Press Releases
OKLAHOMA CITY, OKLAHOMA, FEBRUARY 22, 2011 – Chesapeake Energy Corporation (NYSE:CHK) today announced financial and operational results for the 2010 fourth quarter and full year. For the 2010 fourth quarter, Chesapeake reported net income to common stockholders of $180 million ($0.28 per fully diluted common share) and operating cash flow (defined as cash flow from operating activities before changes in assets and liabilities) of $1.186 billion on revenue of $1.975 billion and production of 269 billion cubic feet of natural gas equivalent (bcfe). For the 2010 full year, Chesapeake reported net income to common stockholders of $1.663 billion ($2.51 per fully diluted common share) and operating cash flow of $4.548 billion on revenue of $9.366 billion and production of 1.035 trillion cubic feet of natural gas equivalent (tcfe).
The company's 2010 fourth quarter and full year results include realized natural gas and oil hedging gains of $571 million and $2.056 billion, respectively. The results also include various items that are typically not included in published estimates of the company's financial results by certain securities analysts. Excluding the items detailed below, for the 2010 fourth quarter, Chesapeake reported adjusted net income to common stockholders of $478 million ($0.70 per fully diluted common share) and adjusted ebitda of $1.274 billion and, for the 2010 full year, Chesapeake reported adjusted net income to common stockholders of $1.971 billion ($2.95 per fully diluted common share) and adjusted ebitda of $5.083 billion. The excluded items and their effects on the 2010 fourth quarter and full year reported results are detailed as follows:
- a net unrealized after-tax mark-to-market loss of $392 million for the 2010 fourth quarter and $364 million for the full year resulting from the company's natural gas, oil and interest rate hedging programs;
- a net after-tax gain of $95 million for the 2010 fourth quarter and $84 million for the full year related to the sale of certain of the company's fixed assets;
- an after-tax gain of $74 million for the full year associated with certain equity investments where the investee sold additional equity to third parties at a price in excess of the company's basis;
- an after-tax loss of $80 million for the full year related to the redemption or exchange of certain of the company's senior notes;
- an after-tax charge of $1 million for the 2010 fourth quarter and $22 million for the full year for the impairment of certain of the company's assets.
The various items described above do not materially affect the calculation of operating cash flow. A reconciliation of operating cash flow, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 17 – 22 of this release.
Key Operational and Financial Statistics Summarized
The table below summarizes Chesapeake's key results during the 2010 fourth quarter and compares them to results during the 2010 third quarter and the 2009 fourth quarter and also compares the 2010 full year to the 2009 full year.
2010 Full Year Average Daily Production Increases 14% over 2009 Full Year Average Daily Production, Setting Record for 21st Consecutive Year
Chesapeake's daily production for the 2010 fourth quarter averaged 2.920 bcfe, a decrease of 4% from the 3.043 bcfe produced per day in the 2010 third quarter and an increase of 12% over the 2.618 bcfe of daily production in the 2009 fourth quarter. At the end of the 2010 third quarter, the company sold future production through a volumetric production payment covering a portion of its Barnett Shale assets, including approximately 350 million cubic feet of natural gas equivalent (mmcfe) per day of production in the 2010 fourth quarter. Excluding this sale, the company's 2010 fourth quarter production would have increased 7% sequentially and 25% year over year. Chesapeake's average daily production of 2.920 bcfe for the 2010 fourth quarter consisted of approximately 2.558 billion cubic feet of natural gas (bcf) (88% on a natural gas equivalent basis) and 60,457 barrels (bbls) of oil and natural gas liquids (NGLs) (12% on a natural gas equivalent basis). For the 2010 fourth quarter, the company's year over year growth rate of natural gas production was 5% and its year over year growth rate of oil and NGLs production was 103%.
The company's daily production for the 2010 full year averaged 2.836 bcfe, an increase of 14% over the 2.481 bcfe of daily production for the 2009 full year. Chesapeake's average daily production for the 2010 full year of 2.836 bcfe consisted of 2.534 bcf (89% on a natural gas equivalent basis) and 50,397 bbls (11% on a natural gas equivalent basis). The 2010 full year was Chesapeake's 21st consecutive year of sequential production growth. Chesapeake anticipates delivering a production growth rate of 25% over the next two years, net of property divestitures pursuant to its 25/25 Plan discussed on page 7 of this release.
Proved Natural Gas and Oil Reserves Increase by 2.8 Tcfe, or 20% for the 2010 Full Year to 17.1 Tcfe; Company Adds Proved Reserves of 5.1 Tcfe through the Drillbit in 2010 at a Drilling and Completion Cost of $1.07 per Mcfe
During 2010, Chesapeake continued the industry's most active drilling program, drilling 1,445 gross operated wells (938 net wells with an average working interest of 65%) and participating in another 1,586 gross wells operated by other companies (211 net wells with an average working interest of 13%). The company's drilling success rate was 98% for both company-operated and non-operated wells. During 2010, Chesapeake's drilling and completion costs include the benefit of approximately $1.151 billion of drilling and completion carries from its joint venture partners.
The following table compares Chesapeake's December 31, 2010 proved reserves, the increase over its year-end 2009 proved reserves, reserve replacement ratio, estimated future net cash flows from proved reserves (discounted at an annual rate of 10% before income taxes (PV-10)), and proved developed percentage based on the trailing 12-month average price required under SEC rules and the 10-year average NYMEX strip prices at December 31, 2010.
The following table summarizes Chesapeake's development costs for 2010 full year using the two pricing methods described above.
A complete reconciliation of proved reserves and reserve replacement ratios based on these two alternative pricing methods, along with total costs, is presented on pages 12 and 13 of this release. Also, a reconciliation of PV-10 to the standardized measure is presented on page 14 of this release.
In addition to the PV-10 value of its proved reserves, the company also has substantial value in its undeveloped leasehold, particularly in the Haynesville, Marcellus, Barnett, Bossier and Fayetteville unconventional natural gas shale plays and the company's unconventional liquids-rich plays, particularly in the Granite Wash, Cleveland, Tonkawa and Mississippian plays of the Anadarko Basin; the Eagle Ford Shale in South Texas; the Niobrara Shale in the Powder River and Denver-Julesburg (DJ) basins; the Avalon, Bone Spring, Wolfcamp and Wolfberry plays in the Permian Basin; and various plays in the Williston Basin.
Additionally, the net book value of the company's other assets (including gathering systems, compressors, land and buildings, investments and other non-current assets) was $6.1 billion as of December 31, 2010, compared to $6.7 billion as of December 31, 2009. The decline in other assets is primarily due to the deconsolidation of the company's midstream joint venture reflecting the implementation of new accounting guidance for certain investments and the sale of the company's Springridge natural gas gathering system and related facilities to our affiliate, Chesapeake Midstream Partners, L.P.
Chesapeake's Leasehold and 3-D Seismic Inventories Total 13.3 Million Net Acres and 27.9 Million Acres, Respectively; Risked Unproved Resources in the Company's Inventory Total 103 Tcfe
Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (13.3 million net acres) and 3-D seismic (27.9 million acres) in the U.S. This position includes the largest inventory of U.S. natural gas shale play leasehold (2.5 million net acres) as well as the largest combined leasehold position in two of the three largest new unconventional liquids-rich plays in the U.S. – the Eagle Ford Shale and the Niobrara Shale.
On its total leasehold inventory, pro forma for the company's recently announced sale of its Fayetteville Shale assets and the Powder River and DJ Basin cooperation agreement with CNOOC International Limited (CNOOC), a wholly owned subsidiary of CNOOC Limited (NYSE:CEO; SEHK:00883), Chesapeake has identified an estimated 15.2 tcfe of proved reserves (using volume estimates based on the 10-year average NYMEX strip prices at December 31, 2010), 103 tcfe of risked unproved resources and 269 tcfe of unrisked unproved resources. Pro forma for the Fayetteville Shale sale, the company is currently using 149 operated drilling rigs to further develop its inventory of approximately 37,800 net drillsites. Of Chesapeake's 149 operated rigs, 85 are drilling wells primarily focused on unconventional natural gas plays (including 50 operated rigs benefiting from drilling carries) and 61 are drilling wells primarily focused on unconventional liquids-rich plays (including 23 operated rigs benefiting from drilling carries) and 3 operated rigs are drilling in other plays. In addition, 143 of the company's 149 operated rigs are drilling horizontal wells.
In recognition of the value gap between oil and natural gas prices, during the past two years Chesapeake has directed a significant portion of its technological and leasehold acquisition expertise to identify, secure and commercialize new unconventional liquids-rich plays. To date, Chesapeake has built leasehold positions and established production in multiple unconventional liquids-rich plays on approximately 4.1 million net leasehold acres with 5.2 billion barrels of oil equivalent (bboe) (30.9 tcfe) of risked unproved resources and 15.4 bboe (92.4 tcfe) of unrisked unproved resources. As a result of its success to date, Chesapeake expects to increase its oil and natural gas liquids production through its drilling activities to more than 150,000 bbls per day, or 20%-25% of total production, by year-end 2012 and to more than 250,000 bbls per day, or 30%-35% of total production, through organic growth by year-end 2015.
The following table summarizes Chesapeake's ownership and activity in its unconventional natural gas shale plays, its unconventional liquids-rich plays and its other conventional and unconventional plays. Chesapeake uses a probability-weighted statistical approach to estimate the potential number of drillsites and unproved resources associated with such drillsites.
Average Realized Prices, Hedging Results and Hedging Positions Detailed
Average prices realized during the 2010 fourth quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.22 per thousand cubic feet of natural gas (mcf) and $62.62 per bbl, for a realized natural gas equivalent price of $5.87 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains from natural gas and oil hedging activities during the 2010 fourth quarter generated a $2.39 gain per mcf and a $1.43 gain per bbl for a 2010 fourth quarter realized hedging gain of $571 million, or $2.13 per mcfe.
By comparison, average prices realized during the 2009 fourth quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $6.05 per mcf and $71.61 per bbl, for a realized natural gas equivalent price of $6.45 per mcfe. Realized gains from natural gas and oil hedging activities during the 2009 fourth quarter generated a $2.42 gain per mcf and a $0.69 gain per bbl for a 2009 fourth quarter realized hedging gain of $544 million, or $2.26 per mcfe.
For the 2010 full year, average prices realized (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.57 per mcf and $62.71 per bbl, for a realized natural gas equivalent price of $6.09 per mcfe. Realized gains from natural gas and oil hedging activities during the 2010 full year generated a $2.14 gain per mcf and a $4.04 gain per bbl for a 2010 full year realized hedging gain of $2.056 billion, or $1.99 per mcfe.
By comparison, average prices realized during the 2009 full year (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.93 per mcf and $58.38 per bbl, for a realized natural gas equivalent price of $6.22 per mcfe. Realized gains from natural gas and oil hedging activities during the 2009 full year generated a $2.77 gain per mcf and a $2.78 gain per bbl for a 2009 full year realized hedging gain of $2.346 billion, or $2.59 per mcfe.
The company's realized cash hedging gains since January 1, 2001 have been $6.478 billion or $1.18 per mcfe.
Company Provides Update on Hedging Positions
To provide protection against potentially weak natural gas prices in 2011 and 2012, Chesapeake has entered into hedges for a portion of its production in those two years. Depending on changes in natural gas and oil futures markets and management's view of underlying natural gas and oil supply and demand trends, Chesapeake may increase or decrease some or all of its hedging positions at any time in the future without notice. The following table summarizes Chesapeake's 2011 and 2012 open swap positions as of February 22, 2011.
In addition to the open hedging positions disclosed above, as of February 22, 2011, the company had an additional $832 million and $42 million of net hedging gains on closed contracts and premiums collected on call options that will be realized in 2011 and 2012, respectively.
Assuming future NYMEX natural gas settlement prices average $4.50 and $5.50 per mcf for 2011 and 2012, respectively, and including the effect of the company's open hedges, closed contracts and previously collected call premiums, the company estimates its average NYMEX natural gas prices will be $5.98 and $5.62 per mcf for 2011 and 2012, respectively. Additionally, assuming future NYMEX oil settlement prices average $90.00 per bbl for 2011 and 2012, the company estimates its average NYMEX oil prices will be $89.28 and $89.60 per bbl for 2011 and 2012, respectively. These estimates do not include the effect of basis differentials and gathering costs.
Details of the company's quarter-end hedging positions, including sold call options, are provided in the company's Form 10-Q and Form 10-K filings with the SEC and current positions are disclosed in summary format in the company's Outlook. The company's updated forecasts for 2011 and 2012 are attached to this release in the Outlook dated February 22, 2011, labeled as Schedule "A," which begins on page 23. This Outlook has been changed from the Outlook dated November 3, 2010, attached as Schedule "B," which begins on page 27, to reflect various updated information.
Company Provides Update on 25/25 Plan
On January 6, 2011, Chesapeake announced its 25/25 Plan, which outlined the company's plan to reduce its long-term debt by 25% during 2011-12 while also growing net natural gas and oil production by 25% during these two years. The company expects to achieve the reduction in debt primarily with proceeds from asset sales and from substantially reduced leasehold spending during this period.
Two recently announced transactions reflect the company's substantial progress already made in implementing its 25/25 Plan. On February 11, 2011, the company closed its Niobrara Shale cooperation agreement through which CNOOC purchased a 33.3% undivided interest in Chesapeake's 800,000 net natural gas and oil leasehold acres in the DJ and Powder River Basins in Colorado and Wyoming for approximately $4,750 per net acre. The company received approximately $570 million in cash at closing, and CNOOC has agreed to fund 66.7% of Chesapeake's share of drilling and completion costs until an additional $697 million has been paid, which Chesapeake expects to occur by year-end 2014.
In addition, on February 21, 2011, Chesapeake announced an agreement to sell all its upstream and midstream assets in the Fayetteville Shale to BHP Billiton Petroleum, a wholly owned subsidiary of BHP Billiton Limited (NYSE:BHP; ASX:BHP), for $4.75 billion in cash before certain deductions and standard closing adjustments. The company anticipates the transaction will close in the first half of 2011.
2010 Fourth Quarter and Full Year Financial and Operational Results Conference Call Information
A conference call to discuss this release has been scheduled for Wednesday, February 23, 2011, at 11:00 a.m. EST. The telephone number to access the conference call is 913-981-5549 or toll-free 888-211-7383. The passcode for the call is 6147630. We encourage those who would like to participate in the call to dial the access number between 10:50 and 11:00 a.m. EST. For those unable to participate in the conference call, a replay will be available for audio playback from 3:00 p.m. EST on February 23, 2011, through midnight EST on March 9, 2011. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 6147630. The conference call will also be webcast live on Chesapeake's website at www.chk.com in the "Events" subsection of the "Investors" section of the website. The webcast of the conference call will be available on Chesapeake's website for one year.
This news release and the accompanying Outlooks include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact and give our current expectations or forecasts of future events. They include estimates of natural gas and oil reserves and resources, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, planned drilling activity, drilling and completion costs and anticipated asset sales, projected cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures concerning the fair value of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this news release, and we undertake no obligation to update this information.
Factors that could cause actual results to differ materially from expected results are described under "Risks Related to Our Business" in our Prospectus Supplement filed with the U.S. Securities and Exchange Commission on February 9, 2011. These risk factors include the volatility of natural gas and oil prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the values of our natural gas and oil properties resulting in ceiling test write-downs; the availability of capital on an economic basis, including through planned asset monetization transactions, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the amount and timing of development expenditures; inability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; hedging activities resulting in lower prices realized on natural gas and oil sales; the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; a reduced ability to borrow or raise additional capital as a result of lower natural gas and oil prices; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business; general economic conditions negatively impacting us and our business counterparties; transportation capacity constraints and interruptions that could adversely affect our cash flow; and losses possible from pending or future litigation.
The SEC requires natural gas and oil companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of natural gas and oil that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. In this news release, we use the terms "risked and unrisked unproved resources" to describe Chesapeake's internal estimates of volumes of natural gas and oil that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques. These are broader descriptions of potentially recoverable volumes than probable and possible reserves, as defined by SEC regulations. Estimates of unproved resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the company. We believe our estimates of unproved resources are reasonable, but such estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.
Chesapeake Energy Corporation is the second-largest producer of natural gas and the most active driller of new wells in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S. Chesapeake owns leading positions in the Barnett, Fayetteville, Haynesville, Marcellus and Bossier natural gas shale plays and in the Eagle Ford, Granite Wash, Cleveland, Tonkawa, Mississippian, Wolfcamp, Bone Spring, Avalon, Niobrara and Williston Basin unconventional liquids plays. The company has also vertically integrated its operations and owns substantial midstream, compression, drilling and oilfield service assets. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information and presentations and all recent press releases
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:
- Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.
- 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.
- Put options: Chesapeake receives a premium from the counterparty in exchange for the sale of a put option. At the time of settlement, if the market prices falls below the fixed price of the put option, Chesapeake pays the counterparty such shortfall, and if the market price settles above the fixed price of the put option, no payment is due from either party.
- 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.
- 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. Since the latter half of 2009 through February 22, 2011, the company has taken advantage of attractive strip prices in 2012 through 2017 and sold natural gas and oil call options to its counterparties in exchange for 2010, 2011 and 2012 natural gas swaps with strike prices above the then current market price. This effectively allowed the company to sell out-year volatility through call options at terms acceptable to Chesapeake in exchange for straight natural gas swaps with strike prices in excess of the market price for natural gas at that time.
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, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in accumulated other comprehensive income until the hedged item is recognized in earnings as the physical transactions being hedged occur. Any change in fair value resulting from ineffectiveness is currently recognized in natural gas and oil sales as unrealized gains (losses). Realized gains (losses) are comprised of settled trades related to the production periods being reported. Unrealized gains (losses) are comprised of both temporary fluctuations in the mark-to-market values of non-qualifying trades and settled values of non-qualifying derivatives related to future production periods.
The company currently has the following open natural gas swaps in place for 2011 and 2012. In addition to the open swap positions disclosed below, at February 22, 2011, the company had $687 million of net hedging gains related to closed natural gas contracts and premiums collected on call options for future production periods.
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:
- Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.
- 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.
- 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.
- Put options: Chesapeake sells put options in exchange for a premium from the counterparty. At the time of settlement, if the market prices falls below the fixed price of the put option, Chesapeake pays the counterparty such shortfall, and if the market price settles above the fixed price of the put option, no payment is due from either party.
- 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.
- 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. In the latter half of 2009 and in 2010, the company took advantage of attractive strip prices in 2012 through 2016 and sold natural gas and oil call options to its counterparties in exchange for 2010 and 2011 natural gas swaps with strike prices above the then current market price. This effectively allowed the company to sell out-year volatility through call options at terms acceptable to Chesapeake in exchange for straight natural gas swaps with strike prices well in excess of the then current market price for natural gas.
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 (losses) from lifted natural gas trades:
