Exhibit 99.1
SCHEDULE “A”
CHESAPEAKE’S OUTLOOK AS OF DECEMBER 11, 2006
Quarter Ending December 31, 2006; Year Ending December 31, 2006; Year Ending December 31, 2007; and Year Ending December 31, 2008.
We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of December 11, 2006, we are using the following key assumptions in our projections for the fourth quarter of 2006, the full-year 2006, the full-year 2007 and the full-year 2008.
The primary changes from our October 26, 2006 Outlook are in italicized bold in the table and are explained as follows:
1) | We have updated the projected effect of changes in our hedging positions; |
2) | We have updated for our €600 million Senior Note Offering; and |
3) | We have updated for our 30 million share Common Stock offering announced on December 7, 2006. |
Quarter Ending 12/31/2006 | Year Ending 12/31/2006 | Year Ending 12/31/2007 | Year Ending 12/31/2008 | |||||
Estimated Production | ||||||||
Oil – mbbls | 2,100 | 8,500 | 8,500 | 8,500 | ||||
Natural gas – bcf | 139 – 141 | 527 – 529 | 614 – 624 | 696 – 706 | ||||
Natural gas equivalent – bcfe | 151.5 – 153.5 | 578 – 580 | 665 – 675 | 747 – 757 | ||||
Daily natural gas equivalent midpoint – in mmcfe | 1,658 | 1,586 | 1,836 | 2,055 | ||||
NYMEX Prices (a) (for calculation of realized hedging effects only): | ||||||||
Oil - $/bbl | $58.26 | $65.73 | $56.25 | $56.25 | ||||
Natural gas - $/mcf | $6.56 | $7.24 | $7.50 | $7.50 | ||||
Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | ||||||||
Oil - $/bbl | $6.52 | -$1.32 | $10.43 | $8.65 | ||||
Natural gas - $/mcf | $3.17 | $2.59 | $1.62 | $1.02 | ||||
Estimated Differentials to NYMEX Prices: | ||||||||
Oil - $/bbl | 6 – 8% | 7 – 9% | 6 – 8% | 6 – 8% | ||||
Natural gas - $/mcf | 8 – 12% | 10 – 15% | 9 – 13% | 9 – 13% | ||||
Operating Costs per Mcfe of Projected Production: | ||||||||
Production expense | $0.85 – 0.95 | $0.85 – 0.90 | $0.90 – 1.00 | $0.90 – 1.00 | ||||
Production taxes (generally 6.0% of O&G revenues) (b) | $0.36 – 0.40 | $0.35 – 0.40 | $0.41 – 0.46 | $0.41 – 0.46 | ||||
General and administrative | $0.17 – 0.22 | $0.15 – 0.20 | $0.20 – 0.25 | $0.22 – 0.27 | ||||
Stock-based compensation (non-cash) | $0.10 – 0.11 | $0.06 – 0.08 | $0.08 – 0.10 | $0.08 – 0.10 | ||||
DD&A of oil and natural gas assets | $2.35 – 2.40 | $2.30 – 2.35 | $2.40 – 2.50 | $2.40 – 2.50 | ||||
Depreciation of other assets | $0.19 – 0.23 | $0.18 – 0.22 | $0.24 – 0.28 | $0.28 – 0.32 | ||||
Interest expense(c) | $0.58 – 0.62 | $0.54 – 0.58 | $0.60 – 0.65 | $0.60 – 0.65 | ||||
Other Income per Mcfe: | ||||||||
Oil and natural gas marketing income | $0.02 – 0.04 | $0.06 – 0.08 | $0.06 – 0.08 | $0.06 – 0.08 | ||||
Service operations income | $0.08 – 0.10 | $0.08 – 0.10 | $0.10 – 0.12 | $0.10 – 0.12 | ||||
Book Tax Rate (≈ 95% deferred) | 38% | 38% | 38% | 38% | ||||
Equivalent Shares Outstanding – in millions: | ||||||||
Basic | 426 | 398 | 453 | 458 | ||||
Diluted | 492 | 460 | 519 | 524 | ||||
Capital Expenditures – in millions: | ||||||||
Drilling, leasehold and seismic | $1,100 – 1,300 | $4,700 – 4,900 | $4,700 – 4,900 | $4,700 –4,900 |
(a) | Oil NYMEX prices have been updated for actual contract prices through November 2006 and natural gas NYMEX prices have been updated for actual contract prices through December 2006. |
(b) | Severance tax per mcfe is based on NYMEX prices of $58.26 per bbl of oil and $6.40 to $7.20 per mcf of natural gas during Q4 2006, $65.73 per bbl of oil and $6.20 to $7.20 per mcf of natural gas during calendar 2006, $56.25 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during calendar 2007 and 2008. |
(c) | 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, we receive a fixed price for the hedged commodity and pay a floating market price, as defined in each instrument, 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) | Basis protection swaps are arrangements that guarantee a price differential of oil or natural gas from a specified delivery point. 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. |
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 loses 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 non-qualifying 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.
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Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following opennatural gas swapsin place and also has the following gains fromlifted natural gas swaps:
Open Swaps in Bcf’s | Avg. NYMEX of Open Swaps | Assuming in Bcf’s of: | Open Swap Positions as a % of Estimated Total Natural Gas Production | Total Gains ($ millions) | Total Lifted Gain Total Natural Gas | |||||||||||
Q4 2006(1) | 58.3 | $ | 8.83 | 140.0 | 42 | % | $ | 237 | $ | 1.69 | ||||||
2007: | ||||||||||||||||
Q1 | 42.5 | $ | 10.16 | 143.2 | 30 | % | $ | 268 | $ | 1.87 | ||||||
Q2 | 21.7 | $ | 9.52 | 150.6 | 14 | % | $ | 96 | $ | 0.64 | ||||||
Q3 | 26.2 | $ | 9.63 | 159.2 | 16 | % | $ | 88 | $ | 0.55 | ||||||
Q4 | 26.2 | $ | 10.44 | 166.0 | 16 | % | $ | 113 | $ | 0.68 | ||||||
Total 2007(1) | 116.6 | $ | 9.98 | 619.0 | 19 | % | $ | 565 | $ | 0.91 | ||||||
Total 2008(1) | 236.6 | $ | 9.57 | 701.0 | 38 | % | $ | 85 | $ | 0.12 | ||||||
Total 2009 | 750.0 | $ | 4 | $ | 0.01 | |||||||||||
(1) | Certain hedging arrangements include swaps with knockout prices ranging from $3.75 to $5.50 covering 8.6 bcf in 2006, $5.30 to $6.50 covering 70.6 bcf in 2007 and $5.75 to $6.50 covering 76.9 bcf in 2008, respectively. |
Note: Not shown above are call options covering 1.8 bcf of production in 2006 at a weighted average price of $12.50, 7.3 bcf of production in 2007 at a weighted average price of $12.50 and 7.3 bcf of production in 2008 at a weighed average price of $12.50.
The company has the followingnatural gas basis protection swaps in place:
Mid-Continent | Appalachia | |||||||||
Volume in Bcf’s | NYMEX less*: | Volume in Bcf’s | NYMEX plus*: | |||||||
Q4 2006 | 36.8 | $ | 0.37 | — | $ | — | ||||
2007 | 141.7 | 0.34 | 36.5 | 0.35 | ||||||
2008 | 118.6 | 0.27 | 36.6 | 0.35 | ||||||
2009 | 86.6 | 0.29 | 18.2 | 0.31 | ||||||
Totals | 383.7 | $ | 0.31 | 91.3 | $ | 0.34 | ||||
* | 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 ($415 million as of September 30, 2006). 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 derivative instruments assumed in connection with the CNR acquisition 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.
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The following details theCNR derivatives (natural gas swaps) we have assumed:
Open Swaps in Bcf’s | Avg. NYMEX Strike Price Of Open (per Mcf) | Avg. Fair Value Upon (per Mcf) | Initial Liability (per Mcf) | Assuming in Bcf’s of: | Open Swap Positions as a % of Estimated Total Natural Gas Production | ||||||||||||
Q4 2006 | 10.6 | $ | 4.86 | $ | 10.38 | $ | (5.52 | ) | 140.0 | 8 | % | ||||||
2007: | |||||||||||||||||
Q1 | 10.3 | $ | 4.82 | $ | 10.97 | $ | (6.15 | ) | 143.2 | 7 | % | ||||||
Q2 | 10.5 | $ | 4.82 | $ | 8.48 | $ | (3.66 | ) | 150.6 | 7 | % | ||||||
Q3 | 10.6 | $ | 4.82 | $ | 8.45 | $ | (3.63 | ) | 159.2 | 7 | % | ||||||
Q4 | 10.6 | $ | 4.82 | $ | 8.87 | $ | (4.05 | ) | 166.0 | 6 | % | ||||||
Total 2007 | 42.0 | $ | 4.82 | $ | 9.18 | $ | (4.36 | ) | 619.0 | 7 | % | ||||||
Total 2008 | 38.4 | $ | 4.67 | $ | 8.01 | $ | (3.34 | ) | 701.0 | 5 | % | ||||||
Total 2009 | 18.3 | $ | 5.18 | $ | 7.28 | $ | (2.10 | ) | 750.0 | 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 $6.00, respectively.
The company also has the followingcrude oil swaps in place:
Open Swaps in mbbls | Avg. NYMEX Strike Price | Assuming Oil Production in | Open Swap of Estimated Total | Total Gains ($ millions) | Total Lifted Gain per bbl of Estimated Total Oil Production | |||||||||||
Q4 2006 | 1,530 | $ | 65.85 | 2,100 | 73 | % | $ | 1.7 | $ | 0.81 | ||||||
2007: | ||||||||||||||||
Q1 | 1,297 | $ | 71.43 | 2,095 | 62 | % | $ | 2.2 | $ | 1.05 | ||||||
Q2 | 1,456 | $ | 72.16 | 2,120 | 69 | % | — | — | ||||||||
Q3 | 1,472 | $ | 71.92 | 2,140 | 69 | % | — | — | ||||||||
Q4 | 1,472 | $ | 71.62 | 2,145 | 69 | % | — | — | ||||||||
Total 2007 | 5,697 | $ | 71.79 | 8,500 | 67 | % | $ | 2.2 | $ | 0.26 | ||||||
Total 2008 | 5,032 | $ | 71.45 | 8,500 | 59 | % | — | — | ||||||||
Total 2009 | 183 | $ | 66.10 | 8,500 | 2 | % | — | — | ||||||||
(1) | Certain hedging arrangements include swaps with knockout prices ranging from $40.00 to $60.00 covering 184 mbbls in 2006, $45.00 to $60.00 covering 1,460 mbbls in 2007 and $45.00 to $60.00 covering 1,098 mbbls in 2008, respectively. |
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SCHEDULE “B”
CHESAPEAKE’S PREVIOUS OUTLOOK AS OF OCTOBER 26, 2006
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY CHESAPEAKE’S OUTLOOK AS OF DECEMBER 11, 2006
Quarter Ending December 31, 2006; Year Ending December 31, 2006; Year Ending December 31, 2007; and Year Ending December 31, 2008.
We have adopted a policy of periodically providing investors with guidance on certain factors that affect our future financial performance. As of October 26, 2006, we are using the following key assumptions in our projections for the fourth quarter of 2006, the full-year 2006, the full-year 2007 and the full-year 2008.
The primary changes from our July 27, 2006 Outlook are in italicized bold in the table and are explained as follows:
1) | We have updated the projected effect of changes in our hedging positions; |
2) | Production, certain costs and capital expenditure assumptions have been updated; and |
3) | We have shown our projections for the quarter ending December 31, 2006 and for the year ending December 31, 2008 for the first time. |
Quarter Ending 12/31/2006 | Year Ending 12/31/2006 | Year Ending 12/31/2007 | Year Ending 12/31/2008 | |||||
Estimated Production | ||||||||
Oil – mbbls | 2,100 | 8,500 | 8,500 | 8,500 | ||||
Natural gas – bcf | 139 – 141 | 527 – 529 | 614 – 624 | 696 – 706 | ||||
Natural gas equivalent – bcfe | 151.5 – 153.5 | 578 – 580 | 665 – 675 | 747 – 757 | ||||
Daily natural gas equivalent midpoint – in mmcfe | 1,658 | 1,586 | 1,836 | 2,055 | ||||
NYMEX Prices (a) (for calculation of realized hedging effects only): | ||||||||
Oil - $/bbl | $56.25 | $65.23 | $56.25 | $56.25 | ||||
Natural gas - $/mcf | $6.40 | $7.20 | $7.50 | $7.50 | ||||
Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | ||||||||
Oil - $/bbl | $8.07 | -$1.03 | $10.42 | $8.65 | ||||
Natural gas - $/mcf | $3.07 | $2.42 | $1.80 | $1.09 | ||||
Estimated Differentials to NYMEX Prices: | ||||||||
Oil - $/bbl | 6 – 8% | 7 – 9% | 6 – 8% | 6 – 8% | ||||
Natural gas - $/mcf | 8 – 12% | 10 – 15% | 9 – 13% | 9 – 13% | ||||
Operating Costs per Mcfe of Projected Production: | ||||||||
Production expense | $0.85 – 0.95 | $0.85 – 0.90 | $0.90 – 1.00 | $0.90 – 1.00 | ||||
Production taxes (generally 6.0% of O&G revenues) (b) | $0.36 – 0.40 | $0.35 – 0.40 | $0.41 – 0.46 | $0.41 – 0.46 | ||||
General and administrative | $0.17 – 0.22 | $0.15 – 0.20 | $0.20 – 0.25 | $0.22 – 0.27 | ||||
Stock-based compensation (non-cash) | $0.10 – 0.11 | $0.06 – 0.08 | $0.08 – 0.10 | $0.08 – 0.10 | ||||
DD&A of oil and natural gas assets | $2.35 – 2.40 | $2.30 – 2.35 | $2.40 – 2.50 | $2.40 – 2.50 | ||||
Depreciation of other assets | $0.19 – 0.23 | $0.18 – 0.22 | $0.24 – 0.28 | $0.28 – 0.32 | ||||
Interest expense(c) | $0.58 – 0.62 | $0.54 – 0.58 | $0.60 – 0.65 | $0.60 – 0.65 | ||||
Other Income per Mcfe: | ||||||||
Oil and natural gas marketing income | $0.02 – 0.04 | $0.06 – 0.08 | $0.06 – 0.08 | $0.06 – 0.08 | ||||
Service operations income | $0.08 – 0.10 | $0.08 – 0.10 | $0.10 – 0.12 | $0.10 – 0.12 | ||||
Book Tax Rate (≈ 95% deferred) | 38% | 38% | 38% | 38% | ||||
Equivalent Shares Outstanding – in millions: | ||||||||
Basic | 420 | 397 | 440 | 445 | ||||
Diluted | 486 | 459 | 505 | 510 | ||||
Capital Expenditures – in millions: | ||||||||
Drilling, leasehold and seismic | $1,100 – 1,300 | $4,700 – 4,900 | $4,700 – 4,900 | $4,700 – 4,900 |
(a) | Oil NYMEX prices have been updated for actual contract prices through September 2006 and natural gas NYMEX prices have been updated for actual contract prices through October 2006. |
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(b) | Severance tax per mcfe is based on NYMEX prices of $56.25 per bbl of oil and $6.40 to $7.20 per mcf of natural gas during Q4 2006, $65.23 per bbl of oil and $6.20 to $7.20 per mcf of natural gas during calendar 2006, $56.25 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during calendar 2007 and 2008. |
(c) | 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, we receive a fixed price for the hedged commodity and pay a floating market price, as defined in each instrument, 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) | Basis protection swaps are arrangements that guarantee a price differential of oil or natural gas from a specified delivery point. 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. |
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 loses 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 non-qualifying 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.
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Excluding the swaps assumed in connection with the acquisition of CNR which are described below, the company currently has the following opennatural gas swapsin place and also has the following gains fromlifted natural gas swaps:
Open Swaps in Bcf’s | Avg. NYMEX of Open Swaps | Assuming in Bcf’s of: | Open Swap Positions as a % of Estimated Total Natural Gas Production | Total Gains ($ millions) | Total Lifted Gain Total Natural Gas | |||||||||||
Q4 2006(1) | 69.7 | $ | 8.91 | 140.0 | 50 | % | $ | 215 | $ | 1.54 | ||||||
2007: | ||||||||||||||||
Q1 | 95.0 | $ | 10.65 | 143.2 | 67 | % | $ | 109 | $ | 0.76 | ||||||
Q2 | 72.4 | $ | 8.95 | 150.6 | 48 | % | $ | 55 | $ | 0.37 | ||||||
Q3 | 73.1 | $ | 9.04 | 159.2 | 46 | % | $ | 56 | $ | 0.35 | ||||||
Q4 | 73.1 | $ | 9.71 | 166.0 | 44 | % | $ | 70 | $ | 0.42 | ||||||
Total 2007(1) | 313.6 | $ | 9.66 | 619.0 | 51 | % | $ | 290 | $ | 0.47 | ||||||
Total 2008(1) | 318.4 | $ | 9.53 | 701.0 | 45 | % | $ | 31 | $ | 0.04 | ||||||
Total 2009 | 750.0 | $ | 4 | $ | 0.01 | |||||||||||
(1) | Certain hedging arrangements include swaps with knockout prices ranging from $3.75 to $5.50 covering 8.6 bcf in 2006, $5.30 to $6.50 covering 72.2 bcf in 2007 and $5.75 to $6.50 covering 76.9 bcf in 2008, respectively. |
Note: Not shown above are call options covering 1.8 bcf of production in 2006 at a weighted average price of $12.50, 7.3 bcf of production in 2007 at a weighted average price of $12.50 and 7.3 bcf of production in 2008 at a weighed average price of $12.50.
The company has the followingnatural gas basis protection swaps in place:
Mid-Continent | Appalachia | |||||||||
Volume in Bcf’s | NYMEX less*: | Volume in Bcf’s | NYMEX plus*: | |||||||
Q4 2006 | 36.8 | $ | 0.37 | — | $ | — | ||||
2007 | 141.7 | 0.34 | 36.5 | 0.35 | ||||||
2008 | 118.6 | 0.27 | 36.6 | 0.35 | ||||||
2009 | 86.6 | 0.29 | 18.2 | 0.31 | ||||||
Totals | 383.7 | $ | 0.31 | 91.3 | $ | 0.34 | ||||
* | 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 ($415 million as of September 30, 2006). 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 derivative instruments assumed in connection with the CNR acquisition 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.
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The following details theCNR derivatives (natural gas swaps) we have assumed:
Open Swaps in Bcf’s | Avg. NYMEX Of Open (per Mcf) | Avg. Fair Value Upon (per Mcf) | Initial Liability (per Mcf) | Assuming in Bcf’s of: | Open Swap Positions as a % of Estimated Total Natural Gas Production | ||||||||||||
Q4 2006 | 10.6 | $ | 4.86 | $ | 10.38 | $ | (5.52 | ) | 140.0 | 8 | % | ||||||
2007: | |||||||||||||||||
Q1 | 10.3 | $ | 4.82 | $ | 10.97 | $ | (6.15 | ) | 143.2 | 7 | % | ||||||
Q2 | 10.5 | $ | 4.82 | $ | 8.48 | $ | (3.66 | ) | 150.6 | 7 | % | ||||||
Q3 | 10.6 | $ | 4.82 | $ | 8.45 | $ | (3.63 | ) | 159.2 | 7 | % | ||||||
Q4 | 10.6 | $ | 4.82 | $ | 8.87 | $ | (4.05 | ) | 166.0 | 6 | % | ||||||
Total 2007 | 42.0 | $ | 4.82 | $ | 9.18 | $ | (4.36 | ) | 619.0 | 7 | % | ||||||
Total 2008 | 38.4 | $ | 4.67 | $ | 8.01 | $ | (3.34 | ) | 701.0 | 5 | % | ||||||
Total 2009 | 18.3 | $ | 5.18 | $ | 7.28 | $ | (2.10 | ) | 750.0 | 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, respectively.
The company also has the followingcrude oil swaps in place:
Open Swaps in mbbls | Avg. Strike Price | Assuming Oil Production in mbbls of: | Open Swap Positions as a % of Estimated Total Oil Production | |||||||
Q4 2006 | 1,840 | $ | 65.64 | 2,100 | 88 | % | ||||
2007: | ||||||||||
Q1 | 1,710 | $ | 70.21 | 2,095 | 82 | % | ||||
Q2 | 1,456 | $ | 72.16 | 2,120 | 69 | % | ||||
Q3 | 1,472 | $ | 71.92 | 2,140 | 69 | % | ||||
Q4 | 1,472 | $ | 71.62 | 2,145 | 69 | % | ||||
Total 2007 | 6,110 | $ | 71.42 | 8,500 | 72 | % | ||||
Total 2008 | 5,032 | $ | 71.45 | 8,500 | 59 | % | ||||
Total 2009 | 183 | $ | 66.10 | 8,500 | 2 | % | ||||
(1) | Certain hedging arrangements include swaps with knockout prices ranging from $40.00 to $60.00 covering 184 mbbls in 2006, $45.00 to $60.00 covering 1,460 mbbls in 2007 and $45.00 to $60.00 covering 1,098 mbbls in 2008, respectively. |
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