Expand Energy (EXE) 8-K Regulation FD Disclosure

SCHEDULE “A”

CHESAPEAKE’S OUTLOOK AS OF OCTOBER 14, 2008

Quarter Ending December 31, 2008 and Years Ending December 31, 2009 and 2010.

We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance.  As of October 14, 2008, we are using the following key assumptions in our projections for the fourth quarter of 2008 and the full years 2009 and 2010.

The primary changes from our September 22, 2008 Outlook are in italicized bold and are explained as follows:

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

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

3)   Our NYMEX oil price assumption for realized hedging effects and estimating future operating cash flow has been reduced; and

4)   Shares outstanding have been updated to remove the effects of certain contingent convertible senior notes that are no longer in the money at current stock price level.

	Quarter Ending 12/31/2008	Year Ending 12/31/2009	Year Ending 12/31/2010
Estimated Production(a)
Natural gas – bcf	197 – 201	893 – 913	1,032 – 1,072
Oil – mbbls	2,825	12,000	13,000
Natural gas equivalent – bcfe	214 – 218	965 – 985	1,110 –1,150
Daily natural gas equivalent midpoint – mmcfe	2,350	2,670	3,095
Year-over-year production increase	5.9%	15.6%	15.9%
NYMEX Prices (b) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$7.82	$8.00	$8.00
Oil - $/bbl	$80.00	$80.00	$80.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$1.48	$1.04	$0.82
Oil - $/bbl	($2.82)	$2.42	$4.79
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	10 – 14%	10 – 14%	10 – 14%
Oil - $/bbl	5 – 7%	5 – 7%	5 – 7%
Operating Costs per Mcfe of Projected Production:
Production expense	$1.00 – 1.10	$1.10 – 1.20	$1.15 – 1.25
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	$2.30 – 2.35	$2.20 – 2.30	$2.15 – 2.25
Depreciation of other assets	$0.20 – 0.24	$0.20 – 0.24	$0.20 – 0.24
Interest expense(e)	$0.30 – 0.35	$0.40 – 0.45	$0.35 – 0.40
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%
Cash Income Taxes – in millions	$350 - 450	$200 – 300	$200 – 300
Equivalent Shares Outstanding – in millions:
Basic	560 – 565	565 - 570	575 - 580
Diluted	580 – 585	585 - 590	595 - 600

Cash Flow Projections – in millions	Quarter Ending 12/31/2008	Year Ending 12/31/2009	Year Ending 12/31/2010
Net inflows:
Operating cash flow before changes in assets and   liabilities(f)(g)	$1,375 – 1,425	$5,800 – 6,000	$6,250 – 6,750
Leasehold and producing property transactions:
Sale of leasehold and producing properties(a)	$2,100 – 2,500	$1,250 – 2,000	$1,250 – 2,000
Sale of producing properties via VPP’s(a)	$400 – 500	$1,000 – 1,250	$1,000 – 1,250
Acquisition of leasehold and producing properties	($750 - $1,000)	($1,250 - $1,750)	($1,000 - $1,500)
Net leasehold and producing property transactions	$1,750 – 2,000	$1,000 – 1,500	$1,250 – 1,750
Debt and equity offerings	–	–	–
Midstream financings	$1,050 – 1,275	$500 – 700	$500 – 700
Proceeds from investments and other	–	$500– 750	$150 – 250
Total Cash Inflows	$4,175 – 4,700	$7,800 – 8,950	$8,150 – 9,450
Net outflows:
Drilling	$1,200 – 1,300	$4,250 – 4,750	$4,750 – 5,250
Geophysical costs	$75	$225 – 275	$225 – 275
Midstream infrastructure and compression	$300 – 325	$1,000 – 1,200	$900 – 1,000
Other PP&E	$50 – 75	$250 – 300	$250 – 300
Dividends, senior notes redemption, capitalized   interest, etc.	$150 – 200	$575 – 600	$575 – 600
Cash income taxes	$350 – 450	$200 – 300	$200 – 300
Total Cash Outflows	$2,125 – 2,425	$6,500  – 7,425	$6,900 – 7,725
Net Cash Change	$2,050 – 2,275	$1,300 –1,525	$1,250 – 1,725

(a)   The 2008 fourth quarter production and cash flow forecasts reflect anticipated sales by the company of: 1) producing properties for approximately $450 million in a volumetric production payment (VPP); and 2) producing properties in South Texas and undeveloped leasehold in the Marcellus Shale and other areas for approximately $2.3 billion.  The 2009 and 2010 production and cash flow forecasts reflect anticipated sales by the company of: 1) producing properties for approximately $1.1 billion in each year in VPP transactions; and 2) undeveloped leasehold or other producing properties for approximately $1.6 billion in each year.

(b)   NYMEX natural gas prices have been updated for actual contract prices through October 2008.

(c)   Severance tax per mcfe is based on NYMEX prices of $80.00 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during Q4 2008; $80.00 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during 2009; and $80.00 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during 2010.

(d)   Excludes expenses associated with noncash 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.

(g)   Assumes NYMEX natural gas of $7.00 to $8.00 per mcf and NYMEX oil prices of $80.00 per bbl.

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 (losses) 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 (Losses) from Lifted Swaps ($ millions)	Total Lifted Gain (Loss) per Mcf of Estimated Total Natural Gas  Production
Q4 2008	110.6	$9.30	199	56%	$79.70	$0.40
Total 2009(1)	533.0	$9.46	903	59%	($36.70)	($0.04)
Total 2010(1)	422.6	$9.58	1,052	40%	$33.90	$0.03

(1)   Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $5.45 to $6.50 covering 35 bcf in 2008, $5.45 to $7.25 covering 356 bcf in 2009 and $5.45 to $7.40 covering 318 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
Q4 2008	26.6	$7.75	$9.32	199	13%
Total 2009(1)	63.9	$8.05	$11.18	903	7%
Total 2010(1)	25.6	$7.71	$11.46	1,052	2%

(1)   Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.50 to $6.00 covering 38 bcf in 2009 and at $6.00 covering 4 bcf in 2010.

The company currently has the following natural gas written call options in place:

	Call Options in Bcf’s	Avg. NYMEX   Call Price	Avg. Premium per mcf	Assuming Natural Gas Production in Bcf’s of:	Call Options as a % of Estimated Total Natural Gas Production
Q4 2008	34.0	$10.39	$0.70	199	17%
Total 2009	225.5	$11.37	$0.61	903	25%
Total 2010	231.8	$10.77	$0.72	1,052	22%

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*:
Q4 2008	32.1	$       0.45	5.8	$    0.33
2009	77.1	0.35	16.9	0.28
2010	—	—	10.2	0.26
2011	45.1	0.64	12.1	0.25
2012	43.2	0.48	—	—
Totals	197.5	$       0.46	45.0	$    0.27

* 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 ($102 million as of June 30, 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
Q4 2008	9.7	$4.66	$7.84	($3.17)	199	5%
Total 2009	18.3	$5.18	$7.28	($2.10)	903	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
Q4 2008(1)	1,702	$77.57	2,825	60%	($4.7)	($1.68)
Total 2009(1)	8,364	$82.38	12,000	70%	($0.6)	($0.05)
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 $60.00 covering 1,104 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 890 mbbls of production in 2008 at a weighted average price of $86.43 for a weighted average premium of $3.63, 3,285 mbbls of production in 2009 at a weighed average price of $122.22 for a weighted average premium of $6.07 and 3,285 mbbls of production in 2010 at a weighed average price of $131.67 for a weighted average premium of $6.94.

SCHEDULE “B”

CHESAPEAKE’S PREVIOUS OUTLOOK AS OF SEPTEMBER 22, 2008

(PROVIDED FOR REFERENCE ONLY)

NOW SUPERSEDED BY OUTLOOK AS OF OCTOBER 14, 2008

Quarters Ending September 30, 2008 and December 31, 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 September 22, 2008, we are using the following key assumptions in our projections for the third and fourth quarters of 2008 and the full years 2008, 2009 and 2010.

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

1)   Our first guidance for the 2008 fourth quarter has been provided;

2)   Projected production volumes have been updated to reflect reduction in rig count and anticipated divestitures;

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)   Our NYMEX natural gas and oil price assumptions for estimating future operating cash flow have been reduced.

	Quarter Ending 9/30/2008	Quarter Ending 12/31/2008	Year Ending 12/31/2008	Year Ending 12/31/2009	Year Ending 12/31/2010
Estimated Production(a)
Natural gas – bcf	196 – 199	197 – 201	777 – 781	893 – 913	1,032 – 1,072
Oil – mbbls	2,825	2,825	11,200	12,000	13,000
Natural gas equivalent – bcfe	213 – 216	214 – 218	844 – 848	965 – 985	1,110 –1,150
Daily natural gas equivalent midpoint – mmcfe	2,330	2,350	2,310	2,670	3,095
Year-over-year production increase	15.0%	5.9%	18.0%	15.6%	15.9%
NYMEX Prices (b) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$10.24	$7.50	$9.18	$8.00	$8.00
Oil - $/bbl	$120.06	$110.00	$112.99	$110.00	$120.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	($0.82)	$1.94	$0.24	$1.04	$0.85
Oil - $/bbl	($39.97)	($28.38)	($32.74)	($44.74)	($28.90)
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	10 – 14%	10 – 14%	10 – 14%	10 – 14%	10 – 14%
Oil - $/bbl	5 – 7%	5 – 7%	5 – 7%	5 – 7%	5 – 7%
Operating Costs per Mcfe of Projected Production:
Production expense	$1.00 – 1.10	$1.00 – 1.10	$1.00 – 1.10	$1.10 – 1.20	$1.15 – 1.25
Production taxes (~ 5% of O&G revenues) (c)	$0.45 – 0.50	$0.35 – 0.40	$0.40 – 0.45	$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	$0.33 – 0.37
Stock-based compensation (non-cash)	$0.10 – 0.12	$0.10 – 0.12	$0.10 – 0.12	$0.10 – 0.12	$0.10 – 0.12
DD&A of natural gas and oil assets	$2.35 – 2.40	$2.30 – 2.35	$2.30 – 2.40	$2.20 – 2.30	$2.15 – 2.25
Depreciation of other assets	$0.20 – 0.24	$0.20 – 0.24	$0.20 – 0.24	$0.20 – 0.24	$0.20 – 0.24
Interest expense(e)	$0.35 – 0.40	$0.30 – 0.35	$0.35 – 0.40	$0.40 – 0.45	$0.35 – 0.40
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	$0.09 – 0.11
Service operations income	$0.04 – 0.06	$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%	38.5%
Cash Income Taxes – in millions	–	$350 - 450	$350 – 450	$200 – 300	$200 – 300
Equivalent Shares Outstanding – in millions:
Basic	553 – 557	560 – 565	530 - 535	565 - 570	575 - 580
Diluted	593 – 598	595 – 600	565 - 570	600 - 605	610 - 615

Cash Flow Projections – in millions	Quarter Ending 9/30/2008	Quarter Ending 12/31/2008	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)(g)	$1,250 – 1,350	$1,350 – 1,450	$5,550 – 5,750	$5,650 – 6,250	$6,500 – 7,100
Sale of leasehold and producing properties(a)	$4,650 – 4,750	$1,650 – 1,850	$6,550 – 6,850	$1,750 – 2,250	$750 – 1,250
Sale of producing properties via VPP’s(a)	$600	$550 – 650	$1,775 – 1,875	$1,100 – 1,300	$1,100 – 1,300
Debt and equity offerings	$1,585	–	$4,730	–	–
Midstream financings	$200 – 250	$650 – 850	$850 – 1,100	$650 – 850	$650 – 850
Proceeds from investments and other	$100 – 150	–	$275 – 325	$775 – 825	$150 – 250
Total Cash Inflows	$8,385 – 8,685	$4,200 – 4,800	$19,730 – 20,630	$9,925 – 11,475	$9,150 – 10,750
Outflows:
Drilling	$1,450 – 1,550	$1,200 – 1,300	$5,500 – 5,700	$4,500 – 5,000	$5,000 – 5,500
Acquisition of leasehold and producing properties	$4,750 – 5,250	$1,000 – 1,500	$8,500 – 9,500	$2,000 – 2,250	$1,250 – 1,750
Geophysical costs	$75	$75	$300	$225 – 275	$225 – 275
Compression and other PP&E	$225 – 250	$100 – 125	$1,000 – 1,050	$500 – 550	$250 – 300
Midstream infrastructure	$275 – 300	$375 – 400	$1,200 – 1,250	$1,350 – 1,500	$750 – 950
Dividends, senior notes redemption, capitalized   interest, etc.	$550 – 600	$150 – 200	$1,150 – 1,250	$575 – 600	$500 – 550
Cash income taxes	–	$350 – 450	$350 – 450	$200 – 300	$200 – $300
Total Cash Outflows	$7,325 – 8,025	$3,250 – 4,050	$18,000 – 19,500	$9,350  – 10,475	$8,175 – 9,625
Net Cash Change	$660 – 1,060	$750 – 950	$1,130 – 1,730	$575 –1,000	$975 – 1,125

(a)   The 2008 production and cash flow forecasts reflect sales completed in the 2008 first half and both completed and anticipated sales by the company of: 1) producing properties for $600 million in the 2008 third quarter and approximately $600 million in the 2008 fourth quarter in two volumetric production payment (VPP) transactions; 2) Haynesville Shale undeveloped leasehold for $1.85 billion to PXP in the 2008 third quarter; 3) Arkoma Basin Woodford Shale properties for $1.75 billion to BP in the 2008 third quarter; 4) Arkoma Basin Fayetteville Shale properties for $1.1 billion to BP in the 2008 third quarter and 5) undeveloped leasehold in the Marcellus Shale and other areas for approximately $1.75 billion in the 2008 fourth quarter.  The 2009 and 2010 production and cash flow forecasts reflect sales by the company of producing properties for approximately $1.2 billion each year in VPP transactions and undeveloped leasehold for approximately $2.0 billion in 2009 and approximately $1.0 billion in 2010.

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

(c)   Severance tax per mcfe is based on NYMEX prices of $120.06 per bbl of oil and $9.50 to $10.50 per mcf of natural gas during Q3 2008; $110.00 per bbl of oil and $7.00 to $8.00 per mcf of natural gas during Q4 2008; $112.99 per bbl of oil and $8.25 to $9.50 per mcf of natural gas during calendar 2008; $110.00 per bbl of oil and $7.00 to $8.50 per mcf of natural gas during 2009; and $120.00 per bbl of oil and $7.00 to $8.50 per mcf of natural gas during 2010.

(d)   Excludes expenses associated with noncash 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.

(g)   Assumes NYMEX natural gas of $7.50 to $8.50 per mcf and NYMEX oil prices of $110.00 per bbl.

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 (losses) 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 (Losses) from Lifted Swaps ($ millions)	Total Lifted Gain (Loss) per Mcf of Estimated Total Natural Gas Production
Q3 2008	154.5	$8.99	198	78%	$38.8	$0.20
Q4 2008	147.5	$9.43	199	74%	$53.4	$0.27
Q3-Q4 2008(1)	302.0	$9.21	397	76%	$92.2	$0.23
Total 2009(1)	570.1	$9.54	903	63%	($135.9)	($0.15)
Total 2010(1)	470.0	$9.70	1,052	45%	($68.9)	($0.07)

(1)   Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $5.45 to $7.50 covering 138 bcf in 2008, $5.45 to $7.50 covering 356 bcf in 2009 and $5.45 to $7.50 covering 318 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
Q3 2008	8.3	$8.17	$10.26	198	4%
Q4 2008	6.5	$8.04	$10.33	199	3%
Q3-Q4 2008	14.8	$8.11	$10.29	397	4%
Total 2009(1)	63.9	$8.05	$11.18	903	7%
Total 2010(1)	25.6	$7.71	$11.46	1,052	2%

(1)   Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.50 to $6.00 covering 38 bcf in 2009 and at $6.00 to $6.50 covering 4 bcf in 2010.

The company currently has the following natural gas written call options in place:

	Call Options in Bcf’s	Avg. NYMEX   Call Price	Avg. Premium per mcf	Assuming Natural Gas Production in Bcf’s of:	Call Options as a % of Estimated Total Natural Gas Production
Q3 2008	25.2	$10.25	$0.86	198	13%
Q4 2008	34.0	$10.39	$0.70	199	17%
Q3-Q4 2008	59.2	$10.32	$0.78	397	15%
Total 2009	225.5	$11.37	$0.61	903	25%
Total 2010	231.8	$10.77	$0.72	1,052	22%

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	65.7	$       0.47	11.6	$    0.33
2009	77.1	0.35	16.9	0.28
2010	—	—	10.2	0.26
2011	32.2	0.68	12.1	0.25
2012	30.4	0.49	—	—
Totals	205.4	$       0.46	50.8	$    0.28

* 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 ($102 million as of June 30, 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 % o f Estimated Total Natural Gas Production
Q3 2008	9.7	$4.68	$7.41	($2.74)	198	5%
Q4 2008	9.7	$4.66	$7.84	($3.17)	199	5%
Q3-Q4 2008	19.4	$4.67	$7.62	($2.95)	397	5%
Total 2009	18.3	$5.18	$7.28	($2.10)	903	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
Q3 2008	1,979	$76.45	2,825	70%	($4.6)	($1.63)
Q4 2008	1,702	$77.57	2,825	60%	($4.7)	($1.68)
Q3-Q4 2008(1)	3,681	$76.97	5,650	65%	($9.3)	($1.66)
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 2,148 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 1,534 mbbls of production in 2008 at a weighted average price of $85.23 for a weighted average premium of $3.34, 3,285 mbbls of production in 2009 at a weighed average price of $122.22 for a weighted average premium of $6.07 and 3,285 mbbls of production in 2010 at a weighed average price of $131.67 for a weighted average premium of $6.94.