⁽¹⁾

115.9

$9.37

816.0

14%

$3.9

$0.01

(1)	Certain hedging arrangements include knockout swaps with knockout provisions at prices ranging from $5.25 to $6.50 covering 116 bcf in Q3-Q4 2007, $5.75 to $6.50 covering 222 bcf in 2008 and $5.90 to $6.50 covering 116 bcf in 2009.

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

	Open Collars in Bcf’s		Avg. NYMEX Floor Price		Avg. NYMEX Ceiling Price		Assuming Natural Gas Production in Bcf’s of:		Open Collars as a % of Estimated Total Natural Gas Production
2007:
Q3		22.1		$6.76		$8.20		*168.5*		13%
Q4		19.6		$7.13		$8.88		*173.5*		11%
Q3-Q4 2007⁽¹⁾		41.7		$6.94		$8.52		*342.0*		12%

Total 2008⁽¹⁾		26.8		$7.41		$9.40		*745.5*		4%

Total 2009⁽¹⁾		18.3		$7.50		$10.72		*816.0*		2%

(1)	Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 33 bcf in Q3-Q4 2007, $5.00 to $6.00 covering 11 bcf in 2008 and $6.00 covering 18 bcf in 2009.

Note: Not shown above are written call options covering 51 bcf of production in Q3-Q4 2007 at a weighted average price of $9.45 for a weighted average premium of $0.55, 104 bcf of production in 2008 at a weighed average price of $10.39 for a weighted average premium of $0.68 and 72 bcf of production in 2009 at a weighed average price of $11.38 for a weighted average premium of $0.54.

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

	Mid-Continent				Appalachia
	Volume in Bcf’s		NYMEX less*:		Volume in Bcf’s		NYMEX plus*:
Q3-Q4 2007		*78.5*		*0.37*		*18.4*		0.35
2008		118.6		0.27		*43.9*		0.35
2009		86.6		0.29		*36.5*		0.31
2010		—		—		*29.2*		*0.31*
2011		—		—		*29.2*		*0.32*
2012		*10.7*		*0.34*		—		—
Totals		*294.4*		*$0.31*		*157.2*		*$0.33*

* weighted average

The following details the CNR derivatives (natural gas swaps) we have assumed:

	Open Swaps in Bcf’s		Avg. NYMEX Strike Price Of Open Swaps (per Mcf)		Avg. Fair Value Upon Acquisition of Open Swaps (per Mcf)		Initial Liability Acquired (per Mcf)		Assuming Natural Gas Production in Bcf’s of:		Open Swap Positions as a % of Estimated Total Natural Gas Production
2007:
Q3		10.6		$4.82		$8.45		($3.63)		*168.5*		6%
Q4		10.6		$4.82		$8.87		($4.05)		*173.5*		6%
Q3-Q4 2007		21.2		$4.82		$8.66		($3.84)		*342.0*		6%

Total 2008		38.4		$4.68		$8.02		($3.34)		*745.5*		5%

Total 2009		18.3		$5.18		$7.28		($2.10)		*816.0*		2%

Note: Not shown above are collars covering 3.7 bcf of production in 2009 at an average floor and ceiling of $4.50 and $6.00.

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

Open Swaps

in mbbls

Avg. NYMEX

Strike Price

Assuming Oil

Production in mbbls of:

Open Swap Positions as a %

of Estimated Total Oil Production

Total Gains from Lifted Swaps

($ millions)

Total Lifted Gain per bbl of Estimated

Total Oil Production

2007:

1,656

$71.61

2,230

74%

$2.1

$0.95

1,656

$71.57

2,300

72%

$2.1

$0.91

Q3-Q4 2007⁽¹⁾

3,312

$71.59

4,530

73%

$4.2

$0.93

Total 2008⁽¹⁾

6,680

$72.77

9,000

74%

$4.8

$0.54

Total 2009⁽¹⁾

2,920

$77.58

9,000

32%

—

(1)	Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $45.00 to $60.00 covering 1,472 mbbls in Q3-Q4 2007 and 3,112 mbbls in 2008 and from $52.50 to $60.00 covering 2,738 mbbls in 2009.

Note: Not shown above are written call options covering 916 mbbls of production in 2008 at a weighted average price of $75.00 for a weighted average premium of $5.03 and 1,460 mbbls of production in 2009 at a weighed average price of $75.00 for a weighted average premium of $5.96.