Expand Energy (EXE) 8-K Regulation FD Disclosure

Exhibit 99.2

SCHEDULE “A”

CHESAPEAKE’S OUTLOOK AS OF JANUARY 4, 2010

Years Ending December 31, 2010 and 2011

Our policy is to periodically provide guidance on certain factors that affect our future financial performance.  As of January 4, 2010, we are using the following key assumptions in our projections for 2010 and 2011.

The primary changes from our November 2, 2009 Outlook are in italicized bold and are explained as follows:

1)   Projected production volumes have been updated to reflect the production loss from the expected sale of 25% of our Barnett assets to Total (initially approximately 175 mmcfe per day) and production gains from the ongoing outperformance of our drilling programs. We believe these two factors will cancel each other in 2010 and therefore our 2010 production guidance remains unchanged at 2,650 mmcfe per day.  However, we have increased  our 2011 production forecast by 50 mmcfe per day to reflect the anticipated ongoing outperformance of our drilling programs;

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

3)   Our cash flow projections have been updated.

	Year Ending 12/31/2010	Year Ending 12/31/2011
Estimated Production:
Natural gas – bcf	882 – 902	1,022 – 1,047
Oil – mbbls	12,500	13,000
Natural gas equivalent – bcfe	957 – 977	1,100 – 1,125
Daily natural gas equivalent midpoint – mmcfe	2,650	3,050
Year-over-year estimated production increase	6 – 8%	14 – 16%
Year-over-year estimated production increase excluding divestitures and curtailments	12 – 14%	15 – 17%
NYMEX Price (for calculation of realized hedging effects only):
Natural gas - $/mcf	$7.00	$7.50
Oil - $/bbl	$80.00	$80.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$0.70	$0.23
Oil - $/bbl	$4.74	$8.30
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	15 – 25%	15 – 25%
Oil - $/bbl	7 – 10%	7 – 10%
Operating Costs per Mcfe of Projected Production:
Production expense	$0.90 – 1.10	$0.90 – 1.10
Production taxes (~ 5% of O&G revenues)	$0.30 – 0.35	$0.30 – 0.35
General and administrative(a)	$0.33 – 0.37	$0.33 – 0.37
Stock-based compensation (non-cash)	$0.10 – 0.12	$0.10 – 0.12
DD&A of natural gas and oil assets	$1.50 – 1.70	$1.50 – 1.70
Depreciation of other assets	$0.20 – 0.25	$0.20 – 0.25
Interest expense(b)	$0.35 – 0.40	$0.35 – 0.40
Other Income per Mcfe:
Marketing, gathering and compression net margin	$0.07 – 0.09	$0.07 – 0.09
Service operations net margin	$0.04 – 0.06	$0.04 – 0.06
Equity in income of midstream joint venture (CMP)	$0.04 – 0.06	$0.04 – 0.06
Book Tax Rate (all deferred)	39%	39%
Equivalent Shares Outstanding (in millions):
Basic	625 – 630	635 – 640
Diluted	640 – 645	645 – 650

	Year Ending 12/31/2010	Year Ending 12/31/2011
Cash Flow Projections ($ in millions):
Operating cash flow before changes in assets and liabilities(c)(d)	$4,450 – 4,750	$5,000 – 5,600
Net leasehold and producing property transactions	$1,300 – 1,700	$1,000 – 1,300
Drilling capital expenditures	($4,000 – 4,300)	($4,100 – 4,400)
Dividends, capitalized interest, cash income taxes, etc.	($350 – 400)	($450 – 550)
Other	($500 – 600)	($250 – 300)
Projected Net Cash Change	$900 – 1,150	$1,200 – 1,650

At December 31, 2009, the company had approximately $2.5 billion of cash and cash equivalents and additional borrowing capacity under its three revolving bank credit facilities.

(a)	Excludes expenses associated with noncash stock compensation.
(b)	Does not include gains or losses on interest rate derivatives (ASC 815).
(c)	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.
(d)	Assumes NYMEX natural gas prices of $6.50 to $7.50 per mcf and NYMEX oil prices of $80.00 per bbl in 2010 and  NYMEX natural gas prices of $ 7.00 to $8.00 per mcf and NYMEX oil prices of $80.00 per bbl in 2011.

Commodity Hedging Activities

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

1)	Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.
2)	Collars: These instruments 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 put and the call strike price, no payments are due from either party.  On occasion, we make a three-way collar by selling an additional put option with the collar in exchange for a more favorable strike price on the collar.  This eliminates the counterparty’s downside exposure below the second put option.
3)	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.
4)	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 either party.
5)	Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point.  For non-Appalachian Basin basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.  For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

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

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

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 ASC 815, 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 ASC 815, 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.

The company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas trades:

	Open Swaps (Bcf)	Avg. NYMEX  Strike Price of Open Swaps	Assuming Natural Gas Production (Bcf)	Open Swap Positions as a % of Estimated Total Natural Gas Production	Total Gains from Lifted Trades ($ millions)	Total Lifted Gain per Mcf of Estimated Total Natural Gas Production
Q1 2010	97	$7.46			$35.9
Q2 2010	99	$7.27			$37.9
Q3 2010	94	$7.54			$65.7
Q4 2010	96	$7.69			$65.2
Total 2010(a)	386	$7.49	892	43%	$204.7	$0.23
Total 2011(a)	64	$8.69	1,035	6%	$62.7	$0.06

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at $5.50 to $6.75 covering 15 bcf in 2010 and $5.75 to 6.50 covering 24 bcf in 2011.

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

	Open Collars (Bcf)	Avg. NYMEX Floor Price	Avg. NYMEX Ceiling Price	Assuming Natural Gas Production (Bcf)	Open Collars as a % of Estimated Total Natural Gas Production
Q1 2010	43	$6.49	$8.51
Q2 2010	16	$7.04	$9.17
Q3 2010	4	$7.60	$11.75
Q4 2010	4	$7.60	$11.75
Total 2010(a)	67	$6.75	$9.03	892	8%
Total 2011	7	$7.70	$11.50	1,035	1%

(a) Certain collar arrangements include three-way collars that include written put options with a strike price ranging from $4.25 to $4.35 covering 12 bcf in 2010.

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

	Call Options (Bcf)	Avg. NYMEX Floor Price	Avg. Premium per mcf	Assuming Natural Gas Production (Bcf)	Call Options as a % of Estimated Total Natural Gas Production
Q1 2010	28	$10.19	$1.47
Q2 2010	38	$9.87	$1.11
Q3 2010	43	$9.93	$0.98
Q4 2010	43	$10.10	$0.98
Total 2010	152	$10.01	$1.10	892	17%
Total 2011	73	$10.25	$0.57	1,035	7%

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

	Non-Appalachia		Appalachia
	Volume (Bcf)	NYMEX less(a)	Volume (Bcf)	NYMEX plus(a)
2010	—	—	10	0.26
2011	45	0.82	12	0.25
2012	43	0.85	—	—
Totals	88	$0.84	22	$0.26

(a) weighted average

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

	Open Swaps (mbbls)	Avg. NYMEX Strike Price	Assuming Oil Production (mbbls)	Open Swap Positions as a % of Estimated Total Oil Production	Total Gains (Losses) from Lifted Trades ($ millions)	Total Lifted Gains (Losses) per bbl of Estimated Total Oil Production
Q1 2010	1,980	$89.56	—	—	$(4.0)	—
Q2 2010	2,002	$89.56	—	—	$(4.0)	—
Q3 2010	2,024	$89.56	—	—	$(4.2)	—
Q4 2010	2,024	$89.56	—	—	$(4.2)	—
Total 2010(a)	8,030	$89.56	12,500	64%	$(16.4)	$(1.31)
Total 2011(a)	3,285	$96.09	13,000	25%	$32.8	$2.53

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 5 mmbbls and 1 mmbbls in 2010 and 2011, respectively.

Note:  Not shown above are written call options covering 3 mmbbls of oil production in 2010 at a weighted average price of $105.00 per bbl for a weighted average discount of $1.10 per bbl and 4 mmbls of oil production in 2011 at a weighted average price of $105.00 per bbl for a weighted average premium of $4.27 per bbl.

SCHEDULE “B”

CHESAPEAKE’S PREVIOUS OUTLOOK AS OF NOVEMBER 2, 2009

(PROVIDED FOR REFERENCE ONLY)

NOW SUPERSEDED BY OUTLOOK AS OF JANURARY 4, 2010

Years Ending December 31, 2009, 2010 and 2011

Our policy is to periodically provide guidance on certain factors that affect our future financial performance.  As of November 2, 2009, we are using the following key assumptions in our projections for 2009, 2010 and 2011.

The primary changes from our October 13, 2009 Outlook are in italicized bold and are explained as follows:

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

2)   Our NYMEX natural gas and oil price assumptions for realized hedging effects and estimating future operating cash flow have been updated; and

3)   Our cash flow projections have been updated.

	Year Ending 12/31/2009	Year Ending 12/31/2010	Year Ending 12/31/2011
Estimated Production:
Natural gas – bcf	815 – 825	882 – 902	1,007 – 1,027
Oil – mbbls	12,000	12,500	13,000
Natural gas equivalent – bcfe	885 – 895	957 – 977	1,085 – 1,105
Daily natural gas equivalent midpoint – mmcfe	2,440	2,650	3,000
Year-over-year estimated production increase	5 – 6%	8 – 10%	12 – 14%
Year-over-year estimated production increase excluding divestitures and curtailments	9 – 10%	10 – 12%	13 – 15%
NYMEX Prices (a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$3.91	$7.00	$7.50
Oil - $/bbl	$57.75	$80.00	$80.00
Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$2.97	$0.85	$0.22
Oil - $/bbl	$3.78	$1.99	$5.71
Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	20 – 30%	15 – 25%	15 – 25%
Oil - $/bbl	7 – 10%	7 – 10%	7 – 10%
Operating Costs per Mcfe of Projected Production:
Production expense	$1.10 – 1.20	$0.90 – 1.10	$0.90 – 1.10
Production taxes (~ 5% of O&G revenues)(b)	$0.20 – 0.25	$0.30 – 0.35	$0.30 – 0.35
General and administrative(c)	$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	$1.50 – 1.70	$1.50 – 1.70	$1.50 – 1.70
Depreciation of other assets	$0.25 – 0.30	$0.20 – 0.25	$0.20 – 0.25
Interest expense(d)	$0.30 – 0.35	$0.35 – 0.40	$0.35 – 0.40
Other Income per Mcfe:
Marketing, gathering and compression net margin	$0.10 – 0.12	$0.07 – 0.09	$0.07 – 0.09
Service operations net margin	$0.04 – 0.06	$0.04 – 0.06	$0.04 – 0.06
Equity in income of midstream joint venture (CMP)	–	$0.04 – 0.06	$0.04 – 0.06
Book Tax Rate (all deferred)	37.5%	39%	39%
Equivalent Shares Outstanding (in millions):
Basic	610 – 615	625 – 630	635 – 640
Diluted	625 – 630	640 – 645	645 – 650

	Year Ending 12/31/2009	Year Ending 12/31/2010	Year Ending 12/31/2011
Cash Flow Projections ($ in millions):
Operating cash flow before changes in assets and liabilities(e)(f)	$3,700 – 3,750	$4,350 – 5,050	$4,750 – 5,450
Net leasehold and producing property transactions	$750 – 900	$1,000 – 1,350	$900 – 1,250
Drilling capital expenditures	($3,150 – 3,350)	($4,400 – 4,700)	($4,600 – 4,900)
Dividends, senior notes redemption, capitalized interest, cash income taxes, etc.	($600 – 825)	($400 – 500)	($450 – 550)
Other	($375 – 550)	($225 – 300)	($50 – 125)
Projected Net Cash Change	($75) – 325	$325 – 900	$550 – 1,125

At September 30, 2009, the company had $3.1 billion of cash and cash equivalents and additional borrowing capacity under its three revolving bank credit facilities.

(a)	NYMEX natural gas prices have been updated for actual contract prices through November 2009 and NYMEX oil prices have been updated for actual contract prices through September 2009.
(b)	Production tax per mcfe is based on NYMEX prices of $57.75 per bbl of oil and $4.75 to $6.25 per mcf of natural gas during 2009 and $80.00 per bbl of oil and $7.00 to $8.25 per mcf of natural gas during 2010 and 2011.
(c)	Excludes expenses associated with noncash stock compensation.
(d)	Does not include gains or losses on interest rate derivatives (ASC 815).
(e)	A non-GAAP financial measure.  We are unable to provide a reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.
(f)	Assumes NYMEX natural gas prices of $5.00 to $6.00 per mcf and NYMEX oil prices of $57.75 per bbl in 2009,  NYMEX natural gas prices of $6.50 to $7.50 per mcf and NYMEX oil prices of $80.00 per bbl in 2010 and  NYMEX natural gas prices of $ 7.00 to $8.00 per mcf and NYMEX oil prices of $80.00 per bbl in 2011.

Commodity Hedging Activities

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

1)	For swap instruments, Chesapeake receives a fixed price for the commodity and pays a floating market price to the counterparty.
2)	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.
3)	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.
4)	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.
5)	Basis protection swaps are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point.  For non-Appalachian Basin basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.  For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.
6)	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.

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

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

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 ASC 815, 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 ASC 815, 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 trades:

	Open Swaps (Bcf)	Avg. NYMEX  Strike Price of Open Swaps	Assuming Natural Gas Production (Bcf)	Open Swap Positions as a % of Estimated Total Natural Gas Production	Total Gains from Lifted Trades ($ millions)	Total Lifted Gain per Mcf of Estimated Total Natural Gas Production
Q4 2009(a)	107.2	$6.83	210	51%	$114.2	$0.54
Q1 2010	28.7	$9.84			$50.6
Q2 2010	27.5	$8.83			$52.7
Q3 2010	31.7	$9.60			$60.1
Q4 2010	33.0	$9.77			$59.5
Total 2010(a)	120.9	$9.53	892	14%	$222.9	$0.25
Total 2011(a)	23.7	$9.86	1,017	2%	$62.7	$0.06

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at $6.00 covering 1 bcf for the remainder of 2009, $5.45 to $6.75 covering 70 bcf in 2010 and $5.75 to 6.50 covering 24 bcf in 2011.

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

	Open Collars (Bcf)	Avg. NYMEX Floor Price	Avg. NYMEX Ceiling Price	Assuming Natural Gas Production (Bcf)	Open Collars as a % of Estimated Total Natural Gas Production
Q4 2009(a)	52.1	$7.34	$8.88	210	25%
Q1 2010	43.2	$6.49	$8.51
Q2 2010	16.4	$7.04	$9.17
Q3 2010	3.7	$7.60	$11.75
Q4 2010	3.7	$7.60	$11.75
Total 2010(a)	67.0	$6.75	$9.03	892	8%
Total 2011	7.2	$7.70	$11.50	1,017	1%

(a) Certain collar arrangements include three-way collars that include written put options with a strike price of $6.00 covering 11 bcf for the remainder of 2009 and ranging from $4.25 to $5.50 covering 26 bcf in 2010.

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

	Call Options (Bcf)	Avg. NYMEX Floor Price	Avg. Premium per mcf	Assuming Natural Gas Production (Bcf)	Call Options as a % of Estimated Total Natural Gas Production
Q4 2009	9.7	$6.51	$2.25	210	5%
Q1 2010	69.3	$10.26	$0.61
Q2 2010	74.6	$10.08	$0.56
Q3 2010	75.4	$10.17	$0.56
Q4 2010	75.4	$10.27	$0.56
Total 2010	294.7	$10.19	$0.57	892	33%
Total 2011	73.1	$10.25	$0.57	1,017	7%

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

	Non-Appalachia		Appalachia
	Volume (Bcf)	NYMEX less(a)	Volume (Bcf)	NYMEX plus(a)
2009	10.4	$1.64	4.4	$0.27
2010	—	—	10.2	0.26
2011	45.1	0.82	12.1	0.25
2012	43.2	0.85	—	—
Totals	98.7	$0.92	26.7	$0.26

(a) weighted average

We assumed certain liabilities related to open derivative positions in connection with the CNR acquisition in November 2005.  In accordance with ASC 805, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($11 million as of September 30, 2009).  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 ASC 815 Derivatives and Hedging, 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 (Bcf)	Avg. NYMEX Strike Price Of Open Swaps	Avg. Fair Value Upon Acquisition of Open Swaps	Initial Liability Acquired	Assuming Natural Gas Production (Bcf)	Open Swap Positions as a % of Estimated Total Natural Gas Production
Q4 2009	4.6	$5.18	$7.32	$(2.14)	210	2%

Note:  Not shown above are collars covering 1 bcf of production for the remainder of 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 (mbbls)	Avg. NYMEX Strike Price	Assuming Oil Production (mbbls)	Open Swap Positions as a % of Estimated Total Oil Production	Total Gains (Losses) from Lifted Trades ($ millions)	Total Lifted Gains (Losses) per bbl of Estimated Total Oil Production
Q4 2009	1,058	$87.05	2,947	36%	$9.4	$3.20
Q1 2010	1,170	$90.25	—	—	$(4.0)	—
Q2 2010	1,183	$90.25	—	—	$(4.0)	—
Q3 2010	1,196	$90.25	—	—	$(4.2)	—
Q4 2010	1,196	$90.25	—	—	$(4.2)	—
Total 2010(a)	4,745	$90.25	12,500	38%	$(16.4)	$(1.31)
Total 2011(a)	1,095	$104.75	13,000	8%	$32.8	$2.53

(a) Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $50.00 to $60.00 covering 1 mmbbls for the remainder of 2009 and $60.00 covering 5 mmbbls and 1 mmbbls in 2010 and 2011, respectively.

Note:  Not shown above are written call options covering 1 mmbbls of oil production for the remainder of 2009 at a weighted average price of $112.50 per bbl for a weighted average discount of $1.21 per bbl, 3 mmbbls of oil production in 2010 at a weighted average price of $115.00 per bbl for a weighted average discount of $0.86 per bbl and 4 mmbls of oil production in 2011 at a weighted average price of $105.00 per bbl for a weighted average premium of $4.27 per bbl.