Chesapeake Underscores Increased Production Results for 2Q


Barnett Shale Play
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Haynesville/Bossier Shale Play
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As announced on July 30, 2009, Chesapeake's daily production for the 2009 second quarter averaged 2.453 bcfe, an increase of 86 million cubic feet of natural gas equivalent (mmcfe), or 4%, over the 2.367 bcfe produced per day in the 2009 first quarter and an increase of 125 mmcfe, or 5%, over the 2.328 bcfe produced per day in the 2008 second quarter.

Adjusted for the company's 2009 voluntary production curtailments due to low natural gas and oil prices (which averaged approximately 74 mmcfe per day during the 2009 second quarter), the company's three 2008 volumetric production payment sales (which averaged approximately 139 mmcfe per day during the 2009 second quarter) and the estimated impact from the company's 2008 sales of Woodford Shale and Fayetteville Shale properties (which would have averaged approximately 81 mmcfe per day during the 2009 second quarter), Chesapeake's sequential and year-over-year production growth rates would have been 4% and 16%, respectively, after making similar adjustments to prior quarters. The company is not currently curtailing production, but may do so again later this summer or fall as market conditions dictate. The company also expects that rising pipeline and gathering system pressures during the next few months will likely result in involuntary natural gas production curtailments across the industry.

Chesapeake's average daily production for the 2009 second quarter consisted of 2.245 billion cubic feet of natural gas (bcf) and 34,637 barrels of oil and natural gas liquids (bbls). The company’s 2009 second quarter production of 223.2 bcfe was comprised of 204.3 bcf (92% on a natural gas equivalent basis) and 3.152 million barrels of oil and natural gas liquids (mmbbls) (8% on a natural gas equivalent basis).

Average Realized Prices, Hedging Results and Hedging Positions Detailed

Average prices realized during the 2009 second quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $5.56 per thousand cubic feet (mcf) and $56.72 per bbl, for a realized natural gas equivalent price of $5.89 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains from natural gas and oil hedging activities during the 2009 second quarter generated a $2.88 gain per mcf and a $3.13 gain per bbl for a 2009 second quarter realized hedging gain of $597 million, or $2.68 per mcfe. Without realized hedging gains, the company’s average realized prices for the 2009 second quarter would have been $2.68 per mcf and $53.59 per bbl, for a natural gas equivalent price of $3.21 per mcfe. Excluding hedging activity, Chesapeake’s average realized pricing basis differentials to NYMEX during the 2009 second quarter were a negative $0.83 per mcf and a negative $6.03 per bbl.

By comparison, average prices realized during the 2008 second quarter (including realized gains or losses from natural gas and oil derivatives, but excluding unrealized gains or losses on such derivatives) were $8.18 per mcf and $76.96 per bbl, for a realized natural gas equivalent price of $8.55 per mcfe. Realized losses from natural gas and oil hedging activities during the 2008 second quarter generated a $1.55 loss per mcf and a $42.85 loss per bbl for a 2008 second quarter realized hedging loss of $423 million, or $1.99 per mcfe. Without realized hedging gains, the company’s average realized prices for the 2008 second quarter would have been $9.73 per mcf and $119.81 per bbl, for a natural gas equivalent price of $10.54 per mcfe. Excluding hedging activity, Chesapeake's average realized pricing basis differentials to NYMEX during the 2008 second quarter were a negative $1.21 per mcf and a negative $4.17 per bbl.

Company Increases Proved Natural Gas and Oil Reserves by 0.7 Tcfe to 12.5 Tcfe and Delivers 2009 Second Quarter Drilling and Net Acquisition Costs of $0.72 per Mcfe; Company Record Set for Organic Reserve Additions and Reserve Replacement During a Six-Month Period

Chesapeake began the 2009 second quarter with estimated proved reserves of 11.851 trillion cubic feet of natural gas equivalent (tcfe) and ended the 2009 second quarter with 12.525 tcfe, an increase of 674 bcfe, or 6%. During the 2009 second quarter, Chesapeake replaced 223 bcfe of production with an estimated 897 bcfe of new proved reserves for a reserve replacement rate of 402%. The quarter's reserve movement included 493 bcfe of extensions, 343 bcfe of positive performance revisions, 156 bcfe of positive revisions resulting from natural gas and oil price increases between March 31, 2009 and June 30, 2009 and 95 bcfe of net divestitures.

Chesapeake's total drilling and net acquisition costs for the 2009 second quarter were $0.72 per mcfe. This calculation excludes costs of $236 million for the acquisition of unproved properties and leasehold, $153 million for capitalized interest on unproved properties, and $26 million for seismic and asset retirement obligations, and also excludes positive revisions of proved reserves from higher natural gas and oil prices. Excluding these items and acquisition and divestiture activity, Chesapeake's exploration and development costs through the drillbit during the 2009 second quarter were $0.87 per mcfe, giving effect to the benefit of $311 million in drilling carries associated with the Haynesville ($118 million), Fayetteville ($166 million) and Marcellus ($27 million) joint ventures.

During the 2009 first half, Chesapeake increased its estimated proved reserves 474 bcfe, or 4%, from 12.051 tcfe at year-end 2008. For the 2009 first half, Chesapeake replaced 436 bcfe of production with an estimated 910 bcfe of new proved reserves for a reserve replacement rate of 209%. The reserve movement in the 2009 first half included 920 bcfe of extensions, 740 bcfe of positive performance revisions, 664 bcfe of downward revisions resulting from a decrease in natural gas prices between December 31, 2008 and June 30, 2009 and 86 bcfe of net divestitures. Chesapeake's 1,660 bcfe of extensions and performance revisions in the 2009 first half set a company record for the highest level of organic reserve additions during a six-month period and its organic reserve replacement rate of 381% for the six-month period was also the highest in the company's history.

Chesapeake's total drilling and net acquisition costs for the 2009 first half were $1.18 per mcfe. This calculation excludes costs of $746 million for the acquisition of unproved properties and leasehold, $314 million for capitalized interest on unproved properties, and $95 million for seismic and asset retirement obligations, and also excludes downward revisions of proved reserves from lower natural gas and oil prices. Excluding these items and acquisition and divestiture activity, Chesapeake's exploration and development costs through the drillbit during the 2009 first half were $1.15 per mcfe, giving effect to the benefit of $580 million in drilling carries associated with the Haynesville ($204 million), Fayetteville ($337 million) and Marcellus ($39 million) joint ventures.

Chesapeake continued the industry’s most active drilling program during the 2009 first half, and drilled 580 gross operated wells (432 net wells with an average working interest of 74%) and participated in another 581 gross wells operated by other companies (44 net wells with an average working interest of 8%). The company's drilling success rate was 99% for both company-operated and non-operated wells. Also during the 2009 first half, Chesapeake invested $1.509 billion in operated wells (using an average of 104 operated rigs) and $401 million in non-operated wells (using an average of 53 non-operated rigs) for total drilling, completing and equipping costs of $1.910 billion (net of carries).

As of June 30, 2009, the present value of future net cash flows, discounted at 10% per year, of Chesapeake's estimated proved reserves (PV-10) was $11.076 billion using field differential adjusted prices based on NYMEX quarter-end prices of $3.89 per mcf and $70.00 per bbl. Chesapeake's PV-10 changes by approximately $400 million for every $0.10 per mcf change in natural gas prices and approximately $65 million for every $1.00 per bbl change in oil prices.

By comparison, the December 31, 2008 PV-10 of the company's proved reserves was $15.601 billion ($11.833 billion applying the SFAS 69 standardized measure) using field differential adjusted prices based on NYMEX year-end prices of $5.71 per mcf and $44.61 per bbl. The June 30, 2008 PV-10 of the company's proved reserves was $51.5 billion using field differential adjusted prices based on NYMEX quarter-end prices of $13.10 per mcf and $140.02 per bbl.

The company calculates the standardized measure of future net cash flows in accordance with SFAS 69 only at year end because applicable income tax information on properties, including recently acquired natural gas and oil interests, is not readily available at other times during the year. As a result, the company is not able to reconcile the 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.

In addition to the PV-10 value of its proved reserves and the very significant value of its undeveloped leasehold, particularly in the Haynesville, Marcellus, Barnett and Fayetteville Shale plays and in the Colony and Texas Panhandle Granite Wash plays, the net book value of the company’s other assets (including gathering systems, compressors, land and buildings, investments and other noncurrent assets) was $6.369 billion as of June 30, 2009, $5.822 billion as of December 31, 2008 and $4.585 billion as of June 30, 2008.
 

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