OKLAHOMA CITY, OKLAHOMA, NOVEMBER 3, 2011 – Chesapeake Energy Corporation (NYSE:CHK) today announced its 2011 third quarter financial and operational results. For the quarter, Chesapeake reported net income to common stockholders of $879 million ($1.23 per fully diluted common share), operating cash flow of $1.409 billion (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $2.013 billion (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization) on revenue of $3.977 billion and production of 306 billion cubic feet of natural gas equivalent (bcfe).
The company’s 2011 third quarter results include various items that are typically not included in published estimates of the company’s financial results by certain securities analysts. For the 2011 third quarter, Chesapeake reported adjusted net income to common stockholders of $496 million ($0.72 per fully diluted common share) and adjusted ebitda of $1.385 billion. The primary excluded item was a net unrealized after-tax mark-to-market gain of $385 million resulting from the company’s natural gas, liquids and interest rate hedging programs.
A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 16 – 20 of this release.
Key Operational and Financial Statistics Summarized
The table below summarizes Chesapeake’s key results during the 2011 third quarter and compares them to results during the 2011 second quarter and the 2010 third quarter.
2011 Third Quarter Average Daily Total Production of 3.329 Bcfe per Day Increases 9% Year over Year and 9% Sequentially; 2011 Third Quarter Liquids Production Increases 91% Year over Year and 21% Sequentially; 2011 Third Quarter Liquids Production Delivers 17% of Total Production and 40% of Unhedged Natural Gas and Liquids Revenue
Chesapeake’s daily production for the 2011 third quarter averaged 3.329 bcfe, an increase of 286 million cubic feet of natural gas equivalent (mmcfe), or 9%, over the 3.043 bcfe produced per day in the 2010 third quarter and an increase of 280 mmcfe, or 9%, from the 3.049 bcfe produced per day in the 2011 second quarter.
Chesapeake’s average daily production of 3.329 bcfe for the 2011 third quarter consisted of 2.763 billion cubic feet of natural gas (bcf) and 94,228 barrels (bbls) of oil and natural gas liquids (collectively, “liquids”). The company’s 2011 third quarter production of 306.2 bcfe was comprised of 254.2 bcf of natural gas (83% on a natural gas equivalent basis) and 8.7 million barrels of liquids (mmbbls) (17% on a natural gas equivalent basis). The company’s year-over-year growth rate of natural gas production was 1% while its year-over-year growth rate of liquids production was 91%. The company’s percentage of revenue from liquids in the 2011 third quarter was 40% of total unhedged natural gas and liquids revenue compared to 23% in the 2010 third quarter and 40% in the 2011 second quarter.
2011 Third Quarter Average Realized Prices Benefit from Realized Hedging Gains of $344 Million, or $1.12 per Mcfe
Average prices realized during the 2011 third quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $4.82 per thousand cubic feet (mcf) and $63.03 per bbl, for a realized natural gas equivalent price of $5.78 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains from natural gas hedging activities during the 2011 third quarter generated a $1.43 gain per mcf, while realized losses from liquids hedging activities generated a $2.26 loss per bbl, resulting in 2011 third quarter net realized hedging gains of $344 million, or $1.12 per mcfe.
By comparison, average prices realized during the 2010 third quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.20 per mcf and $59.81 per bbl, for a realized natural gas equivalent price of $5.67 per mcfe. Realized gains from natural gas and liquids hedging activities during the 2010 third quarter generated a $1.92 gain per mcf and a $5.56 gain per bbl, respectively, for 2010 third quarter realized hedging gains of $512 million, or $1.83 per mcfe.
The company’s realized cash hedging gains since January 1, 2006 have been $8.1 billion, or $1.64 on average for every mcfe produced
Company Provides Update on Hedging Positions
The following table summarizes Chesapeake’s 2011 and 2012 open swap positions as of November 3, 2011. Depending on changes in natural gas and oil futures markets and management’s view of underlying natural gas and liquids supply and demand trends, Chesapeake may increase or decrease some or all of its hedging positions at any time in the future without notice.
In addition to the open hedging positions disclosed above, as of November 3, 2011, the company had an additional $358 million, $294 million and $47 million of net hedging gains on closed contracts and premiums collected on call options that will be realized in 2011, 2012 and 2013, respectively, as set forth below.
Details of the company’s quarter-end hedging positions are available in the company’s Form 10-Q filing with the Securities and Exchange Commission (SEC) and current positions are disclosed in summary format in the company’s Outlook. The company’s updated forecasts for 2011, 2012 and 2013 are attached to this release in the Outlook dated November 3, 2011, labeled as Schedule “A,” which begins on page 21. The Outlook has been changed from the Outlook dated July 28, 2011, attached as Schedule “B,” which begins on page 25, to reflect various updated information.
Proved Natural Gas and Liquids Reserves Increased by 581 Bcfe, or 3%, in the First Three Quarters of 2011 to 17.7 Tcfe Despite the Sale of 2.8 Tcfe of Proved Reserves; Also in the First Three Quarters of 2011, Company Adds New Net Proved Reserves Before Sales of 4.2 Tcfe Through the Drillbit at a Cost of $1.08 per Proved Mcfe
The following table compares Chesapeake’s September 30, 2011 proved reserves, the increase versus its year-end 2010 proved reserves, 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 by the reserve reporting rules of the SEC and the 10-year average NYMEX strip prices at September 30, 2011.
The following table summarizes Chesapeake’s proved well costs for the first three quarters of 2011 using the two pricing methods described above.
A complete reconciliation of proved reserves based on these two alternative pricing methods, along with total costs, is presented on pages 12 and 13 of this release.
In addition to the PV-10 value of its proved reserves, the company also has significant value in its unevaluated properties, which had a book value of $16.4 billion as of September 30, 2011 and a likely value substantially in excess of book value. Furthermore, the net book value of the company’s other assets (including gathering systems, compressors, land and buildings, investments and other non-current assets) was $7.0 billion as of September 30, 2011, an increase of approximately $0.9 billion from December 31, 2010.
Chesapeake’s Leasehold and 3-D Seismic Inventories Total 15.0 Million Net Acres and 30.1 Million Acres, Respectively; Risked Unproved and Unrisked Unproved Resources in the Company’s Inventory Total 111 Tcfe and 338 Tcfe, Respectively
Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (15.0 million net acres) and 3-D seismic (30.1 million acres) in the U.S. The company has also accumulated the largest inventory of U.S. natural gas shale play leasehold (2.5 million net acres) and now owns a leading position in 12 of what Chesapeake believes are the Top 15 unconventional liquids-rich plays in the U.S. – the Granite Wash, Cleveland, Tonkawa and Mississippi Lime plays in the Anadarko Basin; the Avalon, Bone Spring, Wolfcamp and Wolfberry plays in the Permian Basin; the Eagle Ford Shale in South Texas; the Niobrara Shale in the Powder River and DJ Basins; the Bakken/Three Forks in the Williston Basin; and the Utica Shale in the Appalachian Basin.
On its leasehold inventory, Chesapeake has identified an estimated 18.5 trillion cubic feet of natural gas equivalent (tcfe) of proved reserves (using volume estimates based on the 10-year average NYMEX strip prices at September 30, 2011), 111 tcfe of risked unproved resources and 338 tcfe of unrisked unproved resources. The company is currently using 171 operated drilling rigs to further develop its inventory of approximately 38,700 net risked drillsites. Of Chesapeake’s 171 operated rigs, 105 are drilling wells primarily focused on unconventional liquids-rich plays, 63 are drilling wells primarily focused on unconventional natural gas plays and three are drilling conventional natural gas plays. The company has reduced its natural gas-directed activity by 18 rigs from July 2011 and by 31 rigs from January 2011. In addition, 165 of Chesapeake’s 171 operated rigs are drilling horizontal wells.
In recognition of the value gap between liquids and natural gas prices, Chesapeake has directed a significant portion of its technological and leasehold acquisition expertise during the past three years to identify, secure and commercialize new unconventional liquids-rich plays. To date, Chesapeake has built leasehold positions and established production in multiple liquids-rich plays on approximately 6.2 million net leasehold acres with 7.0 billion bbls of oil equivalent (bboe) (or 42 tcfe) of risked unproved resources and 27.0 bboe (or 162 tcfe) of unrisked unproved resources based on the company’s internal estimates. As a result of its success to date, Chesapeake expects to increase its liquids production through its drilling activities to an average of approximately 150,000 bbls per day in 2012, 200,000 bbls per day in 2013 and 250,000 bbls per day in 2015. Previously, these volume estimates were for year-end exit rates and have been recently revised to full-year averages because of the company’s ongoing success in increasing its liquids production rates.
The following table summarizes Chesapeake’s ownership and activity in its unconventional natural gas plays, unconventional liquids-rich plays and 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.
Conference Call Information
A conference call to discuss this release has been scheduled for Friday, November 4, 2011 at 9:00 a.m. EDT. The telephone number to access the conference call is 913-312-1463 or toll-free 888-778-8861. The passcode for the call is 5544489. We encourage those who would like to participate in the call to dial the access number between 8:50 and 9:00 a.m. EDT. For those unable to participate in the conference call, a replay will be available for audio playback from 1:00 p.m. EDT on Friday, November 4, 2011 through midnight on November 18, 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 5544489. 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.
Chesapeake Energy Corporation is the second-largest producer of natural gas, a Top 15 producer of oil and natural gas liquids 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, Haynesville, Bossier, Marcellus and Pearsall natural gas shale plays and in the Granite Wash, Cleveland, Tonkawa, Mississippi Lime, Bone Spring, Avalon, Wolfcamp, Wolfberry, Eagle Ford, Niobrara, Three Forks/Bakken and Utica unconventional liquids plays. The company has also vertically integrated its operations and owns substantial midstream, compression, drilling, trucking, pressure pumping and other oilfield service assets directly and indirectly through its subsidiaries Chesapeake Midstream Development, L.P. and Chesapeake Oilfield Services, L.L.C. and its affiliate Chesapeake Midstream Partners, L.P. (NYSE:CHKM). Chesapeake’s stock is listed on the New York Stock Exchange under the symbol CHK. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and press releases.
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 give our current expectations or forecasts of future events. They include estimates of natural gas and liquids reserves and resources, expected natural gas and liquids production and future expenses, assumptions regarding future natural gas and oil prices, planned drilling activity and well costs, projected cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures of the estimated realized effects of our current hedging positions on future natural gas and liquids sales are based upon market prices that 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 “Risk Factors” in our 2010 Form 10-K filed with the U.S. Securities and Exchange Commission on March 1, 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 liquids properties resulting in ceiling test write-downs; the availability of capital on an economic basis, including 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 liquids 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 liquids 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 revenues and cash flow; and adverse results in pending or future litigation.
Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.
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 liquids 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 liquids 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. The company calculates the standardized measure of future net cash flows of proved reserves only at year end because applicable income tax information on properties, including recently acquired natural gas and liquids interests, is not readily available at other times during the year. As a result, the company is not able to reconcile interim period-end PV-10 values to the standardized measure at such dates. The only difference between the two measures is that PV-10 is calculated before considering the impact of future income tax expenses, while the standardized measure includes such effects. Year-end standardized measure calculations are provided in the financial statement notes in our annual reports on Form 10-K.
Commodity Hedging Activities
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. Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the Securities and Exchange Commission for detailed information about derivative instruments the company uses, its quarter-end natural gas and oil derivative positions and the accounting for commodity derivatives.
At November 3, 2011, the company does not have any open natural gas swaps in place. The company currently has $616 million of net hedging gains related to closed natural gas contracts and premiums collected on call options for future production periods.
The company currently has the following natural gas written call options in place for 2011 through 2020:
The company has the following natural gas basis protection swaps in place for 2011 through 2022
At November 3, 2011, the company has the following open crude oil swaps in place for 2011 and through 2015. In addition, the company has $93 million of net hedging gains related to closed crude oil contracts and premiums collected on call options for future production periods.
The company currently has the following crude oil written call options in place for 2011 through 2017:
Commodity Hedging Activities
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. The company utilizes the following types of natural gas and oil derivative instruments:
- ake 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 price.
- 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 June 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 natural gas swaps with fixed prices in excess of the market price at the time.
Gains or losses from commodity derivative transactions are reflected as adjustments to natural gas and liquids sales. All realized gains (losses) from natural gas and oil derivatives are included in natural gas and liquids 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 liquids 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 nonqualifying trades and settled values of nonqualifying derivatives related to future production periods.
At July 28, 2011, the company has the following open natural gas swaps in place for 2011 and 2012. In addition, the company currently has $630 million of net hedging gains related to closed natural gas contracts and premiums collected on call options for future production periods.
The company currently has the following natural gas written call options in place for 2011 through 2020:
The company has the following natural gas basis protection swaps in place for 2011 through 2022:
At July 28, 2011, the company has the following open crude oil swaps in place for 2011 and 2012. In addition, the company has $60 million of net hedging gains related to closed crude oil contracts and premiums collected on call options for future production periods.
The company currently has the following crude oil written call options in place for 2011 through 2017:
SOURCE: Chesapeake Energy Corporation
Chesapeake Energy Corporation
Jeffrey L. Mobley, CFA, 405-767-4763
John J. Kilgallon, 405-935-4441
Michael Kehs, 405-935-2560
Jim Gipson, 405-935-1310