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| CHK > SEC Filings for CHK > Form 10-Q on 10-Aug-2009 | All Recent SEC Filings |
10-Aug-2009
Quarterly Report
Overview
The following table sets forth certain information regarding the production
volumes, natural gas and oil sales, average sales prices received, other
operating income and expenses for the three and six months ended June 30, 2009
(the "Current Quarter" and the "Current Period") and the three and six months
ended June 30, 2008 (the "Prior Quarter" and the "Prior Period"):
Three Months Ended Six Months Ended
June 30, June 30,
2009 2008 2009 2008
(Adjusted) (Adjusted)
Net Production:
Natural gas (mmcf) 204,282 194,994 400,031 382,766
Oil (mbbls) 3,152 2,816 6,026 5,562
Natural gas equivalent (mmcfe) 223,194 211,890 436,187 416,138
Natural Gas and Oil Sales ($ in millions):
Natural gas sales $ 548 $ 1,896 $ 1,223 $ 3,329
Natural gas derivatives - realized gains
(losses) 587 (302 ) 1,096 (34 )
Natural gas derivatives - unrealized gains
(losses) (192 ) (2,526 ) (123 ) (3,528 )
Total natural gas sales 943 (932 ) 2,196 (233 )
Oil sales 169 337 272 596
Oil derivatives - realized gains (losses) 10 (121 ) 19 (174 )
Oil derivatives - unrealized gains (losses) (25 ) (878 ) 7 (1,010 )
Total oil sales 154 (662 ) 298 (588 )
Total natural gas and oil sales $ 1,097 $ (1,594 ) $ 2,494 $ (821 )
Average Sales Price (excluding all gains
(losses) on derivatives):
Natural gas ($ per mcf) $ 2.68 $ 9.73 $ 3.06 $ 8.70
Oil ($ per bbl) $ 53.59 $ 119.81 $ 45.19 $ 107.13
Natural gas equivalent ($ per mcfe) $ 3.21 $ 10.54 $ 3.43 $ 9.43
Average Sales Price (excluding unrealized
gains (losses) on derivatives):
Natural gas ($ per mcf) $ 5.56 $ 8.18 $ 5.80 $ 8.61
Oil ($ per bbl) $ 56.72 $ 76.96 $ 48.32 $ 75.86
Natural gas equivalent ($ per mcfe) $ 5.89 $ 8.55 $ 5.98 $ 8.93
Other Operating Income (Loss)(a) ($ in
millions):
Natural gas and oil marketing $ 32 $ 24 $ 61 $ 46
Service operations $ (2 ) $ 8 $ 3 $ 15
Other Operating Income (Loss)(a) ($ per
mcfe):
Natural gas and oil marketing $ 0.14 $ 0.12 $ 0.14 $ 0.11
Service operations $ (0.01 ) $ 0.04 $ 0.01 $ 0.04
Expenses ($ per mcfe):
Production expenses $ 0.95 $ 1.03 $ 1.03 $ 1.01
Production taxes $ 0.11 $ 0.41 $ 0.11 $ 0.39
General and administrative expenses $ 0.33 $ 0.48 $ 0.38 $ 0.43
Natural gas and oil depreciation, depletion
and amortization $ 1.32 $ 2.47 $ 1.70 $ 2.49
Depreciation and amortization of other
assets $ 0.26 $ 0.19 $ 0.26 $ 0.18
Interest expense(b) $ 0.29 $ 0.32 $ 0.22 $ 0.37
Interest Expense ($ in millions):
Interest expense $ 69 $ 72 $ 107 $ 158
Interest rate derivatives - realized (gains)
losses (5 ) (4 ) (12 ) (4 )
Interest rate derivatives - unrealized
(gains) losses (42 ) (14 ) (87 ) (1 )
Total interest expense $ 22 $ 54 $ 8 $ 153
Net Wells Drilled 212 485 476 933
Net Producing Wells as of the End of the
Period 22,626 22,324 22,626 22,324
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(a) Includes revenue and operating costs and excludes depreciation and amortization of other assets.
(b) Includes the effects of realized gains (losses) from interest rate derivatives, but excludes the effects of unrealized gains (losses) and is net of amounts capitalized.
We are one of the leading producers of natural gas in the United States. We own interests in approximately 43,300 producing natural gas and oil wells that are currently producing approximately 2.5 bcfe per day, 92% of which is natural gas. Our strategy is focused on discovering, acquiring and developing conventional and unconventional natural gas reserves onshore in the U.S., primarily in the "Big 4" natural gas shale plays: the Barnett Shale in the Fort Worth Basin of north-central Texas, the Haynesville Shale in the Ark-La-Tex area of northwestern Louisiana and East Texas, the Fayetteville Shale in the Arkoma Basin of central Arkansas and the Marcellus Shale in the northern Appalachian Basin of West Virginia, Pennsylvania and New York. We also have substantial operations in various other plays, both conventional and unconventional, in the Mid-Continent, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and Ark-La-Tex regions of the United States.
During the Current Period, Chesapeake continued the industry's most active drilling program drilling 580 gross (432 net with an average working interest of 74%) operated wells and participating in another 581 gross (44 net with an average working interest of 8%) wells operated by other companies. The company's drilling success rate was 99% for both company-operated and non-operated wells. Also during the Current Period, we 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). Currently we are using 95 operated drilling rigs, reflecting the company's decreased drilling activity in response to low natural gas and oil prices.
Our total Current Quarter production was 223.2 bcfe, comprised of 204.3 bcf (92% on a natural gas equivalent basis) and 3.152 mmbbls of oil and natural gas liquids (8% on a natural gas equivalent basis). Daily production for the Current Quarter averaged 2.453 bcfe, an increase of 125 mmcfe, or 5%, over the 2.328 bcfe produced per day in the Prior Quarter. Adjusted for our 2009 voluntary production curtailments due to low natural gas and oil prices (which averaged approximately 74 mmcfe per day during the Current Quarter), our three 2008 volumetric production payment sales (which averaged approximately 139 mmcfe per day during the Current Quarter) and the estimated impact from the 2008 sales of Woodford Shale and Fayetteville Shale properties (which would have averaged approximately 81 mmcfe per day during the Current Quarter), our year over year production growth rate would have been 16% after making similar adjustments to prior quarters. We are not currently curtailing production, but may do so again later this summer or fall as market conditions dictate. We also expect 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 began 2009 with estimated proved reserves of 12.051 tcfe and ended the Current Period with 12.525 tcfe, an increase of 474 bcfe, or 4%. During the Current Period, we replaced 436 bcfe of production with an internally estimated 910 bcfe of new proved reserves, for a reserve replacement rate of 209%. The Current Period's reserve movement includes 920 bcfe of extensions, 740 bcfe of positive performance revisions, 664 bcfe of downward revisions resulting from natural gas price decreases between December 31, 2008 and June 30, 2009 and 86 bcfe of net divestitures. Based on our current drilling schedule and budget, we expect that virtually all of the proved undeveloped reserves added in 2009 will begin producing within the next three to five years. Generally, proved developed reserves are producing at the time they are added or will begin producing within one year.
Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (14.3 million net acres) and 3-D seismic (22.7 million acres) in the U.S. and the largest inventory of U.S. Big 4 Shale play leasehold (2.7 million net acres). On our leasehold, the company has approximately 36,000 net drillsites representing more than a 10-year inventory of drilling projects.
Our high level of hedging at attractive prices should continue to insulate us from potentially soft near-term natural gas prices during the remainder of 2009. We also believe that the remaining joint venture drilling carries of approximately $3.7 billion will result in high returns on invested capital, reduce our capital expenditures and improve our balance sheet.
Our debt, net of cash on hand, as a percentage of total capitalization (total capitalization is the sum of debt, net of cash on hand, and stockholders' equity) was 52% as of June 30, 2009 and 40% as of December 31, 2008. The increase in this percentage is primarily due to the reduction of equity as the result of a $5.5 billion net loss caused by impairments of natural gas and oil properties and other assets of $9.6 billion in the Current Period. The average maturity of our long-term debt is over seven years with an average coupon interest rate of approximately 6.1%. No scheduled principal payments are required under our senior notes until 2013 when $864 million is due.
Business Strategy
Our exploration, development and acquisition activities require us to make substantial capital expenditures. Through the middle of 2008, we increased our capital expenditure budget for 2008 and 2009 several times in response to higher leasehold acquisition costs and in order to accelerate leasehold acquisition and drilling primarily in the Haynesville, Barnett and Marcellus Shale plays. During the second half of 2008 and the first half of 2009, in response to a significant decrease in natural gas prices, deteriorating global economic conditions and outlook and concerns about an oversupply of natural gas in the U.S. market, and in recognition of the substantial reduction in capital requirements resulting from our joint ventures with Plains Exploration & Production Company (PXP), BP America (BP) and StatoilHydro U.S.A. (STO), we significantly reduced our planned capital expenditures through year-end 2010. Our current budgeted capital expenditures are $4.700 billion to $5.425 billion in 2009 and $4.350 billion to $4.975 billion in 2010. We anticipate directing approximately 75% of our gross drilling capital expenditures during 2009 and 2010 to our Big 4 shale plays.
Our innovative joint ventures create a significant cost advantage for us that allows us to drive down finding costs in our joint venture plays. During each of 2009 and 2010, we anticipate our exploration and development costs will be significantly lower than 2008 costs as a result of lower service costs and the benefit of using approximately $2.6 billion of joint venture drilling carries in three of our Big 4 shale plays. The following table provides information about the joint venture drilling carries:
Shale Play
Haynesville(a) Fayetteville Marcellus Total
($ in millions)
Joint venture with PXP BP STO
Closing date July 1, 2008 September 19, November 24,
2008 2008
Cash proceeds at closing $ 1,650 $ 1,100 $ 1,250 $ 4,000
Total drilling carry $ 1,650 $ 800 $ 2,125 $ 4,575
Carries billed as of June 30, 2009 $ 276 $ 536 $ 39 $ 851
Remaining drilling carry as of June 30, 2009 $ 1,374 $ 264 $ 2,086 $ 3,724
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(a) On August 6, 2009, we announced an amendment to our Haynesville Shale joint venture agreement with Plains Exploration & Production Company (PXP). As part of the amendment, PXP has agreed to accelerate the payment of its remaining joint venture drilling carries as of September 30, 2009 in exchange for an approximate 12% reduction in the total amount of drilling carry obligations due to Chesapeake. At the closing, scheduled to occur on September 29, 2009, Chesapeake will receive cash of approximately $1.1 billion instead of an estimated $1.25 billion in remaining carried drilling costs that PXP would have paid over the next three years under the original agreement. In addition, Chesapeake and PXP have agreed to terminate a previous joint venture amendment that granted PXP a one-time option in June 2010 to avoid paying the last $800 million of the drilling carry obligations in exchange for the conveyance of 50% of its Haynesville Shale assets to Chesapeake. After the closing of the amendment, Chesapeake and PXP will each pay their proportionate working interest costs on future drilling. Furthermore, Chesapeake and PXP have agreed to make several other minor modifications to the agreement.
Cash flow from operations is our primary source of liquidity used to fund capital expenditures. Our $3.5 billion revolving bank credit facility and our $460 million midstream revolving bank credit facility provide us with additional liquidity. In February 2009, we issued $1.425 billion principal amount of our 9.5% senior notes due 2015. Net proceeds of $1.346 billion were used to repay outstanding indebtedness under our revolving bank credit facility, which we may reborrow from time to time to fund drilling and leasehold acquisition initiatives and for general corporate purposes. At June 30, 2009, we had borrowings of $2.834 billion and letters of credit of $10 million outstanding under our revolving bank credit facility and we had borrowings of $297 million under the midstream credit facility.
During 2009 and 2010, we plan to increase our liquidity, reduce our borrowings under our revolving bank credit facility and also strengthen our balance sheet through asset monetizations and the growth of our proved reserve base. Transactions we have completed or expect to complete in 2009 include the following:
• In the Current Quarter, we sold producing properties and gathering assets located primarily in Louisiana for $208 million and certain midstream and real estate surface assets for $172 million. In July 2009, we sold producing properties in Central Texas for $75 million. We expect to sell certain other midstream assets in multiple transactions for a total of approximately $70 million in the third quarter of 2009.
• We sold our fifth volumetric production payment transaction (VPP) involving certain of our South Texas assets for proceeds of approximately $371 million on August 4, 2009.
• We plan to sell certain non-Haynesville Shale producing assets in Louisiana in a sixth VPP in the second half of 2009 for approximately $225 million to $250 million.
• We plan to sell to a private equity investor a 50% interest in our Barnett Shale and Mid-Continent natural gas gathering and processing assets in our midstream business subsidiary, Chesapeake Midstream Partners, L.P. We anticipate proceeds of more than $550 million in the 2009 third quarter.
• We continue to have discussions with several companies about a possible joint venture on some or all of our Barnett Shale leasehold in a transaction targeted for completion by year end 2009.
We believe that our anticipated internally generated cash flow, cash resources, expected asset monetization transactions and other sources of liquidity will allow us to fully fund our capital expenditure requirements in 2009. Further deterioration of the economy, continued low natural gas and oil prices and other factors, however, could require us to further curtail our spending.
Liquidity and Capital Resources
Sources and Uses of Funds
Cash flow from operations is a significant source of liquidity used to fund capital expenditures. Our joint venture drilling carries also provide an additional source of liquidity that have reduced and will continue to reduce our capital expenditures. Cash provided by operating activities was $1.998 billion in the Current Period compared to $2.798 billion in the Prior Period. The $800 million decrease in the Current Period was primarily due to lower natural gas and oil prices. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding non-cash items such as impairments of assets, depreciation, depletion and amortization, deferred income taxes and unrealized gains and (losses) on derivatives. See the discussion below under Results of Operations.
Changes in market prices for natural gas and oil directly impact the level of our cash flow from operations. To mitigate the risk of declines in natural gas and oil prices and to provide more predictable future cash flow from operations, we currently have hedged through swaps and collars 86% of our expected remaining natural gas and oil production in 2009 and 22% of our expected natural gas and oil production in 2010 at average prices of $7.46 per mcfe and $9.48 per mcfe, respectively. Our natural gas and oil hedges as of June 30, 2009 are detailed in Item 3 of Part I of this report. Depending on changes in natural gas and oil futures markets and management's view of underlying natural gas and oil supply and demand trends, we may increase or decrease our current hedging positions. As of June 30, 2009, we had a net natural gas and oil derivative asset of $998 million.
Our $3.5 billion bank credit facility, our $460 million midstream credit facility and cash and cash equivalents are other sources of liquidity. At August 6, 2009, there was $1.4 billion of borrowing capacity available under the revolving bank credit facility and $92 million of borrowing capacity under the midstream credit facility. We use the facilities and cash on hand to fund daily operating activities and acquisitions as needed. We borrowed $3.363 billion and repaid $4.166 billion in the Current Period, and we borrowed $6.758 billion and repaid $6.195 billion in the Prior Period.
On February 2, 2009, we completed a public offering of $1.0 billion aggregate principal amount of senior notes due 2015, which have a stated coupon rate of 9.5% per annum. The senior notes were priced at 95.071% of par to yield 10.625%. On February 17, 2009, we completed an offering of an additional $425 million aggregate principal amount of the 9.5% Senior Notes due 2015. The additional senior notes were priced at 97.75% of par plus accrued interest from February 2 to February 17, 2009 to yield 10.0% per annum. Net proceeds of $1.346 billion from these two offerings were used to repay outstanding indebtedness under our revolving bank credit facility, which we may reborrow from time to time to fund drilling and leasehold acquisition initiatives and for general corporate purposes.
Our primary use of funds is for capital expenditures related to exploration, development and acquisition of natural gas and oil properties. We refer you to the table under Investing Activities below, which sets forth the components of our natural gas and oil investing activities and our other investing activities for the Current Period and the Prior Period. We retain a significant degree of control over the timing of our capital expenditures which permits us to defer or accelerate certain capital expenditures if necessary to address any potential liquidity issues. In addition, changes in drilling and field operating costs, drilling results that alter planned development schedules, acquisitions or other factors could cause us to revise our drilling program, which is largely discretionary.
We paid dividends on our common stock of $89 million and $66 million in the Current Period and the Prior Period, respectively. Dividends paid on our preferred stock decreased to $12 million in the Current Period from $22 million in the Prior Period as a result of conversions and exchanges of preferred stock into common stock during 2008 and 2009.
In the Current Period and Prior Period, we received $9 million and paid $93 million, respectively, to settle a portion of the derivative liabilities assumed in our November 2005 acquisition of Columbia Natural Resources, LLC.
SFAS 123(R) requires tax benefits resulting from stock-based compensation deductions in excess of amounts reported for financial reporting purposes to be reported as cash flows from financing activities. In the Current Period and the Prior Period, we reported a tax benefit from stock-based compensation of $0 and $21 million, respectively.
Outstanding payments from certain disbursement accounts in excess of funded cash balances where no legal right of set-off exists decreased $350 million in the Current Period and increased $47 million in the Prior Period. All disbursements are funded on the day they are presented to our bank using available cash on hand or draws on our revolving bank credit facility.
In the Current Period, we received net proceeds of $54 million from the mortgage financing of one of our buildings. The interest-only loan has a five-year term at a floating rate of prime plus 275 basis points. At our option, we may prepay in full without penalty beginning in year four. The payment obligation is guaranteed by Chesapeake. Chesapeake is also party to a master lease for the entire building that will come into effect only in the event that a tenant defaults.
In the Current Quarter, we sold 113 surface land sites in the Barnett Shale area in and around Fort Worth, Texas for net proceeds of approximately $145 million and entered into a master lease agreement under which we agreed to lease the sites for 40 years for approximately $15 million to $27 million annually. As of June 30, 2009, the minimum aggregate future surface land site payments were approximately $866 million.
Credit Risk
A significant portion of our liquidity is concentrated in derivative instruments that enable us to hedge a portion of our exposure to natural gas and oil prices and interest rate volatility. These arrangements expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. On June 30, 2009, our commodity and interest rate derivative instruments were spread among 14 counterparties. Additionally, our multi-counterparty secured hedging facility requires our counterparties to secure their natural gas and oil hedging obligations in excess of defined thresholds. We expect to use the facility for all of our commodity hedging.
Our accounts receivable are primarily from purchasers of natural gas and oil ($534 million at June 30, 2009) and exploration and production companies which own interests in properties we operate ($452 million at June 30, 2009). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parental guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During
the Current Quarter and the Current Period, we recognized $5 million and $13 million, respectively, of bad debt expense related to potentially uncollectible receivables.
Investing Activities
Cash used in investing activities decreased to $3.465 billion during the Current Period, compared to $6.373 billion during the Prior Period. We have been reducing our drilling program since the third quarter of 2008, and our leasehold and property acquisitions expenditures in the Current Period were 86% lower than in the Prior Period. The following table shows our cash used in (provided by) investing activities during these periods:
Six Months Ended
June 30,
2009 2008
Natural Gas and Oil Investing Activities: ($ in millions)
Exploration and development of natural gas and oil
properties $ 1,995 $ 2,785
Acquisition of leasehold and unproved properties 410 2,645
Acquisitions of natural gas and oil companies and proved
properties, net of cash acquired 2 202
Geological and geophysical costs 97 138
Interest capitalized on unproved properties 314 224
Proceeds from sale of volumetric production payment (41 ) (616 )
Divestitures of proved and unproved properties and
leasehold (187 ) (247 )
Deposits for acquisitions 9 19
Deposits for divestitures (8 ) -
Total natural gas and oil investing activities 2,591 5,150
Other Investing Activities:
Additions to other property and equipment 980 1,229
Proceeds from sale of compressors (68 ) (51 )
. . .
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