8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): July 16, 2008

CHESAPEAKE ENERGY CORPORATION

(Exact name of Registrant as specified in its Charter)

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

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

(405) 848-8000

(Registrant’s telephone number, including area code)

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

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

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

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

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

Section 7 – Regulation FD

Item 7.01 Regulation FD Disclosure.

We have updated our Outlook as of July 16, 2008 to reflect changes in our production guidance, capital expenditure assumptions and cash flow sources and to update shares outstanding for both our offering of 28.75 million shares of common stock which closed on July 15, 2008 and for the effects of certain of our contingent convertible senior notes.  In conjunction with the filing of this Current Report on Form 8-K, we have also updated the Outlook on our website at www.chk.com.

Section 9 – Financial Statements and Exhibits

Item 9.01 Financial Statements and Exhibits

(d)   Exhibits

Exhibit No.	Document Description
99.1	Chesapeake Energy Corporation Outlook as of July 16, 2008

SIGNATURE

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

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

Date:                    July 16, 2008

EXHIBIT INDEX

Exhibit No.	Document Description
99.1	Chesapeake Energy Corporation Outlook as of July 16, 2008

EX-99.1

Exhibit 99.1

CHESAPEAKE’S OUTLOOK AS OF JULY 16, 2008

Years Ending December 31, 2008, 2009 and 2010.

We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance.  As of July 16, 2008, we are using the following key assumptions in our projections for the full years 2008, 2009 and 2010.

The primary changes from our May 1, 2008 Outlook are in italicized bold and are explained as follows:

 1)  Production guidance has been updated for full years 2009 and 2010;

 2)  Certain budgeted capital expenditure assumptions and cash flow sources have been updated; and

 3)  Shares outstanding have been updated to reflect our recent common stock offering and to incorporate the effects

      of certain contingent convertible senior notes.

The company will provide its traditional full hedging update disclosure with its 2008 2nd quarter earnings release.

	Year Ending 12/31/2008	Year Ending 12/31/2009	Year Ending 12/31/2010
Estimated Production(a)
Natural gas – bcf	791 – 801	943 – 963	1,122 – 1,162
Oil – mbbls	11,000	12,000	13,000
Natural gas equivalent – bcfe	857 – 867	1,015 – 1,035	1,200 –1,240
Daily natural gas equivalent midpoint – mmcfe	2,360	2,810	3,340
Year-over-year production increase	21%	19%	19%
NYMEX Prices (b) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$8.14	$8.00	$8.00
Oil - $/bbl	$84.48	$80.00	$80.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$1.17	$0.93	$0.40
Oil - $/bbl	$(7.47)	$1.78	$4.34
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	10 – 14%	10 – 14%	10 – 14%
Oil - $/bbl	7 – 9%	7 – 9%	7 – 9%
Operating Costs per Mcfe of Projected Production:
Production expense	$0.95 – 1.05	$1.00 – 1.10	$1.05 – 1.15
Production taxes (~ 5% of O&G revenues) (c)	$0.35 – 0.40	$0.35 – 0.40	$0.35 – 0.40
General and administrative(d)	$0.33 – 0.37	$0.33 – 0.37	$0.33 – 0.37
Stock-based compensation (non-cash)	$0.10 – 0.12	$0.10 – 0.12	$0.10 – 0.12
DD&A of natural gas and oil assets	$2.50 – 2.70	$2.50 – 2.70	$2.50 – 2.70
Depreciation of other assets	$0.20 – 0.24	$0.20 – 0.24	$0.20 – 0.24
Interest expense(e)	$0.50 – 0.55	$0.50 – 0.55	$0.50 – 0.55
Other Income per Mcfe:
Natural gas and oil marketing income	$0.09 – 0.11	$0.09 – 0.11	$0.09 – 0.11
Service operations income	$0.04 – 0.06	$0.04 – 0.06	$0.04 – 0.06
Book Tax Rate	38.5%	38.5%	38.5%
Equivalent Shares Outstanding – in millions:
Basic	530	563	574
Diluted	566	601	609

Cash Flow Projections – in millions	Year Ending 12/31/2008	Year Ending 12/31/2009	Year Ending 12/31/2010
Inflows:
Operating cash flow before changes in assets and   liabilities(f)	$5,500 – 5,600	$6,800 – 7,200	$8,300 – 9,500
Sale of leasehold and producing properties(a)	$8,000 – 8,500	$3,000 – 4,000	$3,000 – 4,000
Debt and equity offerings	$4,600	-	-
Proceeds from investments and other	$500	$600	$700
Total Cash Inflows	$18,600 – 19,200	$10,400 – 11,800	$12,000 – 14,200
Outflows:
Drilling	($5,500 – 6,000)	($6,000 – 6,500)	($6,300 – 6,800)
Acquisition of leasehold and producing properties	($7,000 – 8,000)	($2,000 – 2,300)	($2,000 – 2,300)
Geophysical costs	($300)	($300)	($300)
Midstream, compression and other PP&E	($1,700 – 2,300)	($1,000 – 1,300)	($1,000 – 1,300)
Dividends, Sr. Notes redemption, capitalized   interest, etc.	($1,100)	($600)	($600)
Total Cash Outflows	($15,600 – 17,700)	($9,900 – 11,000)	($10,200 – 11,300)
Net Cash Change	$900 – $3,600	($600) – $1,900	$700 – $4,000

(a)   The 2008 forecast reflects both completed and anticipated sales by the company of: 1) producing properties for $625 million in the 2008 second quarter in a volumetric production payment (VPP) transaction; 2) Haynesville undeveloped leasehold for $1.650 billion in the 2008 third quarter; 3) Arkoma Basin properties for $1.50 - 1.75 billion in the 2008 third quarter; and 4) undeveloped leasehold or producing properties for $3.5 - 4.5 billion in the 2008 second half.  The 2009 and 2010 forecasts assume that the company sells undeveloped leasehold or producing properties for $3.0-4.0 billion in each year.

(b)   NYMEX oil prices have been updated for actual contract prices through March 2008 and NYMEX natural gas prices have been updated for actual contract prices through April 2008.

(c)   Severance tax per mcfe is based on NYMEX prices of $84.48 per bbl of oil and $7.60 to $8.90 per mcf of natural gas during 2008; and $80.00 per bbl of oil and $7.80 to $9.10 per mcf of natural gas during 2009 and 2010.

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

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

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

 CHESAPEAKE’S PREVIOUS OUTLOOK AS OF MAY 1, 2008

(PROVIDED FOR REFERENCE ONLY)

THE OPERATIONS AND CAPITAL EXPENDITURE GUIDANCE BELOW IS NOW

SUPERSEDED BY OUTLOOK AS OF JULY 16, 2008.

Quarter Ending June 30, 2008 and Years Ending December 31, 2008, 2009 and 2010

We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance.  As of May 1, 2008, we are using the following key assumptions in our projections for the second quarter of 2008 and the full years 2008, 2009 and 2010.

The primary changes from our March 31, 2008 Outlook are in italicized bold and are explained as follows:

1)   Our first guidance for the 2008 second quarter and the full year 2010 has been provided;

2)   Production guidance has been updated for full years 2008 and 2009;

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

4)   Certain cost assumptions and budgeted capital expenditure assumptions have been updated; and

5)   Shares outstanding have been updated to reflect the exercise of the over-allotment option in our recent common stock offering and to incorporate the effects of our contingently convertible notes.

	Quarter Ending 6/30/2008	Year Ending 12/31/2008	Year Ending 12/31/2009	Year Ending 12/31/2010
Estimated Production(a)
Natural gas – bcf	190 – 192	791 – 801	918 – 938	1,052 – 1,092
Oil – mbbls	2,700	11,000	12,000	13,000
Natural gas equivalent – bcfe	206 – 208	857 – 867	990 – 1,010	1,130 –1,170
Daily natural gas equivalent midpoint – mmcfe	2,275	2,360	2,740	3,150
Year-over-year production increase	22%	21%	16%	15%
NYMEX Prices (b) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$8.53	$8.14	$8.00	$8.00
Oil - $/bbl	$80.00	$84.48	$80.00	$80.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$0.50	$1.17	$0.93	$0.40
Oil - $/bbl	$(4.66)	$(7.47)	$1.78	$4.34
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	10 – 14%	10 – 14%	10 – 14%	10 – 14%
Oil - $/bbl	7 – 9%	7 – 9%	7 – 9%	7 – 9%
Operating Costs per Mcfe of Projected Production:
Production expense	$0.95 – 1.05	$0.95 – 1.05	$1.00 – 1.10	$1.05 – 1.15
Production taxes (~ 5% of O&G revenues) (c)	$0.35 – 0.40	$0.35 – 0.40	$0.35 – 0.40	$0.35 – 0.40
General and administrative(d)	$0.33 – 0.37	$0.33 – 0.37	$0.33 – 0.37	$0.33 – 0.37
Stock-based compensation (non-cash)	$0.08 – 0.10	$0.10 – 0.12	$0.10 – 0.12	$0.10 – 0.12
DD&A of natural gas and oil assets	$2.50 – 2.70	$2.50 – 2.70	$2.50 – 2.70	$2.50 – 2.70
Depreciation of other assets	$0.20 – 0.24	$0.20 – 0.24	$0.20 – 0.24	$0.20 – 0.24
Interest expense(e)	$0.50 – 0.55	$0.50 – 0.55	$0.50 – 0.55	$0.50 – 0.55
Other Income per Mcfe:
Natural gas and oil marketing income	$0.09 – 0.11	$0.09 – 0.11	$0.09 – 0.11	$0.09 – 0.11
Service operations income	$0.04 – 0.06	$0.04 – 0.06	$0.04 – 0.06	$0.04 – 0.06
Book Tax Rate	38.5%	38.5%	38.5%	38.5%
Equivalent Shares Outstanding – in millions:
Basic	519	514	529	541
Diluted	556	550	564	572
Budgeted E&P Capital Expenditures, net – in millions:
Drilling	$1,300 – 1,500	$5,500 – 6,000	$5,750 – 6,250	$6,000 – 6,500
Acquisition of leasehold and producing properties	$600 – 800	$2,100 – 2,600	$1,500 – 2,000	$1,500 –2,000
Sale of leasehold and producing properties(a)	$(625)	$(2,975 – 3,225)	$(1,000 – 1,500)	$(1,000 – 1,500)
Geological and geophysical costs	$75	$300	$300	$300
Total budgeted E&P capital expenditures, net	$1,350 – 1,750	$4,925 – $5,675	$6,550 – $7,050	$6,800 – $7,300

(a)   The 2008 and 2009 forecasts assume that the company sells: 1) producing properties for $625 million in the 2008 second quarter in a volumetric production payment (VPP) transaction; 2) Arkoma Basin properties for $1.50 - 1.75 billion in the 2008 third quarter; 3) undeveloped leasehold or producing properties for $600 million in the 2008 second half; and 4) undeveloped leasehold or producing properties for $1.0-1.5 billion in each of 2009 and 2010.

(b)   NYMEX oil prices have been updated for actual contract prices through March 2008 and NYMEX natural gas prices have been updated for actual contract prices through April 2008.

(c)   Severance tax per mcfe is based on NYMEX prices of: $80.00 per bbl of oil and $7.40 to $8.70 per mcf of natural gas during Q2 2008; $84.48 per bbl of oil and $7.60 to $8.90 per mcf of natural gas during calendar 2008; and $80.00 per bbl of oil and $7.80 to $9.10 per mcf of natural gas during calendar 2009 and 2010.

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

(e)   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 natural gas and oil production. These strategies include:

(i)   For swap instruments, Chesapeake receives a fixed price and pays a floating market price 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)   Basis protection swaps are arrangements that guarantee a price differential for oil or natural gas from a specified delivery point.  For Mid-Continent basis protection swaps, which 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 basis protection swaps, which 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.

(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 predetermined knockout prices.

(iv)   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

(v)   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.

(vi)   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.

(vii)   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.

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

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

Following provisions of 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 natural gas and oil 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
Q2 2008	139.4	$8.66	191	73%	$40.2	$0.21
Q3 2008	150.0	$8.97	203	74%	$39.3	$0.19
Q4 2008	142.6	$9.53	214	67%	$50.2	$0.23
Q2-Q4 2008(1)	432.0	$9.05	608	71%	$129.7	$0.21
Total 2009(1)	467.6	$9.44	928	50%	$32.6	$0.04
Total 2010(1)	214.5	$9.56	1,072	20%	$(4.2)	$0.00

(1)   Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $5.45 to $6.50 covering 187 bcf in 2008, 5.45 to $7.25 covering 332 bcf in 2009 and $5.45 to $7.25 covering 172 bcf in 2010.

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
Q2 2008	10.9	$8.27	$9.92	191	6%
Q3 2008	11.0	$8.27	$9.92	203	5%
Q4 2008	9.2	$8.20	$9.91	214	4%
Q2-Q4 2008	31.1	$8.25	$9.92	608	5%
Total 2009(1)	45.7	$8.14	$10.82	928	5%
Total 2010(1)	3.7	$7.30	$12.00	1,072	0%

(1)   Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.50 to $6.00 covering 46 bcf in 2009 and at $6.00 covering 4 bcf in 2010.

Note: Not shown above are written call options covering 128 bcf of production in 2008 at a weighed average price of $10.16 for a weighted average premium of $0.68, 178 bcf of production in 2009 at a weighed average price of $11.29 for a weighted average premium of $0.50 and 161 bcf of production in 2010 at a weighed average price of $10.71 for a weighted average premium of $0.60.

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*:
2008	132.4	0.36	23.0	0.33
2009	91.1	0.33	16.9	0.28
2010	—	—	10.2	0.26
2011	—	—	12.1	0.25
2012	10.7	0.34	—	—
Totals	234.2	$0.35	62.2	$0.29

* 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 ($128 million as of March 31, 2008).  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 natural gas and oil 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 natural gas and oil 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 natural gas and oil 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
Q2 2008	9.6	$4.68	$7.41	($2.73)	191	5%
Q3 2008	9.7	$4.68	$7.41	($2.74)	203	5%
Q4 2008	9.7	$4.66	$7.84	($3.17)	214	5%
Q2-Q4 2008	29.0	$4.67	$7.55	($2.88)	608	5%
Total 2009	18.3	$5.18	$7.28	($2.10)	928	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 Losses from Lifted  Swaps ($ millions)	Total Lifted  Losses per bbl of Estimated Total Oil Production
Q2 2008	1,896	75.58	2,700	70%	$(4.7)	$(1.75)
Q3 2008	2,039	76.92	2,730	75%	$(4.6)	$(1.69)
Q4 2008	1,886	79.01	2,825	67%	$(4.7)	$(1.68)
Q2-Q4 2008(1)	5,821	$77.16	8,255	71%	$(14.0)	$(1.70)
Total 2009(1)	8,395	$82.33	12,000	70%	—	—
Total 2010(1)	4,745	$90.25	13,000	37%	—	—

(1)   Certain hedging arrangements include cap-swaps and knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $45.00 to $65.00 covering 3,423 mbbls in 2008, from $52.50 to $60.00 covering 7,848 mbbls in 2009 and $60.00 covering 4,745 mbbls in 2010.

Note: Not shown above are written call options covering 2,109 mbbls of production in 2008 at a weighted average price of $82.82 for a weighted average premium of $3.17, 2,555 mbbls of production in 2009 at a weighed average price of $82.14 for a weighted average premium of $4.98 and 2,555 mbbls of production in 2010 at a weighed average price of $96.43 for a weighted average premium of $3.79.