Exhibit 99.1
SCHEDULE “A”
CHESAPEAKE’S OUTLOOK AS OF OCTOBER 12, 2010
Years Ending December 31, 2010, 2011 and 2012
Our policy is to periodically provide guidance on certain factors that affect our future financial performance. As of October 12, 2010, we are using the following key assumptions in our projections for 2010, 2011 and 2012.
The primary changes from our August 3, 2010 Outlook are in italicized bold and are explained as follows:
| 1) | Our first projections for full-year 2012 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 have been updated; and |
| 5) | Our cash flow projections have been updated. |
Year Ending 12/31/2010 | Year Ending 12/31/2011 | Year Ending 12/31/2012 | |||
| Estimated Production: | |||||
Natural gas – bcf | 898 – 918 | 990 – 1,010 | 1,086 – 1,130 | ||
Oil – mbbls | 19,000 | 32,000 – 36,000 | 38,000 – 44,000 | ||
Natural gas equivalent – bcfe | 1,012 – 1,032 | 1,182 – 1,226 | 1,314 – 1,394 | ||
| Daily natural gas equivalent midpoint – mmcfe | 2,800 | 3,300 | 3,700 | ||
| Year-over-year (YOY) estimated production increase | 12 – 14% | 16 – 20% | 9 – 15% | ||
| YOY estimated production increase excluding asset sales | 20 – 22% | 19 – 23% | 10 – 16% | ||
NYMEX Price(a)(for calculation of realized hedging effects only): | |||||
Natural gas - $/mcf | $4.43 | $4.50 | $5.50 | ||
Oil - $/bbl | $76.99 | $80.00 | $80.00 | ||
| Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | |||||
Natural gas - $/mcf | $2.15 | $1.18 | $0.00 | ||
Oil - $/bbl | $5.02 | $2.72 | $1.43 | ||
| Estimated Differentials to NYMEX Prices: | |||||
Natural gas | 15 – 20% | 15 – 20% | 15 – 20% | ||
Oil | 20 – 25% | 20 – 25% | 20 – 25% | ||
| Operating Costs per Mcfe of Projected Production: | |||||
Production expense | $0.85 – 0.95 | $0.85 – 0.95 | $0.85 – 0.95 | ||
| Production taxes (~ 5% of O&G revenues) | $0.25 – 0.30 | $0.25 – 0.30 | $0.25 – 0.30 | ||
General and administrative(b) | $0.30 – 0.35 | $0.30 – 0.35 | $0.30 – 0.35 | ||
| Stock-based compensation (non-cash) | $0.09 – 0.11 | $0.09 – 0.11 | $0.09 – 0.11 | ||
| DD&A of natural gas and oil assets | $1.35 – 1.55 | $1.35 – 1.55 | $1.35 – 1.55 | ||
| Depreciation of other assets | $0.20 – 0.25 | $0.20 – 0.25 | $0.20 – 0.25 | ||
Interest expense(c) | $0.15 – 0.20 | $0.20 – 0.25 | $0.20 – 0.25 | ||
| Other Income per Mcfe: | |||||
| Marketing, gathering and compression net margin | $0.09 – 0.11 | $0.09 – 0.11 | $0.09 – 0.11 | ||
Service operations net margin | $0.02 – 0.04 | $0.02 – 0.04 | $0.02 – 0.04 | ||
Other income (including equity investments) | $0.06 – 0.08 | $0.06 – 0.08 | $0.06 – 0.08 | ||
| Book Tax Rate (all deferred) | 38.5% | 38.5% | 38.5% | ||
| Equivalent Shares Outstanding (in millions): | |||||
| Basic | 630 – 635 | 640 – 645 | 647 – 652 | ||
| Diluted | 705 – 710 | 750 – 755 | 757 – 762 | ||
Operating cash flow before changes in assets and liabilities(d)(e) | $4,800 – 4,900 | $4,900 – 5,300 | $4,900 – 5,700 | ||
| Drilling and completion costs, net of joint venture carries | $(4,500 – 4,600) | $(4,500 – 4,600) | $(4,500 – 4,600) | ||
| Note: refer to footnotes on following page | |||||
| (a) | NYMEX natural gas prices have been updated for actual contract prices through October 2010 and NYMEX oil prices have been updated for actual contract prices through September 2010. |
| (b) | Excludes expenses associated with noncash stock compensation. |
| (c) | Does not include gains or losses on interest rate derivatives. |
| (d) | 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. |
| (e) | Assumes NYMEX prices of $4.00 to $5.00 per mcf and $75.00 per bbl in 2010, $4.00 to $5.00 per mcf and $80.00 per bbl in 2011 and $5.00 to $6.00 per mcf and $80.00 per bbl in 2012. |
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. |
| 3) | Call options: Chesapeake sells call options in exchange for a premium from the counterparty. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess and if the market price settles below the fixed price of the call option, no payment is due from either party. |
| 4) | 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. |
| 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. In accordance with generally accepted accounting principles, 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., temporary fluctuations in value) are reported currently in the consolidated statement of operations as unrealized gains (losses) within natural gas and oil sales. 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 for 2010, 2011 and 2012 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 (Losses) from Lifted Trades ($ millions) | Total Lifted Gains (Losses) per Mcf of Estimated Total Natural Gas Production | ||||||||||||||
| Q3 2010 | 119 | $ | 7.46 | $ | 59.1 | ||||||||||||||
| Q4 2010 | 120 | $ | 7.70 | $ | 60.2 | ||||||||||||||
Q3-Q4 2010(a) | 239 | $ | 7.58 | 472 | 51% | $ | 119.3 | $ | 0.25 | ||||||||||
| Q1 2011 | 147 | $ | 6.85 | $ | 30.0 | ||||||||||||||
| Q2 2011 | 134 | $ | 6.56 | $ | 46.9 | ||||||||||||||
| Q3 2011 | 107 | $ | 6.76 | $ | 40.7 | ||||||||||||||
| Q4 2011 | 107 | $ | 6.79 | $ | 28.0 | ||||||||||||||
Total 2011(a) | 495 | $ | 6.74 | 1,000 | 50% | $ | 145.6 | $ | 0.15 | ||||||||||
| Total 2012 | 18 | $ | 6.50 | 1,108 | 2% | $ | (35.0) | $ | (0.03) | ||||||||||
| (a) | Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at prices ranging from $6.50 to $6.75 covering 5 bcf in Q3-Q4 2010 and $5.75 to $6.50 covering 24 bcf in 2011. |
The company currently has the following open natural gas collars in place for 2010 and 2011:
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 2010 | 4 | $ | 7.60 | $ | 11.75 | |||||||||
| Q4 2010 | 4 | $ | 7.60 | $ | 11.75 | |||||||||
| Q3-Q4 2010 | 8 | $ | 7.60 | $ | 11.75 | 472 | 2% | |||||||
| Q1 2011 | 2 | $ | 7.70 | $ | 11.50 | |||||||||
| Q2 2011 | 2 | $ | 7.70 | $ | 11.50 | |||||||||
| Q3 2011 | 2 | $ | 7.70 | $ | 11.50 | |||||||||
| Q4 2011 | 2 | $ | 7.70 | $ | 11.50 | |||||||||
| Total 2011 | 8 | $ | 7.70 | $ | 11.50 | 1,000 | 1% | |||||||
The company currently has the following natural gas written call options in place for 2010, 2011 and 2012:
Call Options (Bcf) | Avg. NYMEX Strike Price | Avg. Premium per mcf | Assuming Natural Gas Production (Bcf) | Call Options as a % of Estimated Total Natural Gas Production | ||||||||||
| Q3 2010 | 34 | $ | 10.01 | $ | 1.25 | |||||||||
| Q4 2010 | 34 | $ | 10.08 | $ | 1.25 | |||||||||
| Q3-Q4 2010 | 68 | $ | 10.04 | $ | 1.25 | 472 | 14% | |||||||
| Q1 2011 | 22 | $ | 8.57 | $ | 0.46 | |||||||||
| Q2 2011 | 22 | $ | 8.57 | $ | 0.46 | |||||||||
| Q3 2011 | 23 | $ | 8.57 | $ | 0.46 | |||||||||
| Q4 2011 | 23 | $ | 8.57 | $ | 0.46 | |||||||||
| Total 2011 | 90 | $ | 8.57 | $ | 0.46 | 1,000 | 9% | |||||||
| Total 2012 | 161 | $ | 6.54 | $ | 0.11 | 1,108 | 15% | |||||||
The company has the following natural gas basis protection swaps in place for 2010, 2011 and 2012:
| Non-Appalachia | Appalachia | |||||||||||
| Volume (Bcf) | NYMEX less(a) | Volume (Bcf) | NYMEX plus(a) | |||||||||
| Q3-Q4 2010 | — | $ | — | 5 | $ | 0.26 | ||||||
| 2011 | 45 | $ | 0.82 | 49 | $ | 0.14 | ||||||
| 2012 | 43 | $ | 0.85 | — | $ | — | ||||||
Totals | 88 | $ | 0.84 | 54 | $ | 0.16 | ||||||
| (a) | weighted average |
The company also has the following crude oil swaps in place for 2010, 2011 and 2012:
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 2010 | 2,300 | $ | 89.62 | — | — | $ | (4.1 | ) | — | ||||||||
| Q4 2010 | 2,300 | $ | 89.62 | — | — | $ | (4.1 | ) | — | ||||||||
Q3-Q4 2010(a) | 4,600 | $ | 89.62 | 10,700 | 43% | $ | (8.2 | ) | $ | (0.76) | |||||||
| Q1 2011 | 810 | $ | 96.09 | — | — | $ | 7.3 | — | |||||||||
| Q2 2011 | 819 | $ | 96.09 | — | — | $ | 7.3 | — | |||||||||
| Q3 2011 | 828 | $ | 96.09 | — | — | $ | 7.4 | — | |||||||||
| Q4 2011 | 828 | $ | 96.09 | — | — | $ | 7.4 | — | |||||||||
Total 2011(a) | 3,285 | $ | 96.09 | 34,000 | 10% | $ | 29.4 | $ | 0.86 | ||||||||
Total 2012(a) | 732 | $ | 109.50 | 41,000 | 2% | $ | 29.3 | $ | 0.72 | ||||||||
| (a) | Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 2 mmbbls, 1 mmbbls and 1 mmbbls in Q3-Q4 2010, 2011 and 2012, respectively. |
Note: Not shown above are written call options covering 1 mmbbls of oil production in Q3-Q4 2010 at a weighted average price of $101.25 per bbl for a weighted average discount of $1.93 per bbl, 8 mmbbls of oil production in 2011 at a weighted average price of $84.57 per bbl for a weighted average premium of $1.86 per bbl and 9 mmbbls of oil production in 2012 at a weighted average price of $87.00 per bbl for a weighted average premium of $1.70 per bbl.
SCHEDULE “B”
CHESAPEAKE’S OUTLOOK AS OF AUGUST 3, 2010
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF OCTOBER 12, 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 August 3, 2010, we are using the following key assumptions in our projections for 2010 and 2011.
The primary changes from our May 4, 2010 Outlook are in italicized bold and are explained as follows:
| 1) | Our production guidance has been increased; |
| 2) | Projected effects of changes in our hedging positions have been updated; |
| 3) | Equivalent shares outstanding and interest expense has been updated to reflect our private placement of $2.6 billion of preferred stock and the calling and subsequent repayment of certain senior notes; and |
| 4) | Our cash flow projections and drilling and completion capital expenditures have been updated. |
Year Ending 12/31/2010 | Year Ending 12/31/2011 | |||
| Estimated Production: | ||||
| Natural gas – bcf | 898 – 918 | 990 – 1,010 | ||
| Oil – mbbls | 19,000 | 34,000 | ||
| Natural gas equivalent – bcfe | 1,012 – 1,032 | 1,194 – 1,214 | ||
| Daily natural gas equivalent midpoint – mmcfe | 2,800 | 3,300 | ||
| Year-over-year (YOY) estimated production increase | 12 – 14% | 17 – 19% | ||
| YOY estimated production increase excluding asset sales | 20 – 22% | 19 – 21% | ||
NYMEX Price(a) (for calculation of realized hedging effects only): | ||||
| Natural gas - $/mcf | $4.97 | $5.50 | ||
| Oil - $/bbl | $79.19 | $80.00 | ||
| Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | ||||
| Natural gas - $/mcf | $1.88 | $0.62 | ||
| Oil - $/bbl | $3.98 | $2.81 | ||
| Estimated Differentials to NYMEX Prices: | ||||
| Natural gas - $/mcf | 15 – 20% | 15 – 20% | ||
| Oil - $/bbl | 20 – 25% | 20 – 25% | ||
| Operating Costs per Mcfe of Projected Production: | ||||
| Production expense | $0.85 – 0.95 | $0.85 – 0.95 | ||
| Production taxes (~ 5% of O&G revenues) | $0.25 – 0.30 | $0.25 – 0.30 | ||
General and administrative(b) | $0.30 – 0.35 | $0.30 – 0.35 | ||
| Stock-based compensation (non-cash) | $0.09 – 0.11 | $0.09 – 0.11 | ||
| DD&A of natural gas and oil assets | $1.35 – 1.55 | $1.35 – 1.55 | ||
| Depreciation of other assets | $0.20 – 0.25 | $0.20 – 0.25 | ||
Interest expense(c) | $0.15 – 0.20 | $0.20 – 0.25 | ||
| Other Income per Mcfe: | ||||
| Marketing, gathering and compression net margin | $0.09 – 0.11 | $0.09 – 0.11 | ||
| Service operations net margin | $0.02 – 0.04 | $0.02 – 0.04 | ||
| Other income (including equity investments) | $0.06 – 0.08 | $0.06 – 0.08 | ||
| Book Tax Rate (all deferred) | 38.5% | 38.5% | ||
| Equivalent Shares Outstanding (in millions): | ||||
| Basic | 630 – 635 | 640 – 645 | ||
| Diluted | 705 – 710 | 750 – 755 | ||
Operating cash flow before changes in assets and liabilities(d)(e) | $4,900 – 5,000 | $5,000 – 5,600 | ||
| Drilling and completion costs, net of joint venture carries | $(4,500 – 4,600) | $(4,500 – 4,600) | ||
| Note: refer to footnotes on following page |
| (a) | NYMEX natural gas prices have been updated for actual contract prices through August 2010 and NYMEX oil prices have been updated for actual contract prices through June 2010. |
| (b) | Excludes expenses associated with noncash stock compensation. |
| (c) | Does not include gains or losses on interest rate derivatives. |
| (d) | 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. |
| (e) | Assumes NYMEX prices of $5.00 to $6.00 per mcf and $80.00 per bbl in 2010 and in 2011. |
At June 30, 2010, the company had approximately $2.8 billion of cash and cash equivalents and additional borrowing capacity under its two revolving bank credit facilities.
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. |
| 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 sells call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess and 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. In accordance with generally accepted accounting principles, 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 unrea lized gains (losses) within natural gas and oil sales. 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 for 2010 and 2011 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 2010 | 119 | $ | 7.46 | $ | 59.1 | ||||||||||||||
| Q4 2010 | 120 | $ | 7.70 | $ | 62.1 | ||||||||||||||
Q3-Q4 2010(a) | 239 | $ | 7.58 | 472 | 51% | $ | 121.2 | $ | 0.26 | ||||||||||
Total 2011(a) | 303 | $ | 7.39 | 1,000 | 30% | $ | 59.6 | $ | 0.06 | ||||||||||
| (a) | Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure at prices ranging from $6.50 to $6.75 covering 5 bcf in Q3-Q4 2010 and $5.75 to $6.50 covering 24 bcf in 2011. |
The company currently has the following open natural gas collars in place for 2010 and 2011:
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 2010 | 4 | $ | 7.60 | $ | 11.75 | |||||||||
| Q4 2010 | 4 | $ | 7.60 | $ | 11.75 | |||||||||
| Q3-Q4 2010 | 8 | $ | 7.60 | $ | 11.75 | 472 | 2% | |||||||
| Total 2011 | 7 | $ | 7.70 | $ | 11.50 | 1,000 | 1% | |||||||
The company currently has the following natural gas written call options in place for 2010 and 2011:
Call Options (Bcf) | Avg. NYMEX Strike Price | Avg. Premium per mcf | Assuming Natural Gas Production (Bcf) | Call Options as a % of Estimated Total Natural Gas Production | ||||||||||
| Q3 2010 | 34 | $ | 10.01 | $ | 1.25 | |||||||||
| Q4 2010 | 39 | $ | 10.07 | $ | 1.10 | |||||||||
| Q3-Q4 2010 | 73 | $ | 10.04 | $ | 1.17 | 472 | 15% | |||||||
| Total 2011 | 69 | $ | 9.51 | $ | 0.61 | 1,000 | 7% | |||||||
The company has the following natural gas basis protection swaps in place for 2010, 2011 and 2012:
| Non-Appalachia | Appalachia | |||||||||||
| Volume (Bcf) | NYMEX less(a) | Volume (Bcf) | NYMEX plus(a) | |||||||||
| Q3-Q4 2010 | — | $ | — | 5 | $ | 0.26 | ||||||
| 2011 | 45 | 0.82 | 12 | 0.25 | ||||||||
| 2012 | 43 | 0.85 | — | — | ||||||||
Totals | 88 | $ | 0.84 | 17 | $ | 0.25 | ||||||
| (a) | weighted average |
The company also has the following crude oil swaps in place for 2010 and 2011:
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 2010 | 2,300 | $ | 89.62 | — | — | $ | (4.1 | ) | — | ||||||||
| Q4 2010 | 2,300 | $ | 89.62 | — | — | $ | (4.1 | ) | — | ||||||||
Q3-Q4 2010(a) | 4,600 | $ | 89.62 | 10,700 | 43% | $ | (8.2 | ) | $ | (0.76 | ) | ||||||
Total 2011(a) | 3,285 | $ | 96.09 | 34,000 | 10% | $ | 32.9 | $ | 0.96 | ||||||||
| (a) | Certain hedging arrangements include knockout swaps with provisions limiting the counterparty’s exposure below prices of $60.00 covering 2 mmbbls and 1 mmbbls in Q3-Q4 2010 and 2011, respectively. |
Note: Not shown above are written call options covering 1 mmbbls of oil production in Q3-Q4 2010 at a weighted average price of $101.25 per bbl for a weighted average discount of $1.93 per bbl and 5 mmbbls of oil production in 2011 at a weighted average price of $88.08 per bbl for a weighted average premium of $3.29 per bbl.