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| CHK > SEC Filings for CHK > Form 10-Q on 9-Nov-2009 | All Recent SEC Filings |
9-Nov-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 nine months ended September 30,
2009 (the "Current Quarter" and the "Current Period") and the three and nine
months ended September 30, 2008 (the "Prior Quarter" and the "Prior Period"):
Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 2009 2008
(Adjusted) (Adjusted)
Net Production:
Natural gas (mmcf) 210,292 196,657 610,323 579,423
Oil (mbbls) 3,027 2,810 9,053 8,372
Natural gas equivalent (mmcfe) 228,454 213,517 664,641 629,655
Natural Gas and Oil Sales ($ in
millions):
Natural gas sales $ 596 $ 1,717 $ 1,819 $ 5,046
Natural gas derivatives - realized
gains (losses) 675 (140 ) 1,771 (174 )
Natural gas derivatives -
unrealized gains (losses) (275 ) 3,854 (398 ) 325
Total natural gas sales 996 5,431 3,192 5,197
Oil sales 189 319 461 915
Oil derivatives - realized gains
(losses) 12 (106 ) 31 (280 )
Oil derivatives - unrealized gains
(losses) (10 ) 764 (3 ) (245 )
Total oil sales 191 977 489 390
Total natural gas and oil sales $ 1,187 $ 6,408 $ 3,681 $ 5,587
Average Sales Price (excluding all
gains (losses) on derivatives):
Natural gas ($ per mcf) $ 2.84 $ 8.73 $ 2.98 $ 8.71
Oil ($ per bbl) $ 62.47 $ 113.53 $ 50.97 $ 109.28
Natural gas equivalent ($ per
mcfe) $ 3.44 $ 9.54 $ 3.43 $ 9.47
Average Sales Price (excluding
unrealized gains (losses) on
derivatives):
Natural gas ($ per mcf) $ 6.04 $ 8.02 $ 5.88 $ 8.41
Oil ($ per bbl) $ 66.42 $ 75.74 $ 54.37 $ 75.82
Natural gas equivalent ($ per
mcfe) $ 6.44 $ 8.38 $ 6.14 $ 8.75
Other Operating Income (Loss)(a)
($ in millions):
Marketing, gathering and
compression $ 29 $ 24 $ 91 $ 70
Service operations $ - $ 8 $ 3 $ 23
Other Operating Income (Loss)(a)
($ per mcfe):
Marketing, gathering and
compression $ 0.13 $ 0.11 $ 0.14 $ 0.11
Service operations $ - $ 0.04 $ - $ 0.04
Expenses ($ per mcfe):
Production expenses $ 0.96 $ 1.12 $ 1.01 $ 1.04
Production taxes $ 0.11 $ 0.41 $ 0.11 $ 0.40
General and administrative
expenses $ 0.42 $ 0.51 $ 0.39 $ 0.46
Natural gas and oil depreciation,
depletion and amortization $ 1.29 $ 2.25 $ 1.56 $ 2.41
Depreciation and amortization of
other assets $ 0.27 $ 0.22 $ 0.27 $ 0.20
Interest expense(b) $ 0.28 $ 0.20 $ 0.24 $ 0.31
Interest Expense ($ in millions):
Interest expense $ 70 $ 37 $ 177 $ 194
Interest rate derivatives -
realized (gains) losses (7 ) 5 (19 ) 1
Interest rate derivatives -
unrealized (gains) losses (20 ) (8 ) (106 ) (9 )
Total interest expense $ 43 $ 34 $ 52 $ 186
Net Wells Drilled 224 455 700 1,388
Net Producing Wells as of the End
of the Period 22,749 22,475 22,749 22,475
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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 43,600 producing natural gas and oil wells that are currently producing approximately 2.6 bcfe per day, 93% 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 853 gross operated wells (624 net with an average working interest of 73%) and participating in another 864 gross wells operated by other companies (76 net with an average working interest of 9%). The company's drilling success rate was 99% for company-operated wells and 98% for non-operated wells. Also during the Current Period, we invested $2.211 billion in operated wells (using an average of 102 operated rigs) and $330 million in non-operated wells (using an average of 57 non-operated rigs) for total drilling, completing and equipping costs of $2.541 billion (net of carries).
Our total Current Quarter production was 228.5 bcfe, comprised of 210.3 bcf (92% on a natural gas equivalent basis) and 3.027 mmbbls of oil and natural gas liquids (8% on a natural gas equivalent basis). Daily production for the Current Quarter averaged 2.483 bcfe, an increase of 162 mmcfe, or 7%, over the 2.321 bcfe produced per day in the Prior Quarter. Adjusted for our 2009 voluntary production curtailments due to low natural gas prices and involuntary production curtailments due to pipeline repairs (which together averaged approximately 45 mmcfe per day during the Current Quarter), our 2009 and third and fourth quarter 2008 volumetric production payment transactions (which combined averaged approximately 125 mmcfe per day during the Current Quarter) and the estimated impact from various divestitures (which would have averaged approximately 105 mmcfe per day during the Current Quarter), our year over year production growth rate would have been 14% after making similar adjustments to prior quarters.
Chesapeake began 2009 with estimated proved reserves of 12.051 tcfe and ended the Current Period with 11.994 tcfe, a decrease of 57 bcfe, or 0.5%. During the Current Period, we replaced 665 bcfe of production with an internally estimated 608 bcfe of new proved reserves, for a reserve replacement rate of 91%. The Current Period's reserve movement included 1.455 tcfe of extensions, 1.503 tcfe of positive performance revisions, 2.164 tcfe of downward revisions resulting primarily from a decrease in natural gas prices between December 31, 2008 and September 30, 2009 and 186 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 (14.1 million net acres) and 3-D seismic (23.3 million acres) in the U.S. and the largest inventory of U.S. Big 4 Shale play leasehold (2.8 million net acres). We are currently using 105 operated drilling rigs to further develop our inventory of approximately 36,000 net drillsites, which represents 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 $2.1 billion will enhance 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 equity) was 47% as of September 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 $5.3 billion net loss caused by impairments of natural gas and oil properties and other assets of $9.7 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 6.2%. 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 innovative 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, net of drilling carries, are $3.525 billion to $3.900 billion in 2009 and $4.625 billion to $5.000 billion in 2010. We anticipate directing approximately 75% of the drilling capital expenditures (before drilling carries) during 2009 and 2010 to our Big 4 shale plays.
During 2009, our exploration and development costs have been significantly lower than 2008 costs as a result of lower service costs and the benefit of approximately $959 million of joint venture drilling carries in three of our Big 4 shale plays. We expect low service costs to continue in 2010, and the remaining approximately $2.1 billion of drilling carries associated with our joint ventures create a significant cost advantage for us that will allow us to continue to drive down finding costs in our joint venture plays. The following table provides information about the joint venture drilling carries:
Shale Play
Haynesville(a) Fayetteville Marcellus Total
($ 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
September 30, 2009 $ 1,522 $ 723 $ 85 $ 2,330
Remaining drilling carry as of
September 30, 2009 $ - $ 77 $ 2,040 $ 2,117
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(a) In August 2009, we amended our Haynesville Shale joint venture agreement with Plains Exploration & Production Company (PXP). As part of the amendment, PXP accelerated the payment of its remaining joint venture drilling carries as of September 30, 2009 in exchange for an approximate 10% reduction in the total amount of drilling carry obligations due to Chesapeake and we received cash of $1.1 billion instead of an estimated $1.23 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 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 by conveying 50% of its Haynesville Shale assets to Chesapeake.
The joint ventures in three of our shale plays are a complementary part of our business strategy to maximize the value of our leasehold inventory and minimize our investment risk. We have previously announced our efforts to arrange a joint venture for some or all of our Barnett Shale leasehold which, if successful, would enable us to increase our Barnett drilling activity and production. There are other new plays we are identifying and developing which may become additional joint venture opportunities. Our 50/50 joint venture with Global Infrastructure Partners in the Current Quarter is another example of our joining with a strong partner to develop key assets which include all of our midstream assets in the Barnett Shale and other midstream assets in the Mid-Continent. Upon the closing of this transaction, we received proceeds of $588 million. During the Current Period, we sold non-core natural gas and oil assets for proceeds of $278 million, and we expect to close additional sales of non-core properties in the coming months. Over the next two years, we expect to be a net seller of leasehold and producing properties.
Apart from asset monetizations, cash flow from operations is our primary source of liquidity used to fund capital expenditures. Our three revolving bank credit facilities provide us with borrowing capacity of up to $4.25 billion for 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 reborrow from time to time to fund drilling and leasehold acquisition initiatives and for general corporate purposes. At September 30, 2009, we had borrowings of $1.630 billion and letters of credit of $11 million outstanding under our credit facilities.
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 and 2010. 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. Cash provided by operating activities was $3.131 billion in the Current Period compared to $4.387 billion in the Prior Period. The $1.256 billion decrease in the Current Period was primarily due to lower natural gas 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 75% 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 $7.29 per mcfe and $9.39 per mcfe, respectively. Our natural gas and oil hedges as of September 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 September 30, 2009, we had a net natural gas and oil derivative asset of $384 million.
Our three revolving bank credit facilities, described below under Bank Credit Facilities, are other sources of liquidity. At November 4, 2009, there was $2.9 billion of borrowing capacity available under these credit facilities. We use the facilities and cash on hand to fund daily operating activities and capital expenditures as needed. We borrowed $5.563 billion and repaid $7.866 billion in the Current Period, and we borrowed $12.831 billion and repaid $11.307 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 $1.346 billion from these two offerings were used to repay outstanding indebtedness under our general corporate revolving bank credit facility, which we reborrow from time to time to fund drilling and leasehold acquisition initiatives and for general corporate purposes. The following table reflects the proceeds from sales of securities we issued in the Current Period and the Prior Period ($ in millions):
For the Nine Months Ended September 30,
2009 2008
Total Net Total Net
Proceeds Proceeds Proceeds Proceeds
Senior notes $ 1,425 $ 1,346 $ 800 $ 787
Contingent convertible senior notes - - 1,380 1,349
Common stock - - 2,698 2,598
Total $ 1,425 $ 1,346 $ 4,878 $ 4,734
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Our primary use of funds is for capital expenditures related to exploration, development and acquisition of natural gas and oil properties. As described under Business Strategy, our joint venture drilling carries have reduced and will continue to reduce our capital expenditures. 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 $135 million and $106 million in the Current Period and the Prior Period, respectively. Dividends paid on our preferred stock decreased to $18 million in the Current Period from $29 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 $19 million and paid $146 million, respectively, to settle a portion of the derivative liabilities assumed in our November 2005 acquisition of Columbia Natural Resources, LLC.
ASC 718 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 $42 million, respectively.
Outstanding payments from certain disbursement accounts in excess of funded cash balances where no legal right of set-off exists decreased $305 million in the Current Period and increased $210 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 facilities.
In the Current Period, we formed a joint venture with Global Infrastructure Partners (GIP), a New York-based private equity fund, to own and operate natural gas midstream assets. As part of the transaction, we contributed certain natural gas gathering and processing assets into a new entity, Chesapeake Midstream Partners, L.L.C. (CMP), and GIP purchased a 50% interest in CMP. Chesapeake retained the remaining 50% interest in CMP and received a $588 million cash distribution from CMP. The transaction is discussed in Note 8 of our condensed consolidated financial statements included in this report.
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 the loan in full without penalty beginning in year four.
In the Current Period, we financed 113 real estate surface assets 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 assets for 40 years for approximately $15 million to $27 million annually. As of September 30, 2009, the minimum aggregate future lease payments were approximately $862 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. During the more than 15 years we have engaged in hedging activities, we have experienced a counterparty default only once (Lehman Brothers in September 2008), and the total loss recorded in that instance was immaterial (presently approximately $15 million without giving effect to possible future recoveries or the results of replacement hedges we entered into after the termination of our Lehman hedges pursuant to the terms of the ISDA agreement with Lehman). On September 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 now use this facility for all of our commodity hedging.
Our accounts receivable are primarily from purchasers of natural gas and oil ($476 million at September 30, 2009) and exploration and production companies which own interests in properties we operate ($528 million at September 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 parent 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 a nominal amount and $13 million, respectively, of bad debt expense related to potentially uncollectible receivables.
Investing Activities
Cash used in investing activities decreased to $3.654 billion during the Current Period, compared to $8.283 billion during the Prior Period. We have been reducing our drilling program since the third quarter of 2008, and our leasehold and property acquisitions expenditures in the Current Period were 88% lower than in the Prior Period. The following table shows our cash used in (provided by) investing activities during these periods:
Nine Months Ended
September 30,
2009 2008
($ in millions)
Natural Gas and Oil Investing Activities:
Exploration and development of natural gas and
oil properties $ 2,647 $ 4,407
Acquisition of leasehold and unproved properties 890 6,933
Acquisitions of natural gas and oil companies
and proved properties, net of cash acquired 17 368
. . .
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