Exhibit 99.1
SCHEDULE “A”
CHESAPEAKE’S OUTLOOK AS OF MARCH 31, 2008
Quarter Ending March 31, 2008 and Years Ending December 31, 2008 and 2009.
We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance. As of March 31, 2008, we are using the following key assumptions in our projections for the first quarter of 2008 and the full-years 2008 and 2009.
The primary changes from our February 21, 2008 Outlook are in italicized bold and are explained as follows:
| 1) | We are increasing our prior production guidance for the full-years 2008 and 2009 (note: guidance in this Outlook excludes production expected to be sold in conjunction with various anticipated monetizations transactions in 2008 and 2009); |
| 2) | Projected effects of changes in our hedging positions have been updated; |
| 3) | Budgeted capital expenditure assumptions have been updated; and |
| 4) | Share assumptions have been updated to reflect our recent 20 million share common stock offering. |
Quarter Ending 3/31/2008 | Year Ending 12/31/2008 | Year Ending 12/31/2009 | |||
Estimated Production(a) | |||||
| Oil – mbbls | 2,675 | 10,700 | 11,000 | ||
| Natural gas – bcf | 182 – 186 | 798 – 808 | 924 – 944 | ||
| Natural gas equivalent – bcfe | 198 – 202 | 862.5 – 872.5 | 990 – 1,010 | ||
| Daily natural gas equivalent midpoint – mmcfe | 2,200 | 2,370 | 2,740 | ||
| NYMEX Prices (b) (for calculation of realized hedging effects only): | |||||
| Oil - $/bbl | $80.98 | $82.36 | $80.00 | ||
| Natural gas - $/mcf | $7.55 | $8.01 | $8.00 | ||
| Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | |||||
| Oil - $/bbl | $(6.98) | $(5.94) | $1.94 | ||
| Natural gas - $/mcf | $1.84 | $1.11 | $0.69 | ||
| Estimated Differentials to NYMEX Prices: | |||||
| Oil - $/bbl | 7 – 9% | 7 – 9% | 7 – 9% | ||
| Natural gas - $/mcf | 10 – 14% | 10 – 14% | 10 – 14% | ||
| Operating Costs per Mcfe of Projected Production: | |||||
| Production expense | $0.90 – 1.00 | $0.90 – 1.00 | $0.90 – 1.00 | ||
Production taxes (generally 5% of O&G revenues) (c) | $0.32 – 0.37 | $0.32 – 0.37 | $0.32 – 0.37 | ||
General and administrative(d) | $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 | ||
| DD&A of oil and natural gas 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: | |||||
| Oil and natural gas 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 (≈ 97% deferred) | 38.5% | 38.5% | 38.5% | ||
| Equivalent Shares Outstanding – in millions: | |||||
| Basic | 493 | 509 | 523 | ||
| Diluted | 525 | 540 | 553 | ||
| Budgeted Capital Expenditures, net – in millions: | |||||
| Drilling | $1,100 – 1,200 | $4,600 – 5,000 | $5,000 – 5,400 | ||
| Leasehold and property acquisition costs | $400 – 450 | $1,300 – 1,500 | $1,300 – 1,500 | ||
Monetization of oil and gas properties(a) | — | $(1,000) | $(1,000) | ||
| Geological and geophysical costs | $75 | $250 | $250 | ||
| Total budgeted capital expenditures, net | $1,575 – 1,725 | $5,150 – $5,750 | $5,550 – $6,150 | ||
| (a) | The 2008 and 2009 forecasts assume that the company monetizes $2 billion of producing properties in multiple transactions in the second and fourth quarters of 2008 and 2009. |
| (b) | NYMEX oil prices have been updated for actual contract prices through February 2008 and NYMEX natural gas prices have been updated for actual contract prices through March 2008. |
| (c) | Severance tax per mcfe is based on NYMEX prices of: $80.98 per bbl of oil and $7.00 to $8.00 per mcf of natural gas during Q1 2008; $82.36 per bbl of oil and $7.20 to $8.20 per mcf of natural gas during calendar 2008; and $80.00 per bbl of oil and $7.30 to $8.30 per mcf of natural gas during calendar 2009. |
| (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 oil and natural gas 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) | For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a "cap" limiting the counterparty's exposure. In other words, there is no limit to Chesapeake's exposure but there is a limit to the downside exposure of the counterparty. |
| (iii) | For knockout swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain predetermined knockout prices. |
| (iv) | For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake. |
| (v) | Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party. |
| (vi) | A three-way collar contract consists of a standard collar contract plus a written put option with a strike price below the floor price of the collar. In addition to the settlement of the collar, the put option requires Chesapeake to make a payment to the counterparty equal to the difference between the put option price and the settlement price if the settlement price for any settlement period is below the put option strike price. |
| (vii) | Basis protection swaps are arrangements that guarantee a price differential 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. |
Commodity markets are volatile, and as a result, Chesapeake’s hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction.
Chesapeake enters into oil and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and natural gas prices. Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to oil and natural gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and natural gas sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these 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 oil and natural gas sales.
Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and natural gas sales.
Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas swaps:
Open Swaps in Bcf’s | Avg. NYMEX Strike Price of Open Swaps | Assuming Natural Gas Production in Bcf’s of: | Open Swap Positions as a % of Estimated Total Natural Gas Production | Total Gains from Lifted Swaps ($ millions) | Total Lifted Gain per Mcf of Estimated Total Natural Gas Production | |
| Q1 2008 | 131.0 | $8.59 | 184 | 71% | $156.4 | $0.85 |
| Q2 2008 | 137.5 | $8.62 | 195 | 71% | $40.6 | $0.21 |
| Q3 2008 | 138.0 | $8.80 | 208 | 66% | $38.1 | $0.18 |
| Q4 2008 | 127.6 | $9.34 | 216 | 59% | $47.1 | $0.22 |
Total 2008(1) | 534.1 | $8.83 | 803 | 67% | $282.2 | $0.35 |
Total 2009(1) | 356.1 | $9.22 | 934 | 38% | $22.1 | $0.02 |
| (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 190 bcf in 2008 and $5.45 to $6.50 covering 280 bcf in 2009. |
The company currently has the following open natural gas collars in place:
Open Collars in Bcf’s | Avg. NYMEX Floor Price | Avg. NYMEX Ceiling Price | Assuming Natural Gas Production in Bcf’s of: | Open Collars as a % of Estimated Total Natural Gas Production | |
| Q1 2008 | 18.5 | $7.36 | $9.28 | 184 | 10% |
| Q2 2008 | 9.1 | $8.27 | $9.91 | 195 | 5% |
| Q3 2008 | 9.2 | $8.27 | $9.91 | 208 | 4% |
| Q4 2008 | 7.4 | $8.19 | $9.88 | 216 | 3% |
Total 2008(1) | 44.2 | $7.88 | $9.64 | 803 | 6% |
Total 2009(1) | 56.7 | $8.22 | $10.70 | 934 | 6% |
| (1) | Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 11 bcf in 2008 and $5.50 to $6.00 covering 46 bcf in 2009. |
Note: Not shown above are written call options covering 111 bcf of production in 2008 at a weighed average price of $10.26 for a weighted average premium of $0.66 and 191 bcf of production in 2009 at a weighed average price of $11.24 for a weighted average premium of $0.52.
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 ($173 million as of December 31, 2007). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.
Pursuant to SFAS 149 “Amendment of SFAS 133 on Derivative Instruments and Hedging Activities,” the assumed CNR derivative instruments are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows.
The following details the CNR derivatives (natural gas swaps) we have assumed:
Open Swaps in Bcf’s | Avg. NYMEX Strike Price Of Open Swaps (per Mcf) | Avg. Fair Value Upon Acquisition of Open Swaps (per Mcf) | Initial Liability Acquired (per Mcf) | Assuming Natural Gas Production in Bcf’s of: | Open Swap Positions as a % of Estimated Total Natural Gas Production | |
| Q1 2008 | 9.5 | $4.68 | $9.42 | ($4.74) | 184 | 5% |
| Q2 2008 | 9.5 | $4.68 | $7.41 | ($2.73) | 195 | 5% |
| Q3 2008 | 9.7 | $4.68 | $7.41 | ($2.74) | 208 | 5% |
| Q4 2008 | 9.7 | $4.66 | $7.84 | ($3.17) | 216 | 4% |
| Total 2008 | 38.4 | $4.68 | $8.02 | ($3.34) | 803 | 5% |
| Total 2009 | 18.3 | $5.18 | $7.28 | ($2.10) | 934 | 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 | |
| Q1 2008 | 1,823 | 73.97 | 2,675 | 68% | $(3.2) | $(1.21) |
| Q2 2008 | 1,896 | 75.58 | 2,665 | 71% | $(4.7) | $(1.77) |
| Q3 2008 | 2,039 | 76.92 | 2,680 | 76% | $(4.6) | $(1.72) |
| Q4 2008 | 1,886. | 79.01 | 2,680 | 70% | $(4.7) | $(1.77) |
Total 2008(1) | 7,644 | $76.40 | 10,700 | 71% | $(17.2) | $(1.62) |
Total 2009(1) | 8,395 | $82.33 | 11,000 | 76% | — | — |
| (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 4,304 mbbls in 2008 and from $52.50 to $60.00 covering 7,848 mbbls in 2009. |
Note: Not shown above are written call options covering 2,564 mbbls of production in 2008 at a weighted average price of $82.50 for a weighted average premium of $3.17 and 2,555 mbbls of production in 2009 at a weighed average price of $82.14 for a weighted average premium of $4.98.
SCHEDULE “B”
CHESAPEAKE’S PREVIOUS OUTLOOK AS OF FEBRUARY 21, 2008
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF MARCH 31, 2008
Quarter Ending March 31, 2008 and Years Ending December 31, 2008 and 2009.
We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance. As of February 21, 2008, we are using the following key assumptions in our projections for the first quarter of 2008 and the full years 2008 and 2009.
The primary changes from our November 6, 2007 Outlook are in italicized bold and are explained as follows:
| 1) | We are providing our first guidance for the 2008 first quarter and increasing our prior production guidance for the full years 2008 and 2009. Guidance in this Outlook excludes production expected to be sold in conjunction with various anticipated monetization transactions in 2008 and 2009, whereas guidance issued on November 6, 2007 included such volumes; |
| 2) | Projected effects of changes in our hedging positions have been updated; |
| 3) | Certain cost assumptions, shares outstanding and budgeted capital expenditure assumptions have been updated; and |
| 4) | Our projected book tax rate has been updated. |
Quarter Ending 3/31/2008 | Year Ending 12/31/2008 | Year Ending 12/31/2009 | |||
Estimated Production(a) | |||||
| Oil – mbbls | 2,675 | 10,500 | 11,000 | ||
| Natural gas – bcf | 182 – 186 | 788 – 798 | 892 – 902 | ||
| Natural gas equivalent – bcfe | 198 – 202 | 851 – 861 | 958 – 968 | ||
| Daily natural gas equivalent midpoint – mmcfe | 2,200 | 2,340 | 2,640 | ||
| NYMEX Prices(b)(for calculation of realized hedging effects only): | |||||
| Oil - $/bbl | $80.98 | $76.49 | $75.00 | ||
| Natural gas - $/mcf | $7.55 | $7.51 | $7.50 | ||
| Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | |||||
| Oil - $/bbl | $(6.98) | $(2.11) | $6.00 | ||
| Natural gas - $/mcf | $1.84 | $1.39 | $0.63 | ||
| Estimated Differentials to NYMEX Prices: | |||||
| Oil - $/bbl | 7 – 9% | 7 – 9% | 7 – 9% | ||
| Natural gas - $/mcf | 10 – 14% | 10 – 14% | 10 – 14% | ||
| Operating Costs per Mcfe of Projected Production: | |||||
| Production expense | $0.90 – 1.00 | $0.90 – 1.00 | $0.90 – 1.00 | ||
Production taxes (generally 5% of O&G revenues) (c) | $0.32 – 0.37 | $0.32 – 0.37 | $0.32 – 0.37 | ||
General and administrative(d) | $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 | ||
| DD&A of oil and natural gas 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: | |||||
| Oil and natural gas 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 (≈ 97% deferred) | 38.5% | 38.5% | 38.5% | ||
| Equivalent Shares Outstanding – in millions: | |||||
| Basic | 493 | 496 | 504 | ||
| Diluted | 525 | 526 | 534 | ||
| Budgeted Capital Expenditures, net – in millions: | |||||
| Drilling | $1,100 – 1,200 | $4,400 – 4,800 | $4,400 – 4,800 | ||
| Leasehold and property acquisition costs | $400 – 450 | $1,200 – 1,400 | $1,200 – 1,400 | ||
Monetization of oil and gas properties(a) | — | $(1,000) | $(1,000) | ||
| Geological and geophysical costs | $75 | $250 – 300 | $250 – 300 | ||
| Total budgeted capital expenditures, net | $1,575 – 1,725 | $4,850 – $5,500 | $4,850 – $5,500 | ||
| (a) | The 2008 and 2009 forecasts assume that the company monetizes $2 billion of producing properties in multiple transactions in the second and fourth quarters of 2008 and 2009. |
| (b) | NYMEX oil prices have been updated for actual contract prices through January 2008 and NYMEX natural gas prices have been updated for actual contract prices through February 2008. |
| (c) | Severance tax per mcfe is based on NYMEX prices of: $80.98 per bbl of oil and $7.00 to $8.00 per mcf of natural gas during Q1 2008; $76.49 per bbl of oil and $7.40 to $8.40 per mcf of natural gas during calendar 2008; and $75.00 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during calendar 2009. |
| (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 oil and natural gas 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) | For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a "cap" limiting the counterparty's exposure. In other words, there is no limit to Chesapeake's exposure but there is a limit to the downside exposure of the counterparty. |
| (iii) | For knockout swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain predetermined knockout prices. |
| (iv) | For written call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake. |
| (v) | Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party. |
| (vi) | A three-way collar contract consists of a standard collar contract plus a written put option with a strike price below the floor price of the collar. In addition to the settlement of the collar, the put option requires Chesapeake to make a payment to the counterparty equal to the difference between the put option price and the settlement price if the settlement price for any settlement period is below the put option strike price. |
| (vii) | Basis protection swaps are arrangements that guarantee a price differential 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. |
Commodity markets are volatile, and as a result, Chesapeake’s hedging activity is dynamic. As market conditions warrant, the company may elect to settle a hedging transaction prior to its scheduled maturity date and lock in the gain or loss on the transaction.
Chesapeake enters into oil and natural gas derivative transactions in order to mitigate a portion of its exposure to adverse market changes in oil and natural gas prices. Accordingly, associated gains or losses from the derivative transactions are reflected as adjustments to oil and natural gas sales. All realized gains and losses from oil and natural gas derivatives are included in oil and natural gas sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these 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 oil and natural gas sales.
Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and natural gas sales.
Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following open natural gas swaps in place and also has the following gains from lifted natural gas swaps:
Open Swaps in Bcf’s | Avg. NYMEX Strike Price of Open Swaps | Assuming Natural Gas Production in Bcf’s of: | Open Swap Positions as a % of Estimated Total Natural Gas Production | Total Gains from Lifted Swaps ($ millions) | Total Lifted Gain per Mcf of Estimated Total Natural Gas Production | |
| Q1 2008 | 131.0 | $8.59 | 184 | 71% | $156.4 | $0.85 |
| Q2 2008 | 133.0 | $8.51 | 194 | 69% | $44.5 | $0.23 |
| Q3 2008 | 132.5 | $8.69 | 205 | 65% | $40.5 | $0.20 |
| Q4 2008 | 119.5 | $9.23 | 210 | 57% | $45.3 | $0.22 |
Total 2008(1) | 516.0 | $8.74 | 793 | 65% | $286.7 | $0.36 |
Total 2009(1) | 276.0 | $9.04 | 897 | 31% | $12.8 | $0.01 |
| (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 191 bcf in 2008 and $5.45 to $6.50 covering 214 bcf in 2009. |
The company currently has the following open natural gas collars in place:
Open Collars in Bcf’s | Avg. NYMEX Floor Price | Avg. NYMEX Ceiling Price | Assuming Natural Gas Production in Bcf’s of: | Open Collars as a % of Estimated Total Natural Gas Production | |
| Q1 2008 | 18.5 | $7.36 | $9.28 | 184 | 10% |
| Q2 2008 | 2.7 | $7.50 | $9.68 | 194 | 1% |
| Q3 2008 | 2.8 | $7.50 | $9.68 | 205 | 1% |
| Q4 2008 | 2.8 | $7.50 | $9.68 | 210 | 1% |
Total 2008(1) | 26.8 | $7.41 | $9.40 | 793 | 3% |
Total 2009(1) | 45.7 | $8.14 | $10.82 | 897 | 5% |
| (1) | Certain collar arrangements include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 11 bcf in 2008 and $5.50 to $6.00 covering 46 bcf in 2009. |
Note: Not shown above are written call options covering 110 bcf of production in 2008 at a weighed average price of $10.26 for a weighted average premium of $0.66 and 142 bcf of production in 2009 at a weighed average price of $11.18 for a weighted average premium of $0.48.
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 ($173 million as of December 31, 2007). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes listed below at their fair values on the date of our acquisition of CNR.
Pursuant to SFAS 149 “Amendment of SFAS 133 on Derivative Instruments and Hedging Activities,” the assumed CNR derivative instruments are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows.
The following details the CNR derivatives (natural gas swaps) we have assumed:
Open Swaps in Bcf’s | Avg. NYMEX Strike Price Of Open Swaps (per Mcf) | Avg. Fair Value Upon Acquisition of Open Swaps (per Mcf) | Initial Liability Acquired (per Mcf) | Assuming Natural Gas Production in Bcf’s of: | Open Swap Positions as a % of Estimated Total Natural Gas Production | |
| Q1 2008 | 9.5 | $4.68 | $9.42 | ($4.74) | 184 | 5% |
| Q2 2008 | 9.5 | $4.68 | $7.41 | ($2.73) | 194 | 5% |
| Q3 2008 | 9.7 | $4.68 | $7.41 | ($2.74) | 205 | 5% |
| Q4 2008 | 9.7 | $4.66 | $7.84 | ($3.17) | 210 | 5% |
| Total 2008 | 38.4 | $4.68 | $8.02 | ($3.34) | 793 | 5% |
| Total 2009 | 18.3 | $5.18 | $7.28 | ($2.10) | 897 | 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 | |
| Q1 2008 | 1,823 | 73.97 | 2,675 | 68% | $(3.2) | $(1.21) |
| Q2 2008 | 1,866 | 75.22 | 2,605 | 72% | $(4.7) | $(1.81) |
| Q3 2008 | 1,886 | 75.11 | 2,610 | 72% | $(4.6) | $(1.76) |
| Q4 2008 | 1,702 | 76.79 | 2,610 | 65% | $(4.7) | $(1.82) |
Total 2008(1) | 7,277 | $75.24 | 10,500 | 69% | $(17.2) | $(1.65) |
Total 2009(1) | 8,030 | $81.60 | 11,000 | 73% | — | — |
| (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 4,090 mbbls in 2008 and from $52.50 to $60.00 covering 7,483 mbbls in 2009. |
Note: Not shown above are written call options covering 2,564 mbbls of production in 2008 at a weighted average price of $82.50 for a weighted average premium of $3.17 and 2,555 mbbls of production in 2009 at a weighed average price of $82.14 for a weighted average premium of $4.98.