chk10132009_991.htm

Exhibit 99.1

SCHEDULE “A”

CHESAPEAKE’S OUTLOOK AS OF OCTOBER 13, 2009

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 October 13, 2009, we are using the following key assumptions in our projections for 2009, 2010 and 2011.

The primary changes from our August 3, 2009 Outlook are in italicized bold and are explained as follows:

1)	Our first projections for full-year 2011 have been provided;

2)	Our production guidance has been updated;

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

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

5)	Our projections have been adjusted to reflect the anticipated deconsolidation as of January 1, 2010 of Chesapeake’s 50/50 midstream joint venture with Global Infrastructure Partners;

6)	Our cash inflows from property sales and capital spending have been updated to reflect our second amendment to our Haynesville Shale joint venture with Plains Exploration & Production Company;

7)	Our asset monetization projections have been updated; and

8)	Certain revenue, cost and cash income tax assumptions 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	$3.85	$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	$3.00	$0.85	$0.22
Oil - $/bbl	$3.77	$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 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


Cash Flow Projections ($ in millions):	Year Ending 12/31/2009	Year Ending 12/31/2010	Year Ending 12/31/2011

Net Cash Inflows:
Operating cash flow before changes in assets and liabilities(e)(f)	$3,700 – 3,750	$4,350 – 5,050	$4,750 – 5,450

Leasehold and producing property transactions:
Sale of leasehold and producing properties	$1,900 – 2,000	$1,500 – 2,000	$1,250 – 1,750
Acquisition of leasehold and producing properties:	($1,000 – 1,250)	$(500 – 650)	($350 – 500)
Net leasehold and producing property transactions	$750 – 900	$1,000 – 1,350	$900 – 1,250

Midstream equity financings and system sales	$600 – 800	$250 – 300	$300 – 500
Midstream credit facility draws (repayments)	($200 – 300)	$150 – 200	–
Proceeds from investments and other	$450	–	$200 – 250
Total Cash Inflows	$5,300 – 5,600	$5,750 – 6,900	$6,150 – 7,450

Net Cash Outflows:
Drilling	$3,150 – 3,350	$4,400 – 4,700	$4,600 – 4,900
Geophysical costs	$125 – 150	$125 – 150	$125 – 150
Midstream infrastructure and compression	$700 – 900	$300 – 400	$300 – 400
Other PP&E	$400 – 450	$200 – 250	$200 – 250
Dividends, senior notes redemption, capitalized interest, etc.	$600 – 800	$550 – 650	$450 – 550
Cash income taxes	$0 – 25	($100 – 200)	–
Total Cash Outflows	$4,975 – 5,675	$5,475 – 5,950	$5,675 – 6,250

Net Cash Change	($75) – 325	$275 – 950	$475 – 1,200

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 October 2009 and NYMEX oil prices have been updated for actual contract prices through September 2009.
(b)	Severance 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 (SFAS 133).
(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 or oil from a specified delivery point. For Mid-Continent 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 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 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



Q3 2009	74.4	$	7.32			$	17.8
Q4 2009	105.0	$	6.88			$	114.2
Q3-Q4 2009(a)	179.4	$	7.06	420	43 %	$	132.0	$	0.31

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 %	$	222.8	$	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 2 bcf in 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



Q3 2009	102.7	$	7.02	$	8.76
Q4 2009	52.1	$	7.34	$	8.88
Q3-Q4 2009(a)	154.8	$	7.12	$	8.80	420	37%

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(a)	7.2	$	7.70	$	11.50	1,017	1%

(a)	Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 36 bcf in 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



Q3 2009	14.0	$	6.75	$	1.61
Q4 2009	9.7	$	6.51	$	2.25
Q3-Q4 2009	23.7	$	6.65	$	1.87	420	6%

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(a)	73.1	$	10.25	$	0.57	1,017	7%

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

	Mid-Continent			Appalachia
	Volume (Bcf)	NYMEX less(a)		Volume (Bcf)	NYMEX plus(a)
2009	10.9	$	1.57	8.9	$	0.27
2010	—		—	10.2		0.26
2011	45.1		0.82	12.1		0.25
2012	43.2		0.85	—		—
Totals	99.2	$	0.92	31.2	$	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 SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $592 million ($19 million as of June 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 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 (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
Q3 2009	4.6	$	5.18	$	6.89	$	(1.71)
Q4 2009	4.6	$	5.18	$	7.32	$	(2.14)
Q3-Q4 2009	9.2	$	5.18	$	7.11	$	(1.92)	420	2%

Note: Not shown above are collars covering 1.84 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 (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
Q3 2009	1,058	$	87.05			$	8.9
Q4 2009	1,058	$	87.05			$	9.4
Q3-Q4 2009(a)	2,116	$	87.05	5,974	35%	$	18.3	$	3.07

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 knockout swaps with provisions limiting the counterparty’s exposure below prices ranging from $50.00 to $60.00 covering 3 mmbbls in 2009 and $60.00 covering 5 mmbbls and 1 mmbbls in 2010 and 2011, respectively.

Note: Not shown above are written call options covering 2 mmbbls of oil production in 2009 at a weighted average price of $106.25 per bbl for a weighted average premium of $0.85 per bbl, 3 mmbbls of oil production in 2010 at a weighted average price of $115.00 per bbl for a weighted average premium of ($0.86) per bbl and 6 mmbls of oil production in 2011 at a weighted average price of $105.00 per bbl for a weighted average premium of $4.26 per bbl.

SCHEDULE “B”

CHESAPEAKE’S PREVIOUS OUTLOOK AS OF AUGUST 3, 2009

(PROVIDED FOR REFERENCE ONLY)

NOW SUPERSEDED BY OUTLOOK AS OF OCTOBER 13, 2009

Years Ending December 31, 2009 and 2010

Our policy is to periodically provide guidance on certain factors that affect our future financial performance. As of August 3, 2009, we are using the following key assumptions in our projections for 2009 and 2010.

The primary changes from our May 4, 2009 Outlook are in italicized bold and are explained as follows:

1)	Our production guidance has been updated. It reflects anticipated volumetric production payment transactions in 2009 and 2010 and does not assume any future voluntary production curtailments;

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

3)	Our NYMEX natural gas and oil price assumptions for realized hedging effects and estimating future operating cash flow have been updated for 2009 and 2010; and

4)	Certain cost, book and cash income tax and share assumptions have been updated.

	Year Ending 12/31/2009	Year Ending 12/31/2010
Estimated Production:
Natural gas – bcf	805 – 815	865 – 885
Oil – mbbls	12,000	12,000
Natural gas equivalent – bcfe	875 – 885	940 – 960

Daily natural gas equivalent midpoint – mmcfe	2,410	2,600

Year-over-year estimated production increase	4 – 5%	7 – 8%
Year-over-year estimated production increase excluding divestitures and curtailments	8 – 9%	9 – 10%

NYMEX Prices (a) (for calculation of realized hedging effects only):
Natural gas - $/mcf	$4.30	$6.25
Oil - $/bbl	$55.67	$70.00

Estimated Realized Hedging Effects (based on assumed NYMEX prices above):
Natural gas - $/mcf	$2.68	$0.93
Oil - $/bbl	$5.65	$7.37

Estimated Differentials to NYMEX Prices:
Natural gas - $/mcf	20 – 30%	15 – 20%
Oil - $/bbl	7 – 10%	5 – 7%

Operating Costs per Mcfe of Projected Production:
Production expense	$1.10 – 1.20	$1.10 – 1.20
Production taxes (~ 5% of O&G revenues)(b)	$0.20 – 0.25	$0.30 – 0.35
General and administrative(c)	$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	$0.25 – 0.30	$0.25 – 0.30
Interest expense(d)	$0.30 – 0.35	$0.35 – 0.40

Other Income per Mcfe:
Natural gas and oil midstream income	$0.10 – 0.12	$0.09 – 0.11
Service operations income	$0.04 – 0.06	$0.04 – 0.06

Book Tax Rate (all deferred)	37.5%	39%

Equivalent Shares Outstanding (in millions):
Basic	610 – 615	625 – 630
Diluted	625 – 630	640 – 645


Cash Flow Projections ($ in millions):	Year Ending 12/31/2009	Year Ending 12/31/2010

Net inflows:
Operating cash flow before changes in assets and liabilities(e)(f)	$3,700 – 3,750	$3,950 – 4,650

Leasehold and producing property transactions:
Sale of leasehold and producing properties	$1,750 – 2,250	$1,000 – 1,500
Acquisition of leasehold and producing properties:	($500 – 750)	($350 – 500)
Net leasehold and producing property transactions	$1,250 – 1,500	$650 – 1,000

Midstream equity financings and system sales	$600 – 800	$250 – 300
Midstream credit facility draws (repayments)	($200 – 300)	$150 – 200
Proceeds from investments and other	$450	–
Total Cash Inflows	$5,800 – 6,200	$5,000 – 6,150

Net outflows:
Drilling	$3,000 – 3,200	$3,400 – 3,700
Geophysical costs	$100 – 125	$100 – 125
Midstream infrastructure and compression	$700 – 900	$300 – 400
Other PP&E	$400 – 450	$200 – 250
Dividends, senior notes redemption, capitalized interest, etc.	$600 – 800	$600 – 700
Cash income taxes	$175 – 200	($200 – 300)
Total Cash Outflows	$4,975 – 5,675	$4,400 – 4,875

Net Cash Change	$525 – 825	$600 – 1,275

At June 30, 2009, the company had $1.3 billion of cash and cash equivalents and additional borrowing capacity under its two revolving bank credit facilities.

(a)	NYMEX natural gas prices have been updated for actual contract prices through August 2009 and NYMEX oil prices have been updated for actual contract prices through June 2009.
(b)	Severance tax per mcfe is based on NYMEX prices of $55.67 per bbl of oil and $5.00 to $6.00 per mcf of natural gas during 2009 and $70.00 per bbl of oil and $7.00 to $8.00 per mcf of natural gas during 2010.
(c)	Excludes expenses associated with noncash stock compensation.
(d)	Does not include gains or losses on interest rate derivatives (SFAS 133).
(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 $60.00 per bbl in 2009 and NYMEX natural gas prices of $6.00 to $7.00 per mcf and NYMEX oil prices of $70.00 per bbl in 2010.