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Cabot Oil & Gas 10-K 2008 Documents found in this filing:
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2007 Commission file number 1-10447
CABOT OIL & GAS CORPORATION (Exact name of registrant as specified in its charter)
1200 Enclave Parkway, Houston, Texas 77077 (Address of principal executive offices including ZIP code) (281) 589-4600 (Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K x. (continued)
Table of ContentsIndex to Financial StatementsIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
(Do not check if a smaller reporting company) Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x The aggregate market value of Common Stock, par value $.10 per share (“Common Stock”), held by non-affiliates as of the last business day of registrant’s most recently completed second fiscal quarter (based upon the closing sales price on the New York Stock Exchange on June 29, 2007) was approximately $3.6 billion. As of February 25, 2008, there were 97,768,036 shares of Common Stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held April 30, 2008 are incorporated by reference into Part III of this report.
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Table of ContentsIndex to Financial StatementsThe statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. These statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results of future drilling and marketing activity, future production and costs, and other factors detailed in this document and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A for additional information about these risks and uncertainties. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this document. See “Forward-Looking Information” for further details. CERTAIN DEFINITIONS The following is a list of commonly used terms and their definitions included within this Annual Report on Form 10-K:
OVERVIEW Cabot Oil & Gas Corporation is an independent oil and gas company engaged in the development, exploitation and exploration of oil and gas properties located in North America. Our five principal areas of operation are the Appalachian Basin, onshore Gulf Coast, including south and east Texas and north Louisiana, the Rocky Mountains, the Anadarko Basin and the deep gas basin of Western Canada. Operationally, we have four regional offices located in Houston, Texas; Charleston, West Virginia; Denver, Colorado; and Calgary, Alberta. Net income for 2007 of $167.4 million, or $1.73 per share, was lower than the prior year’s net income of $321.2 million, or $3.32 per share, by $153.8 million, or 48%. The year-over-year net income decrease was primarily due to the recognition of a gain on sale of assets of $231.2 million ($144.5 million, net of tax) in 2006 related to the disposition of our offshore portfolio and certain south Louisiana properties to a third party, which was substantially completed in 2006 (the 2006 south Louisiana and offshore properties sale) and, to a lesser extent, lower operating revenues as discussed below. Additionally, operating expenses increased by $5.8 million between 2006 and 2007 principally due to increased depreciation, depletion and amortization costs and impairment charges, partially offset by lower exploration and general and administrative expenses. These lower operating revenues and increased operating expenses, along with a $1.2 million decrease in interest and other expense, reduced income before income taxes by $253.0 million and consequently decreased income tax expense by $99.2 million. Also contributing to the decrease in income taxes was the decrease in the effective tax rate primarily due to a reduction in our overall state income tax liability for 2007 relating to the 2006 south Louisiana and offshore properties sale.
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Table of ContentsIndex to Financial StatementsOperating revenues decreased by $29.8 million, or four percent, over the prior year as described below. Natural gas production revenues increased by $13.5 million, or two percent, over the prior year due to an increase in realized natural gas prices and an increase in natural gas production in the West region, East region and Canada, partially offset by decreased natural gas production in the Gulf Coast region as a result of the 2006 south Louisiana and offshore properties sale. Crude oil and condensate revenues decreased by $36.2 million, or 40%, over the prior year mainly due to decreased crude oil and condensate production in the Gulf Coast region as a result of the 2006 south Louisiana and offshore properties sale, partially offset by an increase in crude oil realized prices. Excluding $70.5 million and $47.4 million, respectively, of natural gas and crude oil revenues from our 2006 results that were attributable to the 2006 south Louisiana and offshore properties sale, natural gas revenues for 2007 would have increased by 17% and crude oil revenues would have increased by 26%. Brokered natural gas revenues decreased by $0.5 million due to a decrease in brokered volumes, offset in part by an increase in sales price. In 2007, energy commodity prices remained strong throughout the year. Our 2007 average realized natural gas price was $7.23 per Mcf, one percent higher than the 2006 average realized price of $7.13. Our 2007 average realized crude oil price was $67.16 per Bbl, three percent higher than the 2006 average realized price of $65.03. These realized prices include realized gains and losses resulting from commodity derivatives (zero-cost collars or swaps). For information about the impact of these derivatives on realized prices, refer to the “Results of Operations” section in Item 7 of this Annual Report on Form 10-K. Our balance sheet, strengthened by the 2006 south Louisiana and offshore properties sale, and a hedge position covering approximately half of our anticipated production at levels exceeding our budgeted prices, allowed us to once again expand our capital program. In 2007, we pursued and completed the largest investment program in our history ($636.2 million) which was funded largely through cash flow from operations and, to a lesser extent, borrowings on our revolving credit facility. We believe our balance sheet and availability under our credit facility provides sufficient liquidity to pursue our 2008 program and evaluate other opportunities. On an equivalent basis, our production level in 2007 decreased by three percent from 2006. We produced 85.5 Bcfe, or 234.1 Mmcfe per day, in 2007, as compared to 88.2 Bcfe, or 241.7 Mmcfe per day, in 2006. Natural gas production increased to 80.5 Bcf in 2007 from 79.7 Bcf in 2006 primarily due to increased production in the West and East regions associated with an increase in the drilling program and an increase in Canada due to increased pipeline capacity and drilling activity in the Hinton field, partially offset by a decline in Gulf Coast production. Excluding 9.0 Bcf of natural gas production sold in the 2006 south Louisiana and offshore properties sale, total natural gas production would have increased by 14%. Gulf Coast natural gas production decreased from 29.9 Bcf in 2006 to 26.8 Bcf in 2007 primarily due to the 2006 south Louisiana and offshore properties sale. Excluding 9.0 Bcf of production sold in that sale, Gulf Coast production would have increased 28% in 2007 over 2006, primarily due to increased drilling in the Minden, Angie (County Line) and McCampbell fields and recompletions in the Raymondville field. Oil production decreased by 582 Mbbls from 1,405 Mbbls in 2006 to 823 Mbbls in 2007, due primarily to a decrease in production in the Gulf Coast region. Excluding 707 Mbbls of crude oil production related to the 2006 south Louisiana and offshore properties sale, oil production would have increased by 18% from 2006 to 2007 mainly due to an increase in drilling and workover activity in the McCampbell field and, to a lesser extent, in the Minden field. Oil production increased slightly in the East region and in Canada and decreased by 17% in the West region due to natural decline. Excluding 13.3 Bcfe of equivalent production sold in the 2006 south Louisiana and offshore properties sale, total equivalent production would have increased by 10.6 Bcfe, or 14%. A portion of our production was covered by oil and gas hedge instruments throughout 2006 and 2007. Again during 2007 as in 2006, we employed the use of collars to hedge our price exposure on our production. In addition, at the end of 2007, we employed the use of cash flow swaps to cover a portion of our 2008 natural gas production. For 2007, collars covered 53% of natural gas production and had a weighted-average floor of $8.99 per Mcf and a weighted-average ceiling of $12.19 per Mcf. At December 31, 2007, approximately 38% of the anticipated 2008 natural gas production is hedged using collars with a weighted-average floor of $8.17 per Mcf and a weighted-average ceiling of $10.14 per Mcf. Swaps as of December 31, 2007 cover approximately six percent of our anticipated 2008 natural gas production with a weighted-average price of $7.44 per Mcf. For 2007, collars covered 44% of crude oil production with a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl. At December 31, 2007, approximately 49% of our anticipated crude oil production is hedged for 2008 with a floor of
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Table of ContentsIndex to Financial Statements$60.00 per Bbl and a ceiling of $80.00 per Bbl. As of December 31, 2007, no derivatives are in place for 2009. Our decision to hedge 2008 production fits with our risk management strategy and allows us to lock in the benefit of high commodity prices on a portion of our anticipated production. For the year ended December 31, 2007, we drilled 461 gross wells (391 net) with a success rate of 96% compared to 387 gross wells (307 net) with a success rate of 96% for the prior year. In 2008, we plan to drill approximately 419 gross wells (366 net). The number of wells we plan to drill in 2008 is down from 2007 primarily due to lower planned activity in the Rocky Mountains area based on lower natural gas prices and lower planned activity in Canada based on uncertainty around royalties and exchange rates. Our 2007 capital and exploration spending was $636.2 million compared to $537.5 million of total capital and exploration spending in 2006. In both 2007 and 2006, we allocated our planned program for capital and exploration expenditures among our various operating regions based on return expectations, availability of services and human resources. We plan to continue such method of allocation in 2008. Funding of the program is expected to be provided by operating cash flow, existing cash and increased borrowings, if required. We remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results and selectively pursuing impact exploration opportunities as we accelerate drilling on our accumulated acreage position. For 2008, the Gulf Coast region will start the year with the largest allocation of capital, followed by the East, the West and Canada. We believe these strategies are appropriate in the current industry environment and will continue to add shareholder value over the long term. In 2008, we plan to spend approximately $490 million on capital and exploration activities. Our proved reserves totaled approximately 1,616 Bcfe at December 31, 2007, of which 97% was natural gas. This reserve level was up by 14 percent from 1,416 Bcfe at December 31, 2006 on the strength of results from our drilling program and the increase in our capital spending. The following table presents certain reserve, production and well information as of December 31, 2007.
On September 29, 2006, we substantially completed the sale of our offshore portfolio and certain south Louisiana properties to Phoenix Exploration Company LP (Phoenix) for a gross sales price of $340.0 million. We received approximately $333.3 million in net proceeds from the sale. In addition to the net gain of $231.2 million ($144.5 million, net of tax) recorded in 2006, we recorded a net gain of $12.3 million ($7.7 million, net of tax) in the Consolidated Statement of Operations in 2007, which included cash proceeds of $5.8 million received in the first quarter of 2007, $2.1 million in purchase price adjustments and $4.4 million that had been deferred until legal title to certain properties could be assigned. Our interest in both developed and undeveloped properties is primarily in the form of leasehold interests held under customary mineral leases. These leases provide us the right, in general, to develop oil and/or natural gas on the properties. Their primary terms range in length from approximately three to seven years. These properties are
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Table of ContentsIndex to Financial Statementsheld for longer periods if production is established. We own leasehold rights on approximately 2.9 million gross acres. In addition, we own fee interest in approximately 0.2 million gross acres, primarily in West Virginia. Our ten largest fields, which are fields with 2.5% or greater of total company proved reserves, make up approximately 48% of total company proved reserves.
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Table of ContentsIndex to Financial StatementsEAST REGION Our East region activities are concentrated primarily in West Virginia. This region is managed from our office in Charleston, West Virginia. In this region, our assets include a large acreage position, a high concentration of wells, natural gas gathering and pipeline systems, and storage capacity. Capital and exploration expenditures for 2007 were $178.6 million, or 28% of our total 2007 capital and exploration expenditures, compared to $145.4 million for 2006, or 27% of our total 2006 capital and exploration expenditures. Of the total company year-over-year increase in capital and exploration expenditures, 23% was attributable to an increase in the East region spending. For 2008, we have budgeted approximately $189 million for capital and exploration expenditures in the region. At December 31, 2007, we had 3,178 wells (2,962.2 net), of which 3,085 wells are operated by us. There are multiple producing intervals that include the Big Lime, Weir, Berea and Devonian Shale formations at depths primarily ranging from 1,000 to 9,500 feet, with an average depth of approximately 4,000 feet. Average net daily production in 2007 was 67.1 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2007 was 24.4 Bcf and 26 Mbbls, respectively. While natural gas production volumes from East reservoirs are relatively low on a per-well basis compared to other areas of the United States, the productive life of East region reserves is relatively long. At December 31, 2007, we had 778.4 Bcfe of proved reserves (substantially all natural gas) in the East region, constituting 48% of our total proved reserves. Developed and undeveloped reserves made up 551.2 Bcfe and 227.2 Bcfe of the total proved reserves for the East region, respectively. While no properties are individually significant to our company as a whole, the Sissonville, Pineville, Logan-Holden-Dingess, Big Creek, Hernshaw-Bullcreek and Huff Creek fields in West Virginia are included in our ten largest fields and together contain approximately 29% of our total company proved equivalent reserves. In 2007, we drilled 254 wells (244.6 net) in the East region, of which 250 wells (240.8 net) were development and extension wells. In 2008, we plan to drill approximately 265 wells (258.5 net), primarily in West Virginia, including the Sissonville, Pineville, Logan-Holden-Dingess, Big Creek, Huff Creek and Hernshaw-Bullcreek fields. In 2007, we produced and marketed approximately 71 barrels of crude oil/condensate per day in the East region at market responsive prices. Ancillary to our exploration, development and production operations, we operated a number of gas gathering and transmission pipeline systems, made up of approximately 3,100 miles of pipeline with interconnects to three interstate transmission systems, seven local distribution companies and numerous end users as of the end of 2007. The majority of our pipeline infrastructure in West Virginia is regulated by the Federal Energy Regulatory Commission (FERC) for interstate transportation service and the West Virginia Public Service Commission (WVPSC) for intrastate transportation service. As such, the transportation rates and terms of service of our pipeline subsidiary, Cranberry Pipeline Corporation, are subject to the rules and regulations of the FERC and the WVPSC. Our natural gas gathering and transmission pipeline systems enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, local distribution companies and industrial end users. Control of our gathering and transmission pipeline systems also enables us to purchase, transport and sell natural gas produced by third parties. In addition, we can engage in development drilling without relying upon third parties to transport our natural gas and incur only the incremental costs of pipeline and compressor additions to our system. We have two natural gas storage fields located in West Virginia with a combined working capacity of approximately 4 Bcf. We use these storage fields to take advantage of the seasonal variations in the demand for natural gas and the higher prices typically associated with winter natural gas sales, while maintaining production at a nearly constant rate throughout the year. The storage fields also enable us to increase for shorter intervals of time the volume of natural gas that we can deliver by more than 40% above the volume that we could deliver solely from our production in the East region. The pipeline systems and storage fields are fully integrated with our operations.
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Table of ContentsIndex to Financial StatementsThe principal markets for our East region natural gas are in the northeast United States. We sell natural gas to industrial customers, local distribution companies and gas marketers both on and off our pipeline and gathering system. Approximately 70% of our natural gas sales volume in the East region is sold at index-based prices under contracts with a term of one year or greater. In addition, spot market sales are made at index-based prices under month-to-month contracts, while industrial and utility sales generally are made under year-to-year contracts. Approximately two percent of East production is sold on fixed price contracts that typically renew annually. GULF COAST REGION Our development, exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in east and south Texas and north Louisiana. A regional office in Houston manages the operations. Principal producing intervals are in the Cotton Valley and James Lime formations in north Louisiana and east Texas and the Frio, Vicksburg and Wilcox formations in south Texas at depths ranging from 2,200 to 17,700 feet, with an average depth of approximately 10,800 feet. Capital and exploration expenditures were $291.5 million for 2007, or 46% of our total 2007 capital and exploration expenditures, compared to $234.8 million for 2006, or 44% of our total 2006 capital and exploration expenditures. For 2008, we have budgeted approximately $209 million for capital and exploration expenditures in the region. Our 2008 Gulf Coast drilling program will emphasize activity primarily in east Texas. We had 685 wells (464.1 net) in the Gulf Coast region as of December 31, 2007, of which 502 wells are operated by us. Average daily production in 2007 was 83.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2007 was 26.8 Bcf and 606 Mbbls, respectively. At December 31, 2007, we had 324.2 Bcfe of proved reserves (89% natural gas) in the Gulf Coast region, which represented 20% of our total proved reserves. Developed and undeveloped reserves made up 207.9 Bcfe and 116.3 Bcfe of the total proved reserves for the Gulf Coast region, respectively. While no properties are individually significant to our company as a whole, the Minden field in east Texas is included in our ten largest fields based on percentage of our total company proved equivalent reserves. In 2007, we drilled 92 wells (71.0 net) in the Gulf Coast region, of which 87 wells (66.5 net) were development and extension wells. In 2008, we plan to drill 69 wells (51.3 net), primarily in east Texas, including the Minden, County Line and Trawick fields. Our principal markets for Gulf Coast region natural gas are in the industrialized Gulf Coast area and the northeast United States. We sell natural gas to intrastate pipelines, natural gas processors and marketing companies. Currently, approximately 50% of our natural gas sales volumes in the Gulf Coast region are sold at index-based prices under contracts with terms of one to three years. The remaining 50% of our sales volumes are sold at index-based prices under short-term agreements. The Gulf Coast properties are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets. In 2007, we produced and marketed approximately 1,659 barrels of crude oil/condensate per day in the Gulf Coast region at market responsive prices. WEST REGION Our activities in the West region, which is comprised of the Rocky Mountains and Mid-Continent areas, are managed by a regional office in Denver, Colorado. At December 31, 2007, we had 477.5 Bcfe of proved reserves (96% natural gas) in the West region, constituting 30% of our total proved reserves. Developed and undeveloped
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Table of ContentsIndex to Financial Statementsreserves made up 384.4 Bcfe and 93.1 Bcfe of the total proved reserves for the West region, respectively. While no properties are individually significant to our company as a whole, the Mocane-Laverne field in Oklahoma in the Mid-Continent area and the Lincoln Road and Cow Hollow fields in Wyoming in the Rocky Mountain area are included within our ten largest fields and together contain approximately 10% of our total company proved equivalent reserves. Our principal markets for West region natural gas are in the northwest and midwest United States. We sell natural gas to power generators, natural gas processors, local distribution companies, industrial customers and marketing companies. Currently, approximately 90% of our natural gas production in the West region is sold primarily under contracts with a term of one to three years at index-based prices. Another nine percent of the natural gas production is sold under short-term arrangements at index-based prices, and the remaining one percent is sold under certain fixed-price contracts. The West region properties are connected to the majority of the midwest and northwest interstate and intrastate pipelines, affording us access to multiple markets. In 2007, we produced and marketed approximately 476 barrels of crude oil/condensate per day in the West region at market responsive prices. Rocky Mountains Activities in the Rocky Mountains are concentrated in the Green River and Washakie Basins in Wyoming and Paradox Basin in Colorado. At December 31, 2007, we had 271.6 Bcfe of proved reserves (96% natural gas) in the Rocky Mountains area, or 17% of our total proved reserves. Capital and exploration expenditures in the Rocky Mountains were $54.7 million for 2007, or nine percent of our total 2007 capital and exploration expenditures, compared to $66.2 million for 2006, or 12% of our total 2006 capital and exploration expenditures. For 2008, we have budgeted approximately $23 million for capital and exploration expenditures in the area. We had 677 wells (302.0 net) in the Rocky Mountains area as of December 31, 2007, of which 340 wells are operated by us. Principal producing intervals in the Rocky Mountains area are in the Almond, Frontier, Dakota and Honaker Trail formations at depths ranging from 4,200 to 14,375 feet, with an average depth of approximately 10,900 feet. Average net daily production in the Rocky Mountains during 2007 was 41.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2007 was 14.4 Bcf and 114 Mbbls, respectively. In 2007, we drilled 49 wells (26.2 net) in the Rocky Mountains, of which 47 wells (25.0 net) were development wells. In 2008, we plan to drill 16 wells (6.8 net), primarily in Wyoming, including the Cow Hollow and Lincoln Road fields. Mid-Continent Our Mid-Continent activities are concentrated in the Anadarko Basin in southwest Kansas, Oklahoma and the panhandle of Texas. At December 31, 2007, we had 205.9 Bcfe of proved reserves (97% natural gas) in the Mid-Continent area, or 14% of our total proved reserves. Capital and exploration expenditures were $54.5 million for 2007, or eight percent of our total 2007 capital and exploration expenditures, compared to $39.8 million for 2006, or seven percent of our total 2006 capital and exploration expenditures. For 2008, we have budgeted approximately $56 million for capital and exploration expenditures in the area. As of December 31, 2007, we had 778 wells (541.8 net) in the Mid-Continent area, of which 605 wells are operated by us. Principal producing intervals in the Mid-Continent are in the Chase, Morrow and Chester formations at depths ranging from 2,200 to 17,500 feet, with an average depth of approximately 7,050 feet. Average net daily production in 2007 was 31.2 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2007 was 11.0 Bcf and 66 Mbbls, respectively.
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Table of ContentsIndex to Financial StatementsIn 2007, we drilled 56 wells (43.9 net) in the Mid-Continent, all of which were development wells. In 2008, we plan to drill 66 wells (48.0 net), primarily in Oklahoma, including the Mocane-Laverne field.
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Table of ContentsIndex to Financial StatementsCANADA REGION Our activities in the Canada region are managed by a regional office in Calgary, Alberta. Our Canadian exploration, development and producing activities are concentrated in the Province of Alberta. At December 31, 2007, we had 35.8 Bcfe of proved reserves (97% natural gas) in the Canada region, constituting two percent of our total proved reserves. Developed and undeveloped reserves made up 32.6 Bcfe and 3.2 Bcfe of the total proved reserves for the Canada region, respectively. No properties in the Canada region are individually significant to our company as a whole. The largest field in this region is the Hinton field in Alberta, which is not included in our ten largest fields. Capital and exploration expenditures in Canada were $55.1 million for 2007, or nine percent of our total 2007 capital and exploration expenditures, compared to $49.0 million for 2006, or nine percent of our total 2006 capital and exploration expenditures. For 2008, we have budgeted approximately $13 million for capital and exploration expenditures in the area. We had 38 wells (13.4 net) in the Canada region as of December 31, 2007, of which 21 wells are operated by us. Principal producing intervals in the Canada region are in the Falher, Bluesky, Cadomin, Dunvegan and the Mountain Park formations at depths ranging from 8,500 to 14,500 feet, with an average depth of approximately 10,950 feet. Average net daily production in Canada during 2007 was 11.0 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2007 was 3.9 Bcf and 18 Mbbls, respectively. In 2007, we drilled 10 wells (5.2 net) in Canada, of which 8 wells (4.0 net) were development and extension wells. In 2008, we plan to drill 3 wells (1.3 net) in various fields in Alberta. Our principal markets for Canada natural gas are in western Alberta. We sell natural gas to gas marketers. Currently, all of our natural gas production in Canada is sold primarily under contracts with a term of one year at index-based prices. The Canadian properties are connected to the major interstate pipelines. In 2007, we produced and marketed approximately 48 barrels of crude oil/condensate per day in the Canada region at market responsive prices. RISK MANAGEMENT From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. While there are many different types of derivatives available, in 2007 we employed natural gas price collar and swap agreements and crude oil price collar agreements for portions of our 2007 and 2008 production to attempt to manage price risk more effectively. The collar arrangements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price is below the floor. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of natural gas for the period is greater or less than the fixed price established for that period when the swap is put in place. In 2006 and 2005, we also employed natural gas and crude oil price collar agreements. Additionally, in 2005, we employed natural gas price swap agreements. At December 31, 2007, we have natural gas price collar and swap arrangements and crude oil price collar arrangements in place for 2008. We will continue to evaluate the benefit of employing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk” for further discussion concerning our use of derivatives.
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Table of ContentsIndex to Financial StatementsRESERVES Current Reserves The following table presents our estimated proved reserves at December 31, 2007.
The proved reserve estimates presented here were prepared by our petroleum engineering staff and reviewed by Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents concluded the following: In their judgment we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues; we used appropriate engineering, geologic and evaluation principles and techniques in accordance with practices generally accepted in the petroleum industry in making our estimates and projections and our total proved reserves are reasonable. For additional information regarding estimates of proved reserves, the review of such estimates by Miller and Lents, Ltd., and other information about our oil and gas reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8. A copy of the review letter by Miller and Lents, Ltd. has been filed as an exhibit to this Form 10-K. Our estimates of proved reserves in the table above are consistent with those filed by us with other federal agencies. During 2007, we filed estimates of our oil and gas reserves for the year 2006 with the Department of Energy. These estimates differ by 5 percent or less from the reserve data presented. Our reserves are sensitive to natural gas and crude oil sales prices and their effect on economic producing rates. Our reserves are based on oil and gas index prices in effect on the last day of December 2007. If we had considered the impact of our hedging activities, which were in a receivable position at December 31, 2007, in our proved reserves, there would not have been any significant effect. For additional information about the risks inherent in our estimates of proved reserves, see “Risk Factors—Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.
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Table of ContentsIndex to Financial StatementsHistorical Reserves The following table presents our estimated proved reserves for the periods indicated.
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Table of ContentsIndex to Financial StatementsVolumes and Prices: Production Costs The following table presents regional historical information about our net wellhead sales volume for natural gas and crude oil (including condensate and natural gas liquids), produced natural gas and crude oil realized sales prices, and production costs per equivalent.
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Table of ContentsIndex to Financial StatementsAcreage The following tables summarize our gross and net developed and undeveloped leasehold and mineral acreage at December 31, 2007. Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.
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Table of ContentsIndex to Financial StatementsTotal Net Leasehold Acreage by Region of Operation
Total Net Undeveloped Acreage Expiration by Region of Operation The following table presents our net undeveloped acreage expiring over the next three years by operating region as of December 31, 2007. The figures below assume no future successful development or renewal of undeveloped acreage.
Well Summary The following table presents our ownership at December 31, 2007, in productive natural gas and oil wells in the East region (consisting of various fields located in West Virginia, Virginia and Ohio), in the Gulf Coast region (consisting primarily of various fields located in Louisiana and Texas), in the West region (consisting of various fields located in Oklahoma, Kansas, Colorado, Utah and Wyoming) and in the Canada region (consisting of various fields located in the Province of Alberta). This summary includes natural gas and oil wells in which we have a working interest.
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Table of ContentsIndex to Financial StatementsDrilling Activity We drilled wells, participated in the drilling of wells, or acquired wells as indicated in the region tables below.
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Table of ContentsIndex to Financial Statements
Competition Competition in our primary producing areas is intense. Price, contract terms and quality of service, including pipeline connection times and distribution efficiencies, affect competition. We believe that in the East region our extensive acreage position, existing natural gas gathering and pipeline systems, services and equipment that we have secured for the upcoming year and storage fields enhance our competitive position over other producers who do not have similar systems or facilities in place. We also actively compete against other companies with substantially larger financial and other resources. OTHER BUSINESS MATTERS Major Customer In 2007 and 2006, no customer accounted for more than 10% of our total sales. In 2005, approximately 11% of our total sales were made to one customer. Seasonality Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the colder winter months. Regulation of Oil and Natural Gas Exploration and Production Exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field, and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo constant review
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Table of ContentsIndex to Financial Statementsand often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. We do not believe, however, we are affected differently by these regulations than others in the industry. Natural Gas Marketing, Gathering and Transportation Federal legislation and regulatory controls have historically affected the price of the natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938 (NGA), the FERC regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC has granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of gas for resale without further FERC approvals. As a result, all of our produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the provisions of the Energy Policy Act of 2005, the NGA has been amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas. The FERC established new regulations that are intended to increase natural gas pricing transparency through, among other things, requiring market participants to report their gas sales transactions annually to the FERC. The 2005 Act also significantly increases the penalties for violations of the NGA. Our natural gas sales prices nevertheless continue to be affected by intrastate and interstate gas transportation regulation, because the prices we receive for our production are affected by the cost of transporting the gas to the consuming market. Through a series of comprehensive rulemakings, beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of gas to the primary role of gas transporters, and by increasing the transparency of pricing for pipeline services. The FERC has also established interim rules governing the relationship of pipelines with their marketing affiliates, and has initiated a rulemaking proceeding to consider whether to make those rules permanent. The FERC has also implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis. In light of these statutory and regulatory changes, most pipelines have divested their gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants, and most pipelines have also implemented the large-scale divestiture of their gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines thus now generally provide unbundled, open and nondiscriminatory transportation and transportation-related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. Sellers and buyers of gas have gained direct access to the particular pipeline services they need, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. Certain of our pipeline systems and storage fields in West Virginia are regulated for safety compliance by the U.S. Department of Transportation (DOT) and the West Virginia Public Service Commission. In 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (2002 Act), which contains a number of provisions intended to increase pipeline operating safety. The DOT’s final regulations implementing the act became effective February 2004. Among other provisions, the regulations require that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission and non-rural gathering pipeline facilities within the next ten years, and at least every seven years thereafter. On March 15, 2006, the DOT revised these regulations to define more clearly the categories of gathering facilities subject to DOT regulation,
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Table of ContentsIndex to Financial Statementsestablish new safety rules for certain gathering lines in rural areas, revise the current regulations applicable to safety and inspection of gathering lines in non-rural areas, and adopt new compliance deadlines. In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, which reauthorized the programs adopted under the 2002 Act, proposed enhancements for state programs to reduce excavation damage to pipelines, established increased federal enforcement of one-call excavation programs, and established a new program for review of pipeline security plans and critical facility inspections. We have substantially completed the required initial inspection (baseline assessment) of our pipeline systems in West Virginia, and expect to complete that assessment within the required timeline. We are not able to predict with certainty the final outcome of these rules on our facilities or our business. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, it is impossible to predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, and despite the recent trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas, cannot be predicted. Federal Regulation of Petroleum Our sales of oil and natural gas liquids are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In March 2006, to implement this required five-year re-determination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 1.3 percent should be the oil pricing index for the five-year period beginning July 1, 2006. Another FERC proceeding that may impact our transportation costs relates to an ongoing proceeding to determine whether and to what extent pipelines should be permitted to include in their transportation rates an allowance for income taxes attributable to non-corporate partnership interests. Following a court remand, the FERC has established a policy that a pipeline structured as a master limited partnership or similar non-corporate entity is entitled to a tax allowance with respect to income for which there is an “actual or potential income tax liability,” to be determined on a case by case basis. Generally speaking, where the holder of a partnership unit interest is required to file a tax return that includes partnership income or loss, such unit-holder is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. We are not able to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index, or of the application of the FERC’s new policy on income tax allowances. Environmental Regulations General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Government regulations can increase the cost of planning, designing, installing and operating oil and gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and gas production operations. No assurance can be given that significant costs and liabilities will not be incurred.
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Table of ContentsIndex to Financial StatementsAlso, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production could result in substantial costs and liabilities to us. The transition zone and shallow-water areas of the U.S. Gulf Coast are ecologically sensitive. Environmental issues have led to higher drilling costs and a more difficult and lengthy well permitting process. U.S. laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment, requiring consistency with applicable coastal zone management plans, or otherwise relating to the protection of the environment. Solid and Hazardous Waste. We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other solid wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become more strict over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination. We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today. Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the owner and operator of a site and any party that disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In the course of business, we have generated and will continue to generate wastes that may fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such wastes have been disposed. Oil Pollution Act. The Federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term “waters of the United States” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. We believe that we substantially comply with the Oil Pollution Act and related federal regulations. Clean Water Act. The Federal Water Pollution Control Act (Clean Water Act) and resulting regulations, which are implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities that are the source of water discharges. We believe that we substantially comply with the Clean Water Act and related federal and state regulations. Clean Air Act. Our operations are subject to local, state and federal laws and regulations to control emissions from
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Table of ContentsIndex to Financial Statementssources of air pollution. Payment of fines and correction of any identified deficiencies generally resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease construction or operation of certain facilities that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations. Employees As of December 31, 2007, we had 404 active employees. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. The Company and its employees are not represented by a collective bargaining agreement. Website Access to Company Reports We make available free of charge through our website, www.cabotog.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). Information on our website is not a part of this report. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information filed by the Company. The public may read and copy materials that we file with the SEC at the SEC’s Public Reference Room located at 100 F Street, NE, Washington, DC 20549. Information regarding the operation of the Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330. Corporate Governance Matters The Company’s Corporate Governance Guidelines, Corporate Bylaws, Code of Business Conduct, Corporate Governance and Nominations Committee Charter, Compensation Committee Charter and Audit Committee Charter are available on the Company’s website at www.cabotog.com, under the “Corporate Governance” section of “Investor Relations” and a copy will be provided, without charge, to any shareholder upon request. Requests can also be made in writing to Investor Relations at our corporate headquarters at 1200 Enclave Parkway, Houston, Texas, 77077. We have filed the required certifications of our chief executive officer and our chief financial officer under Section 302 of the Sarbanes-Oxley Act of 2002 as exhibits 31.1 and 31.2 to this Form 10-K. In 2007, we submitted to the New York Stock Exchange the chief executive officer certification required by Section 303A.12(a) of the NYSE’s Listed Company Manual.
Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business. Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. Because our reserves are predominantly natural gas, changes in natural gas prices have a particularly large impact on our financial results. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:
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Table of ContentsIndex to Financial Statements
These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. If natural gas prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations. Drilling natural gas and oil wells is a high-risk activity. Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:
Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate for activity within a particular geographic area may decline. We may ultimately not be able to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may not be able to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:
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Table of ContentsIndex to Financial Statements
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Table of ContentsIndex to Financial StatementsThese projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil. High demand for field services and equipment and the ability of suppliers to meet that demand may limit our ability to drill and produce our natural gas and oil properties. Due to current industry demands, well service providers and related equipment and personnel are in short supply. This may cause escalating prices, delays in drilling and other exploration activities, the possibility of poor services coupled with potential damage to downhole reservoirs and personnel injuries. Such pressures would likely increase the actual cost of services, extend the time to secure such services and add costs for damages due to any accidents sustained from the over use of equipment and inexperienced personnel. Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as natural gas and oil prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and crude oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves. You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board in Statement of Financial Accounting Standards No. 69 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable. In general, the production rate of natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and oil production and lower revenues and cash flow from operations. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low natural gas and oil prices may further limit the kinds of reserves that we can develop economically. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.
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Table of ContentsIndex to Financial StatementsOur reserve report estimates that production from our proved developed producing reserves as of December 31, 2007 will decline at estimated rates of three percent, 15%, 13% and 10% during 2008, 2009, 2010 and 2011, respectively. Future development of proved undeveloped and other reserves currently not classified as proved developed producing will impact these rates of decline. Because of higher initial decline rates from newly developed reserves, we consider this pattern fairly typical. Exploration, development and exploitation activities involve numerous risks that may result in dry holes, the failure to produce natural gas and oil in commercial quantities and the inability to fully produce discovered reserves. From time to time, we may identify and evaluate opportunities to acquire natural gas and oil properties. We may not be able to successfully consummate any acquisition, to acquire producing natural gas and oil properties that contain economically recoverable reserves, or to integrate the properties into our operations profitably. We face a variety of hazards and risks that could cause substantial financial losses. Our business involves a variety of operating risks, including:
In addition, we conduct operations in shallow offshore areas (largely coastal waters), which are subject to additional hazards of marine operations, such as capsizing, collision and damage from severe weather. Any of these events could result in injury or loss of human life, loss of hydrocarbons, significant damage to or destruction of property, environmental pollution, regulatory investigations and penalties, impairment of our operations and substantial losses to us. Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. As of December 31, 2007, we owned or operated approximately 3,300 miles of natural gas gathering and pipeline systems. As part of our normal maintenance program, we have identified certain segments of our pipelines that we believe periodically require repair, replacement or additional maintenance. We may not be insured against all of the operating risks to which we are exposed. We maintain insurance against some, but not all, of these risks and losses. We do not carry business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.
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Table of ContentsIndex to Financial StatementsWe have limited control over the activities on properties we do not operate. Other companies operate some of the properties in which we have an interest. Non-operated wells represented approximately 15% of our total owned gross wells, or approximately 4.7% of our owned net wells, as of December 31, 2007. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs. Terrorist activities and the potential for military and other actions could adversely affect our business. The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business. Our ability to sell our natural gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing. The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. Our failure to obtain these services on acceptable terms could materially harm our business. Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position. Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for natural gas and oil. From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. While there are many different types of derivatives available, in 2007 we employed natural gas price collar and swap agreements and crude oil price collar agreements covering portions of our 2007 production and anticipated 2008 production to attempt to manage price risk more effectively. The collar arrangements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price is below the floor. The price swaps call for payments to, or receipts from, counterparties based on whether
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Table of ContentsIndex to Financial Statementsthe market price of natural gas for the period is greater or less than the fixed price established for that period when the swap is put in place. These hedging arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:
We will continue to evaluate the benefit of employing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A for further discussion concerning our use of derivatives. The loss of key personnel could adversely affect our ability to operate. Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed. We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business. Our operations are subject to extensive federal, state and local laws and regulations, including tax laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities. Provisions of Delaware law and our bylaws and charter could discourage change in control transactions and prevent stockholders from receiving a premium on their investment. Our bylaws provide for a classified Board of Directors with staggered terms, and our charter authorizes our Board of Directors to set the terms of preferred stock. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Our bylaws prohibit stockholder action by written consent and limit stockholder proposals at meetings of stockholders. We also have adopted a stockholder rights plan. Because of our stockholder rights plan and these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors.
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Table of ContentsIndex to Financial StatementsThe personal liability of our directors for monetary damages for breach of their fiduciary duty of care is limited by the Delaware General Corporation Law and by our certificate of incorporation. The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors’ duty of care to equitable remedies such as injunction or rescission. Our certificate of incorporation limits the liability of our directors to the fullest extent permitted by Delaware law. Specifically, our directors will not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liability:
This limitation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our stockholders.
None.
See Item 1. Business.
We are a defendant in various legal proceedings arising in the normal course of our business. All known liabilities are accrued based on management’s best estimate of the potential loss. While the outcome and impact of such legal proceedings on us cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved. West Virginia Royalty Litigation In December 2001, we were sued by two royalty owners in West Virginia state court for an unspecified amount of damages. The plaintiffs requested class certification and alleged that we failed to pay royalty based upon the wholesale market value of the gas, that we had taken improper deductions from the royalty and that we failed to properly inform royalty owners of the deductions. The plaintiffs also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that we reached with Columbia Gas Transmission Corporation in 1995 bankruptcy proceedings. The Court entered an order on June 1, 2005 granting the motion for class certification. The parties reached a tentative settlement in 2007, pursuant to which we paid $11.6 million into a trust fund which will disburse the settlement proceeds to the class members upon final approval of the settlement by the Court. These restricted cash funds are held by a financial institution in West Virginia under the joint custody of the plaintiffs and us. These funds have been classified within Other Current Assets in the Consolidated Balance Sheet. Subsequent to reaching the tentative settlement, it was determined that an additional payment of $0.4 million
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Table of ContentsIndex to Financial Statementswould be required to account for production from new wells that came on-line during the process of settlement negotiations and were not included in the volumes upon which the $11.6 million settlement was reached. The additional funds bring the total to be paid by us to $12.0 million. In the tentative settlement, we also agreed with the class members to a methodology for payment of future royalties and the reporting format such methodology will take. The tentative settlement was not to be final or binding until approved by the Court. The hearing for final approval of the settlement was held on February 12, 2008. The Court approved the final settlement at the hearing. Upon filing of the written Order of Approval by the Court, the process will begin for distribution of the settlement proceeds from the trust. We had provided a reserve sufficient to cover the amount agreed upon to settle this litigation. Commitment and Contingency Reserves We have established reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that we could incur approximately $8.4 million of additional loss with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued. While the outcome and impact on us cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.
No matters were submitted to a vote of security holders during the fourth quarter of 2007. EXECUTIVE OFFICERS OF THE REGISTRANT The following table shows certain information as of February 15, 2008 about our executive officers, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.
All officers are elected annually by our Board of Directors. All of the executive officers have been employed by Cabot Oil & Gas Corporation for at least the last five years.
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Table of ContentsIndex to Financial StatementsPART II
The common stock is listed and principally traded on the New York Stock Exchange under the ticker symbol “COG.” The following table presents the high and low closing sales prices per share of the common stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the common stock are also shown. A regular dividend has been declared each quarter since we became a public company in 1990. On February 23, 2007, our Board of Directors declared a 2-for-1 split of our common stock in the form of a stock distribution. The stock dividend was distributed on March 30, 2007 to stockholders of record on March 16, 2007. All common stock accounts and per share data, including cash dividends per share, have been retroactively adjusted to give effect to the 2-for-1 split of our common stock. After the stock split, the dividend was increased to $0.03 per share per quarter, or a 50% increase from pre-split levels.
As of January 31, 2007, there were 574 registered holders of the common stock. Shareholders include individuals, brokers, nominees, custodians, trustees, and institutions such as banks, insurance companies and pension funds. Many of these hold large blocks of stock on behalf of other individuals or firms. ISSUER PURCHASES OF EQUITY SECURITIES Our Board of Directors has authorized a share repurchase program under which we may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. During 2007, we did not repurchase any shares of common stock. All purchases executed to date have been through open market transactions. The maximum number of shares that may yet be purchased under the plan as of December 31, 2007 was 4,795,300.
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Table of ContentsIndex to Financial StatementsPERFORMANCE GRAPH The following graph compares our common stock performance (“COG”) with the performance of the Standard & Poors’ 500 Stock Index and the Dow Jones US Exploration & Production Index for the period December 2002 through December 2007. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 2002 and that all dividends were reinvested.
The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933 unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A.
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Table of ContentsIndex to Financial Statements
The following table summarizes our selected consolidated financial data for the periods indicated. This information should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7, and the Consolidated Financial Statements and related Notes in Item 8.
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Table of ContentsIndex to Financial Statements
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. Please read “Forward-Looking Information” for further details. We operate in one segment, natural gas and oil development, exploitation and exploration, exclusively within the United States and Canada. OVERVIEW Cabot Oil & Gas and its subsidiaries are a leading independent oil and gas company engaged in the development, exploitation, exploration, production and marketing of natural gas, and to a lesser extent, crude oil and natural gas liquids from its properties in North America. We also transport, store, gather and produce natural gas for resale. Our exploitation and exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. Our program is designed to be disciplined and balanced with a focus on achieving strong financial returns. At Cabot, there are three types of investment alternatives that compete for available capital: drilling opportunities, financial opportunities such as debt repayment or repurchase of common stock and, to a lesser extent, acquisition opportunities. Depending on circumstances, we allocate capital among the alternatives based on a rate-of-return approach. Our goal is to invest capital in the highest return opportunities available at any given time. At any one time, one or more of these may not be economically feasible. Our financial results depend upon many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Price volatility in the commodity markets has remained prevalent in the last few years. Throughout 2006 and 2007, the futures market reported strong natural gas and crude oil contract prices. Our realized natural gas and crude oil price was $7.23 per Mcf and $67.16 per Bbl, respectively, in 2007. These realized prices include the realized impact of derivative instruments. In an effort to manage commodity price risk, we entered into a series of crude oil and natural gas price collars. These financial instruments are an important element of our risk management strategy and assisted in the increase in our realized natural gas price from 2006 to 2007. Commodity prices are impacted by many factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market demands, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices, and therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. See “Risk Factors—Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business” and “Risk Factors—Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable” in Item 1A.
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Table of ContentsIndex to Financial StatementsThe tables below illustrate how natural gas prices have fluctuated by month over 2006 and 2007. “Index” represents the first of the month Henry Hub index price per Mmbtu. The “2006” and “2007” price is the natural gas price per Mcf realized by us and includes the realized impact of our natural gas price collar and swap arrangements, as applicable:
We reported earnings of $1.73 per share, or $167.4 million, for 2007. This is down from the $3.32 per share, or $321.2 million, reported in 2006. Earnings decreased from 2006 to 2007 primarily due to the $231.2 million ($144.5 million, net of tax) gain recorded in 2006 related to the 2006 south Louisiana and offshore properties sale. Natural gas revenues increased from 2006 to 2007 as a result of an increase in realized prices, resulting from favorable natural gas hedge settlements, and increased natural gas production. Crude oil revenues decreased from 2006 to 2007 primarily due to decreased Gulf Coast production related primarily to the 2006 south Louisiana and offshore properties sale. Prices, including the realized impact of derivative instruments, increased by one percent for natural gas and three percent for oil. We drilled 461 gross wells with a success rate of 96% in 2007 compared to 387 gross wells with a success rate of 96% in 2006. Total capital and exploration expenditures increased by $98.7 million to $636.2 million in 2007 compared to $537.5 million in 2006. We believe our cash on hand and operating cash flow in 2008 will be sufficient to fund a substantial portion of our budgeted capital and exploration spending of approximately $490 million. Any additional needs will be funded by borrowings from our credit facility. Our 2008 strategy will remain consistent with 2007. We will remain focused on our strategy of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we will continue to add to our acreage position in certain areas for future drilling opportunities. In the current year we have allocated our planned program for capital and exploration expenditures among our various operating regions. We believe that these strategies are appropriate for our portfolio of projects and the current industry environment and that this activity will continue to add shareholder value over the long term. The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read “Forward-Looking Information” for further details.
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Table of ContentsIndex to Financial StatementsFINANCIAL CONDITION Capital Resources and Liquidity Our primary sources of cash in 2007 were from funds generated from the sale of natural gas and crude oil production and borrowings under our revolving credit facility. Cash flows provided by operating activities were primarily used to fund development and, to a lesser extent, exploratory expenditures, and to pay dividends. See below for additional discussion and analysis of cash flow. We generate cash from the sale of natural gas and crude oil. Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes. Prices for crude oil and natural gas have historically been volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have also influenced prices throughout the recent years. In addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on sales. Working capital is also substantially influenced by these variables discussed above. From time to time, our working capital will reflect a surplus, while at other times it will reflect a deficit. This fluctuation is not unusual. We believe we have adequate liquidity available to meet our working capital requirements.
Operating Activities. Net cash provided by operating activities in 2007 increased by $105.0 million over 2006. This increase was mainly due to a decrease in cash paid for current income taxes from 2006 to 2007 primarily due to the 2006 payment of approximately $102 million related to the 2006 south Louisiana and offshore properties sale, as well as our 2007 tax net operating loss position and the receipt in 2007 of $29.6 million in federal tax refunds relating to our 2006 tax return. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased by one percent in 2007 over 2006 and average crude oil realized prices increased by three percent over the same period. Equivalent production decreased by three percent in 2007 compared to 2006 as a result of a decrease in crude oil production, offset in part by an increase in natural gas production. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities. Net cash provided by operating activities in 2006 decreased by $7.5 million over 2005. This decrease was primarily due to an increase in current income tax expense, partially offset by an increase in earnings and an increase in working capital changes. The increase in cash paid for income taxes from 2005 to 2006 is primarily due to the December 2006 payment of approximately $102 million related to the 2006 south Louisiana and offshore properties sale. Other factors impacting net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased six percent over 2005, while crude oil realized prices increased 47% over the same period. Equivalent production increased by five percent in 2006 compared to 2005. See “Results of Operations” for a discussion on commodity prices and a review of the impact of prices and volumes on sales revenue. Investing Activities. The primary uses of cash in investing activities were capital spending and exploration expenses. We established the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices and new opportunities which may arise, our capital expenditures may be periodically adjusted during any given year. Cash flows used in investing activities increased by $402.6 million from 2006 to 2007 and decreased by $224.8 million from 2005 to 2006. The increase from 2006 to 2007 was due to a decrease of $322.4 million in 2007 in proceeds from the sale of assets and an increase of $89.8 million in 2007 in capital expenditures, partially offset by reduced exploration expenses of $9.6 million.
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Table of ContentsIndex to Financial StatementsCash flows used in investments in capital and exploration expenditures were $516.8 million in 2006 compared to $413.1 million used in 2005, in response to higher commodity prices. This increase of $103.7 million in investments in capital and exploration expenses was entirely offset by the increase of $328.5 million in proceeds from the sale of assets, primarily as a result of the 2006 south Louisiana and offshore properties sale. Financing Activities. Cash flows provided by financing activities were $104.4 million for 2007, and contained a net increase in borrowings under our revolving credit facility and proceeds from the exercise of stock options, partially offset by dividend payments. Cash flows used in financing activities were $138.5 million for 2006, and were comprised of payments made to decrease outstanding debt under our revolving credit facility, to purchase treasury stock and to pay dividends. Partially offsetting these cash uses were inflows from the exercise of stock options and the tax benefit received from stock-based compensation. Cash flows provided by financing activities were $48.2 million for 2005, resulting from borrowings under the credit facility, partially offset by the purchase of treasury stock and dividend payments. At December 31, 2007, we had $140 million of borrowings outstanding under our credit facility at a weighted-average interest rate of 6.9%. The credit facility provides for an available credit line of $250 million, which can be expanded up to $350 million, either with the existing banks or new banks. The available credit line is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the banks’ petroleum engineer) and other assets. The revolving term of the credit facility ends in December 2009. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Management believes that we have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including potential acquisitions. Our Board of Directors has authorized a share repurchase program under which we may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. We did not repurchase any shares of our common stock during 2007. All purchases executed to date have been through open market transactions. The maximum number of shares that may yet be purchased under the plan as of December 31, 2007 was 4,795,300. See Item 5 “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for additional information. Capitalization Information about our capitalization is as follows:
For the year ended December 31, 2007, we paid dividends of $10.7 million on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990. After the March 2007 2-for-1 stock split, the dividend was increased to $0.03 per share per quarter, or a 50% increase from pre-split levels.
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Table of ContentsIndex to Financial StatementsIncrease in Authorized Shares On May 4, 2006, our stockholders approved an increase in the authorized number of shares of our common stock from 80 million to 120 million shares. We correspondingly increased the number of shares of Series A Junior Participating Preferred Stock reserved for issuance from 800,000 to 1,200,000. The shares of Series A Junior Participating Preferred Stock are issuable pursuant to our Rights Agreement with The Bank of New York, as Rights Agent. Capital and Exploration Expenditures On an annual basis, we generally fund most of our capital and exploration activities, excluding any significant oil and gas property acquisitions, with cash generated from operations and, when necessary, our revolving credit facility. We budget these capital expenditures based on our projected cash flows for the year. The following table presents major components of our capital and exploration expenditures for the three years ended December 31, 2007.
We plan to drill approximately 419 gross wells (366 net) in 2008 compared with 461 gross wells (391 net) drilled in 2007. The number of wells we plan to drill in 2008 is down from 2007 primarily due to lower planned activity in the Rocky Mountains area based on lower natural gas prices and lower planned activity in Canada based on uncertainty around royalties and exchange rates. This 2008 drilling program includes approximately $490 million in total capital and exploration expenditures, down from $636.2 million in 2007. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly. There are many factors that impact our depreciation, depletion and amortization (DD&A) rate. These include reserve additions and revisions, development costs, impairments and changes in anticipated production in a future period. In 2008, management expects an increase in our DD&A rate due to higher capital costs, partially as a result of inflationary cost pressures in the industry over the last four years. This change is currently estimated to be approximately five percent greater than 2007 levels. This increase will not have an impact on our cash flows. Contractual Obligations Our known material contractual obligations include long-term debt, interest on long-term debt, firm gas transportation agreements, drilling rig commitments and operating leases. We have no off-balance sheet debt or other similar unrecorded obligations. During 2006, we assisted certain non-executive employees in obtaining loans to purchase interests offered under our Mineral, Royalty and Overriding Royalty Interest Plan by providing a guarantee of repayment should the non-executive employee fail to repay the loan. The repayment term for all of these loans was five years. The outstanding loan balances were approximately $0.3 million in the aggregate as of December 31, 2006 and the fair value of these guarantees were immaterial to our financial statements. There were no outstanding loan balances as of December 31, 2007. All loans were collateralized by the interests transferred to the employees in the producing properties.
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Table of ContentsIndex to Financial StatementsA summary of our known contractual obligations as of December 31, 2007 are set forth in the following table:
Amounts related to our asset retirement obligations are not included in the above table given the uncertainty regarding the actual timing of such expenditures. The total amount of asset retirement obligations at December 31, 2007 was $24.7 million, up from $22.7 million at December 31, 2006, primarily due to $1.0 million of accretion expense during 2007 as well as $1.6 million of drilling additions. Potential Impact of Our Critical Accounting Policies Readers of this document and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. The most significant policies are discussed below. Oil and Gas Reserves The process of estimating quantities of proved reserves is inherently imprecise, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. Since 1990, 100% of our reserves have been reviewed by Miller & Lents, Ltd., an independent oil and gas reservoir engineering consulting firm, who in their opinion determined the estimates presented to be reasonable in the aggregate. We have not been required to record a significant reserve revision in the past three years. For more information regarding reserve estimation, including historical reserve revisions, refer to the “Supplemental Oil and Gas Information.” Our rate of recording DD&A expense is dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower
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Table of ContentsIndex to Financial Statementsmarket prices, which may make it non-economic to drill for and produce higher cost fields. A five percent positive or negative revision to proved reserves throughout the Company would decrease or increase the DD&A rate by approximately $0.08 to $0.09 per Mcfe. Revisions in significant fields may individually affect our DD&A rate. It is estimated that a positive or negative reserve revision of 10% in one of our most productive fields would have a $0.01 to $0.02 impact on our total DD&A rate. These estimated impacts are based on current data, and actual events could require different adjustments to our DD&A rate. In addition, a decline in proved reserve estimates may impact the outcome of our annual impairment test under Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Due to the inherent imprecision of the reserve estimation process, risks associated with the operations of proved producing properties and market sensitive commodity prices utilized in our impairment analysis, management cannot determine if an impairment is reasonably likely to occur in the future. Carrying Value of Oil and Gas Properties We evaluate the impairment of our oil and gas properties on a lease-by-lease basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted cash flows, based on our estimate of future crude oil and natural gas prices, operating costs and anticipated production from proved reserves are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. In 2007, 2006 and 2005, there were no unusual or unexpected occurrences that caused significant revisions in estimated cash flows which were utilized in our impairment test. Costs attributable to our unproved properties are not subject to the impairment analysis described above; however, a portion of the costs associated with such properties is subject to amortization based on past experience and average property lives. Average property lives are determined on a regional basis and based on the estimated life of unproved property leasehold rights. Historically, the average property lives in each of the regions have not significantly changed. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $8.6 million or decrease by approximately $6.5 million, respectively per year. In the past, the average leasehold life in the Gulf Coast region has been shorter than the average life in the East and West regions. Average property lives in the East, Gulf Coast and West regions have been six, four and seven years, respectively. Average property lives in Canada are estimated to be five years. As these properties are developed and reserves are proven, the remaining capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful, the capitalized costs related to the unsuccessful activity is expensed in the year the determination is made. The rate at which the unproved properties are written off depends on the timing and success of our future exploration program. Accounting for Derivative Instruments and Hedging Activities Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. We follow the accounting prescribed in SFAS No. 133. Under SFAS No. 133, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each quarterly period, these instruments are marked-to-market. The gain or loss on the change in fair value is recorded as Accumulated Other Comprehensive Income, a component of equity, to the extent that the derivative instrument is designated as a hedge and is effective. Under SFAS No. 133, effectiveness is a measurement of how closely correlated the hedge instrument is with the underlying physical sale. For example, a natural gas price swap that converts Henry Hub index to a fixed price would be perfectly correlated, and 100% effective, if the underlying gas were sold at the Henry Hub index. The ineffective portion, if any, of the change in the fair value of derivatives designated as hedges, and the change in fair value of all other derivatives, is recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue, as appropriate in the Consolidated Statement of Operations.
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Table of ContentsIndex to Financial StatementsLong-Term Employee Benefit Costs Our costs of long-term employee benefits, particularly pension and postretirement benefits, are incurred over long periods of time, and involve many uncertainties over those periods. The net periodic benefit cost attributable to current periods is based on several assumptions about such future uncertainties, and is sensitive to changes in those assumptions. It is management’s responsibility, often with the assistance of independent experts, to select assumptions that in its judgment represent best estimates of those uncertainties. It also is management’s responsibility to review those assumptions periodically to reflect changes in economic or other factors that affect those assumptions. The current benefit service costs, as well as the existing liabilities, for pensions and other postretirement benefits are measured on a discounted present value basis. The discount rate is a current rate, related to the rate at which the liabilities could be settled. Our assumed discount rate is based on average rates of return published for a theoretical portfolio of high-quality fixed income securities. In order to select the discount rate, we use benchmarks such as the Moody’s Aa Corporate Rate, which was 5.8% as of December 31, 2007, and the Citigroup Pension Liability Index, which was 6.48% as of December 31, 2007. We look to these benchmarks as well as considering durations of expected benefit payments. We have determined based on these assumptions that a discount rate of 6.0% at December 31, 2007 is reasonable. In order to value our pension liabilities, we use the RP-2000 Combined Mortality Table. This is a widely accepted table used for valuing pension liabilities. This table represents a more recent and conservative mortality table than the 1983 Group Annuity Mortality Table, and appears to be an appropriate table based on the demographics of our benefit plans. Another consideration that is made is a salary scale selection. We have assumed that salaries will increase four percent based on our expectation of future salary increases. The benefit obligation and the periodic cost of postretirement medical benefits also are measured based on assumed rates of future increase in the per capita cost of covered health care benefits. As of December 31, 2007, the assumed rate of increase was 9.0%. The net periodic cost of pension benefits included in expense also is affected by the expected long-term rate of return on plan assets assumption. The expected return on plan assets rate is normally changed less frequently than the assumed discount rate, and reflects long-term expectations, rather than current fluctuations in market conditions. The actual rate of return on plan assets may differ from the expected rate due to the volatility normally experienced in capital markets. Management’s goal is to manage the investments over the long term to achieve optimal returns with an acceptable level of risk and volatility. We have established objectives regarding plan assets in the pension plan. We attempt to maximize return over the long-term, subject to appropriate levels of risk. One of our plan objectives is that the performance of the equity portion of the pension plan exceed the Standard and Poors’ 500 Index over the long term. We also seek to achieve a minimum five percent annual real rate of return (above the rate of inflation) on the total portfolio over the long-term. In our pension calculations, we have used eight percent as the expected long-term return on plan assets for 2007, 2006 and 2005. A Monte Carlo simulation was run using 5,000 simulations based upon our actual asset allocation and liability duration, which has been determined to be approximately 16 years. This model uses historical data for the period of 1926-2003 for stocks, bonds and cash to determine the best estimate range of future returns. The median rate of return, or return that we expect to achieve over 50 percent of the time, is approximately nine percent. We expect to achieve a minimum 6.4% annual real rate of return on the total portfolio over the long term at least 75 percent of the time. In addition, the actual rate of return on plan assets annualized over the past ten years is approximately six percent. We believe that the eight percent chosen is a reasonable estimate based on our actual results. We generally target a portfolio of assets utilizing equity securities, fixed income securities and cash equivalents that are within a range of approximately 50% to 80% for equity securities and approximately 20% to 40% for fixed income securities. Large capitalization equities may make up a maximum of 65% of the portfolio. Small capitalization equities and international equities may make up a maximum of 30% and 15%, respectively, of the portfolio. Fixed income bonds may make up a maximum of 40% of our portfolio. The account will typically be fully invested; however, as a temporary investment or an asset protection measure, part of the account may be
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Table of ContentsIndex to Financial Statementsinvested in money market investments up to 20%. One percent of the portfolio is invested in short-term funds at the designated bank to meet the cash flow needs of the plan. No prohibited investments, including direct or indirect investments in commodities, commodity futures, derivatives, short sales, real estate investment trusts, letter stock, restricted stock or other private placements, are allowed without prior committee approval. Stock-Based Compensation Effective January 1, 2006, we adopted the accounting policies described in SFAS No. 123(R), “Share Based Payment (revised 2004).” We chose to use the modified prospective method of transition, and accordingly, no adjustments to prior period financial statements were made. Prior to January 1, 2006, we accounted for stock-based compensation in accordance with the intrinsic value based method prescribed by Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.” Under this method, we recognized compensation cost as the excess, if any, of the quoted market price of our stock at the grant date over the amount an employee must pay to acquire the stock. In addition, SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” outlines a fair value based method of accounting for stock options or similar equity instruments. Under the fair value method, compensation cost is measured at the grant date based on the value of an award and is recognized over the service period, which is usually the vesting period. To calculate the fair value, either a binomial or Black-Scholes valuation model may be used. One primary difference in our method of accounting after the adoption of SFAS No. 123(R) is that unvested stock options are now expensed as a component of Stock-Based Compensation cost in General and Administrative Expense in the Consolidated Statement of Operations. This expense is based on the fair value of the award at the original grant date and is recognized over the vesting period. Prior to the adoption of SFAS No. 123(R), we included this amount as a pro-forma disclosure in the Notes to the Consolidated Financial Statements. The expense resulting from the expensing of stock options was $0.1 million and $0.3 million for the years ended December 31, 2007 and 2006, respectively. Another change relates to the accounting for our performance share awards. Certain of these awards are now accounted for by bifurcating the equity and liability components. A Monte Carlo model is used to value the liability component, rather than accounting for the award using the average closing stock price at the end of each reporting period. All other awards are accounted for in substantially the same way as they were or would have been in prior periods, with the exception of the differences noted below. Other differences in the way we account for stock-based compensation after January 1, 2006, result from the application of a forfeiture rate to all grants rather than only recording actual forfeitures as they occur. We are now required to estimate forfeitures on all equity-based compensation and adjust periodic expense. Upon adoption, we did not report a cumulative effect adjustment for these forfeitures as the amount was immaterial. In addition, this change in accounting for forfeitures resulted in an immaterial change in overall compensation cost for the years ended December 31, 2007 and 2006. Furthermore, we are required to expense certain awards to retirement-eligible employees in the month an employee becomes retirement eligible, depending on the structure of each individual plan. The retirement-eligibility provision only applies to new grants that were awarded after January 1, 2006. The total expense that we recognized related to restricted stock awards and stock appreciation rights granted to retirement-eligible employees in 2007 and 2006 was $0.6 million in each year. We issued stock appreciation rights to executive officers for the first time during the first quarter of 2006. The grant date fair value of these awards is measured using a Black-Scholes model and compensation cost is expensed over the three year graded-vesting service period. Expense related to these awards was $1.5 million and $1.0 million, before the effect of taxes, for 2007 and 2006, respectively. In addition, two new types of performance shares were issued to employees during 2007 and 2006. During 2007, we issued to executive officers a new type of performance share award that vests depending on our operating income. These awards vest based on a three-year graded vesting service period, vesting one-third on each anniversary date following the date of grant, provided that we have positive operating income. If we do not have positive operating income for the year preceding a vesting date, then the portions of the award that would have vested on that date will be forfeited. Compensation cost related to these new operating-income based performance
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Table of ContentsIndex to Financial Statementsshare awards granted to employees was $1.7 million, before the effect of taxes, for 2007. A second new type of performance share award, issued to non-executive employees for the first time in 2006 and again in 2007, measures our performance based on three internal metrics, rather than a peer group’s stock performance which we use to measure certain other performance share awards. These awards cliff vest at the end of the three year service period. Compensation cost related to these internal-metric based performance share awards granted to employees was $4.7 million and $1.4 million, before the effect of taxes, for 2007 and 2006, respectively. Total performance share expense related to all types of performance share awards, before the effect of taxes, was $9.4 million for 2007 and $12.9 million for 2006. A $0.6 million ($0.4 million, net of tax) cumulative effect charge incurred during the first quarter of 2006 is included in 2006 performance share expense within General and Administrative Expenses due to its immateriality, as a result of changes made in our accounting for performance shares. For further information on the accounting for these and our other stock-based compensation awards, please refer to Notes 1 and 10 of the Notes to the Consolidated Financial Statements. During the third quarter of 2006, we adopted the provisions outlined under Financial Accounting Standard Board (FASB) Staff Position (FSP) FAS No. 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which discusses accounting for taxes for stock awards using the APIC Pool concept. We made a one time election as prescribed under the FSP to use the shortcut approach to derive the initial windfall tax benefit pool. We chose to use a one-pool approach which combines all awards granted to employees, including non-employee directors. Our Compensation Committee of our Board of Directors made one modification to our stock option awards in 2005. It approved the acceleration to December 15, 2005 of the vesting of 198,799 unvested stock options awarded in February 2003 under our Second Amended and Restated 1994 Long-Term Incentive Plan and 24,500 unvested stock options awarded in April 2004 under our 2004 Incentive Plan. The 198,799 shares awarded to employees under the 1994 plan at an exercise price of $15.32 would have vested in February 2006. The 24,500 shares awarded to non-employee directors under the 2004 plan at an exercise price of $23.32 would have vested 12,250 shares in each of April 2006 and April 2007. The decision to accelerate the vesting of these unvested options, which we believed to be in the best interest of our shareholders and employees, was made solely to reduce compensation expense and administrative burden associated with our adoption of SFAS No. 123(R). The accelerated vesting of the options did not have an impact on our results of operations or cash flows for 2005. The acceleration of vesting reduced our compensation expense related to these options by approximately $0.2 million for 2006. Uncertain Tax Positions Effective January 1, 2007, we adopted the provisions of FASB Interpretation Number (FIN) 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109.” This adoption did not have a material impact on our financial statements. This Interpretation provides guidance for recognizing and measuring uncertain tax positions as defined in SFAS No. 109, “Accounting for Income Taxes.” Under FIN 48, we now conduct a two-step process for accounting for income tax uncertainties. First, we perform an analysis to determine if a threshold condition of “more likely than not” is met to determine whether any of the benefit of the uncertain tax position should be recognized in the financial statements. Next, if the recognition threshold is met, we measure the amount of the uncertain tax position to be recognized based on additional guidance prescribed in FIN 48. Under FIN 48, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. Guidance is also provided regarding derecognition, classification, interest and penalties, interim period accounting, transition and increased disclosure of these uncertain tax position. For further information regarding the adoption of FIN No. 48, please refer to Note 6 of the Notes to the Consolidated Financial Statements. OTHER ISSUES AND CONTINGENCIES Corporate Income Tax. We have benefited in the past and may benefit in the future from the alternative minimum
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Table of ContentsIndex to Financial Statementstax (AMT) relief granted under the Comprehensive National Energy Policy Act of 1992 (the Act). The Act repealed provisions of the AMT requiring a taxpayer’s alternative minimum taxable income to be increased on account of certain intangible drilling costs (IDC) and percentage depletion deductions for corporations other than integrated oil companies. The repeal of these provisions generally applies to taxable years beginning after 1992. The repeal of the excess IDC preference cannot reduce a taxpayer’s alternative minimum taxable income by more than 40% of the amount of such income determined without regard to the repeal of such preference. Regulations. Our operations are subject to various types of regulation by federal, state and local authorities. See “Regulation of Oil and Natural Gas Exploration and Production,” “Natural Gas Marketing, Gathering and Transportation,” “Federal Regulation of Petroleum” and “Environmental Regulations” in the “Other Business Matters” section of Item 1 for a discussion of these regulations. Restrictive Covenants. Our ability to incur debt and to make certain types of investments is subject to certain restrictive covenants in our various debt instruments. Among other requirements, our revolving credit agreement and our senior notes specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. At December 31, 2007, we are in compliance in all material respects with all restrictive covenants on both the revolving credit agreement and notes. In the unforeseen event that we fail to comply with these covenants, we may apply for a temporary waiver with the lender, which, if granted, would allow us a period of time to remedy the situation. See further discussion in “Capital Resources and Liquidity.” Operating Risks and Insurance Coverage. Our business involves a variety of operating risks. See “Risk Factors—We face a variety of hazards and risks that could cause substantial financial losses” in Item 1A. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The costs of these insurance policies are somewhat dependent on our historical claims experience and also the areas in which we choose to operate. During the past few years, we have invested a significant portion of our drilling dollars in the Gulf Coast, where insurance rates are significantly higher than in other regions such as the East. Commodity Pricing and Risk Management Activities. Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Declines in oil and gas prices may have a material adverse effect on our financial condition, liquidity, ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that we can produce economically. Historically, oil and gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenue and could potentially impact the outcome of our annual impairment test under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Because our reserves are predominantly natural gas, changes in natural gas prices may have a particularly large impact on our financial results. The majority of our production is sold at market responsive prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. However, management may mitigate this price risk with the use of derivative financial instruments. Most recently, we have used financial instruments such as price collars and swap arrangements to reduce the impact of declining prices on our revenue. Under both arrangements, there is also risk that the movement of the index prices will result in our not being able to realize the full benefit of a market improvement. Recently Issued Accounting Pronouncements In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interest in Consolidated Financial Statements, an amendment of Accounting Research Bulletin (ARB) No. 51.” SFAS No. 160 clarifies that a noncontrolling interest (previously commonly referred to as a minority interest) in a subsidiary is an ownership
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Table of ContentsIndex to Financial Statementsinterest in the consolidated entity and should be reported as equity in the consolidated financial statements. The presentation of the consolidated income statement has been changed by SFAS No. 160, and consolidated net income attributable to both the parent and the noncontrolling interest is now required to be reported separately. Previously, net income attributable to the noncontrolling interest was typically reported as an expense or other deduction in arriving at consolidated net income and was often combined with other financial statement amounts. In addition, the ownership interests in subsidiaries held by parties other than the parent must be clearly identified, labeled, and presented in the equity in the consolidated financial statements separately from the parent’s equity. Subsequent changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary should be accounted for consistently, and when a subsidiary is deconsolidated, any retained noncontrolling equity interest in the former subsidiary must be initially measured at fair value. Expanded disclosures, including a reconciliation of equity balances of the parent and noncontrolling interest are also required. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. Prospective application is required. At this time, we do not have any material noncontrolling interests in consolidated subsidiaries. Therefore, we do not believe that the adoption of SFAS No. 160 will have a material impact on our financial position, results of operations or cash flows. In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and increased transparency through expanded disclosures. It changes how business acquisitions are accounted for and will impact financial statements at the acquisition date and in subsequent periods. Certain of these changes will introduce more volatility into earnings. The acquirer must now record all assets and liabilities of the acquired business at fair value, and related transaction and restructuring costs will be expensed rather than the previous method of being capitalized as part of the acquisition. SFAS No. 141(R) also impacts the annual goodwill impairment test associated with acquisitions, including those that close before the effective date of SFAS No. 141(R). The definitions of a “business” and a “business combination” have been expanded, resulting in more transactions qualifying as business combinations. SFAS No. 141(R) is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. We cannot predict the impact that the adoption of SFAS No. 141(R) will have on our financial position, results of operations or cash flows with respect to any acquisitions completed after December 31, 2007. In May 2007, the FASB issued FSP No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48,” which amends FIN 48 and provides guidance concerning how an entity should determine whether a tax position is “effectively,” rather than the previously required “ultimately,” settled for the purpose of recognizing previously unrecognized tax benefits. In addition, FSP No. FIN 48-1 provides guidance on determining whether a tax position has been effectively settled. The guidance in FSP No. FIN 48-1 is effective upon the initial January 1, 2007 adoption of FIN 48. Companies that have not applied this guidance must retroactively apply the provisions of this FSP to the date of the initial adoption of FIN 48. We have adopted FSP No. FIN 48-1 and no retroactive adjustments were necessary. In April 2007, the FASB issued FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39,” to amend FIN 39, “Offsetting of Amounts Related to Certain Contracts.” The terms “conditional contracts” and “exchange contracts” used in FIN 39 have been replaced with the more general term “derivative contracts.” In addition, FSP No. FIN 39-1 permits the offsetting of recognized fair values for the right to reclaim cash collateral or the obligation to return cash collateral against fair values of derivatives under certain circumstances, such as under master netting arrangements. Additional disclosure is also required regarding a company’s accounting policy with respect to offsetting fair value amounts. The guidance in FSP No. FIN 39-1 is effective for fiscal years beginning after November 15, 2007, with early application allowed. The effects of initial adoption should be recognized as a change in accounting principle through retrospective application for all periods presented. We do not believe that the adoption of FSP No. FIN 39-1 will have a material impact on our financial position, results of operations or cash flows. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115,” which permits companies to choose, at
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Table of ContentsIndex to Financial Statementsspecified dates, to measure certain eligible financial instruments at fair value. The objective of this Statement is to reduce volatility in preparer reporting that may be caused as a result of measuring related financial assets and liabilities differently and to expand the use of fair value measurements. The provisions of the Statement apply only to entities that elect to use the fair value option and to all entities with available-for-sale and trading securities. Additional disclosures are also required for instruments for which the fair value option is elected. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. No retrospective application is allowed, except for companies that choose to adopt early. At the effective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of the first remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. Since we have not elected to adopt the fair value option for eligible items, we do not believe that SFAS No. 159 will have an impact on our financial position or results of operations. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by United States generally accepted accounting principles (GAAP) to be measured at fair value. SFAS No. 157 clarifies guidance in FASB Concepts Statement (CON) No. 7 which discusses present value techniques in measuring fair value. Additional disclosures are also required for transactions measured at fair value. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. In November 2007, the FASB granted a one year deferral (to fiscal years beginning after November 15, 2008) for non-financial assets and liabilities to comply with SFAS No. 157. We do not believe that SFAS No. 157 will have a material impact on our financial position or results of operations. Forward-Looking Information The statements regarding future financial and operating performance and results, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. RESULTS OF OPERATIONS 2007 and 2006 Compared We reported net income for the year ended December 31, 2007 of $167.4 million, or $1.73 per share. During 2006, we reported net income of $321.2 million, or $3.32 per share. This decrease of $153.8 million in net income was primarily due to a decrease in operating income of $254.2 million resulting from the gain on sale of assets of $231.2 million included in 2006 related to the 2006 south Louisiana and offshore properties sale, partially offset by a $99.2 million decrease in income tax expense and a $1.2 million decrease in interest and other expenses in 2007. The decrease in operating income was primarily the result of a decrease in 2007 of $218.6 million in gain on sale of assets primarily from the 2006 south Louisiana and offshore properties sale. Additionally, there was a $29.8 million decrease in 2007 in operating revenues and an increase of $5.8 million in operating expenses. The decrease in operating revenues was largely the result of lower oil production in the Gulf Coast region primarily as a result of the 2006 south Louisiana and offshore properties sale. The increase in operating expenses was primarily the result of increased DD&A and impairment expenses, offset in part by reduced exploration and general and administrative expenses.
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Table of ContentsIndex to Financial StatementsNatural Gas Production Revenues Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $7.23 per Mcf for 2007 compared to $7.13 per Mcf for 2006. These prices include the realized impact of derivative instrument settlements, which increased the price by $0.99 per Mcf in 2007 and $0.35 per Mcf in 2006. There was no revenue impact from the unrealized change in natural gas derivative fair value for the years ended December 31, 2007 or 2006.
The increase of $13.5 million in Natural Gas Production Revenue is due to an increase in realized natural gas sales prices as well as increased natural gas production. Natural gas revenues increased in all regions except for the Gulf Coast region in 2007 over 2006. After removing from the 2006 results $70.5 million of natural gas revenues and 9,037 Mmcf of natural gas production associated with properties in the Gulf Coast region sold in the 2006 south Louisiana and offshore properties sale, total natural gas revenue would have increased by $84.0 million, or 17%, and natural gas production would have increased by 9,791 Mmcf, or 14%, from 2006 to 2007.
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Table of ContentsIndex to Financial StatementsBrokered Natural Gas Revenue and Cost
The increased brokered natural gas margin of approximately $1.1 million is driven by an increase in sales price that outpaced the increase in purchase price, partially offset by a decrease in the volumes brokered in 2007 over 2006.
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Table of ContentsIndex to Financial StatementsCrude Oil and Condensate Revenues Our average total company realized crude oil sales price was $67.16 per Bbl for 2007. The 2007 price includes the realized impact of derivative instrument settlements which decreased the price by $0.97 per Bbl. Our average total company realized crude oil sales price was $65.03 per Bbl for 2006. There was no realized impact of crude oil derivative instruments in 2006. There was no unrealized impact of crude oil derivative instruments in 2007 or 2006.
The decrease in the realized crude oil production, partially offset by the increase in realized prices, resulted in a net revenue decrease of approximately $36.2 million. The decrease in oil production is mainly the result of the 2006 south Louisiana and offshore properties sale in the Gulf Coast region. After removing from the 2006 results $47.4 million of crude oil revenues and 707 Mbbls of crude oil production associated with properties in the Gulf Coast region sold in the 2006 south Louisiana and offshore properties sale, total crude oil revenue would have increased by $11.2 million, or 26%, and crude oil production would have increased by 124 Mbbls, or 18%, from 2006 to 2007.
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Table of ContentsIndex to Financial StatementsImpact of Derivative Instruments on Operating Revenues The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:
We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Operating Expenses Total costs and expenses from operations increased by $5.8 million for the year ended December 31, 2007 compared to the year ended December 31, 2006. The primary reasons for this fluctuation are as follows:
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Table of ContentsIndex to Financial Statements
Interest Expense, Net Interest expense, net decreased by $1.1 million in 2007 compared to 2006 due to a lower weighted-average interest rate on borrowings under our revolving credit facility, a lower outstanding principal amount of our 7.19% fixed rate debt and lower weighted-average borrowings under our credit facility, as well as increased income related to FIN 48 as discussed below. These decreases to interest expense were offset in part by decreased regulatory capitalized interest on our pipeline in the East region. Weighted-average borrowings under our credit facility based on daily balances were approximately $52 million during 2007 compared to approximately $61 million during 2006. The weighted-average effective interest rate on the credit facility decreased to 7.2% during 2007 from 7.9% during 2006. In addition, interest expense decreased due to the reversal of interest payable on a previous uncertain tax position. During 2007, we recorded net interest income related to FIN 48 of $1.3 million, with no amount recorded in 2006. Income Tax Expense Income tax expense decreased by $99.2 million due to a comparable decrease in our pre-tax income, primarily as a result of the decrease in the gain on sale of assets. The effective tax rates for 2007 and 2006 were 35.0% and 37.1%, respectively. The decrease in the effective tax rate is primarily due to a reduction in our overall state income tax rate for 2007. 2006 and 2005 Compared We reported net income for the year ended December 31, 2006 of $321.2 million, or $3.32 per share. During 2005, we reported net income of $148.4 million, or $1.52 per share. Net income increased in 2006 by $172.8 million primarily due to an increase in operating income as a result of the gain of $231.2 million ($144.5 million, net of tax) recorded in 2006 related to the 2006 south Louisiana and offshore properties sale as well as an increase in natural gas and oil production revenues. This increase is partially offset by an increase in total operating expenses of $41.0 million and an increase of $101.5 million in income tax expense. Operating income increased by $270.2 million compared to the prior year, from $258.7 million in 2005 to $528.9 million in 2006.
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Table of ContentsIndex to Financial StatementsNatural Gas Production Revenues Our average total company realized natural gas production sales price for 2006, including the realized impact of derivative instruments, was $7.13 per Mcf compared to $6.74 per Mcf for the prior year. These prices include the realized impact of derivative instruments, which increased these prices by $0.35 per Mcf in 2006 and reduced these prices by $1.33 per Mcf in 2005. The following table excludes the unrealized gain from the change in derivative fair value of $1.1 million for the year ended December 31, 2005. There was no unrealized impact from the change in derivative fair value for the year ended December 31, 2006. These unrealized changes in fair value have been included in Natural Gas Production Revenues in the Consolidated Statement of Operations.
The increase in Natural Gas Production Revenue is due to the increase in natural gas sales production and, to a lesser extent, the increase in realized natural gas prices. Production increased in all regions and prices were up in the Gulf Coast and West. The increase in the total realized natural gas price and production resulted in a net revenue increase of $70.0 million, excluding the unrealized impact of derivative instruments. This growth primarily resulted from our 2005 and 2006 drilling programs, which focused on projects in basins traditionally known for gas development, including the East region, the Minden field in the Gulf Coast and Canada. This natural gas production increase includes the effects of the 2006 south Louisiana and offshore properties sale. For the year ended December 31, 2006, natural gas volumes from the properties sold in the third quarter 2006 disposition were 9,037 Mmcf and natural gas revenues from those properties were approximately $70.5 million.
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Table of ContentsIndex to Financial StatementsBrokered Natural Gas Revenue and Cost
The decreased brokered natural gas margin of $1.1 million was driven by a decrease in sales price that outpaced the decrease in purchase cost, offset in part by an increase in volume.
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Table of ContentsIndex to Financial StatementsCrude Oil and Condensate Revenues Our average total company realized crude oil sales price for 2006 was $65.03 per Bbl. There was no realized impact of crude oil derivative instruments in 2006. Our average total company realized crude oil sales price was $44.19 per Bbl for 2005, including the realized impact of derivative instruments, which reduced the price by $9.93 per Bbl. The following table excludes the unrealized gain from the change in derivative fair value of $5.5 million for the year ended December 31, 2005. There was no unrealized impact from the change in derivative fair value for the year ended December 31, 2006. These unrealized changes in fair value have been included in Crude Oil and Condensate Revenues in the Consolidated Statement of Operations.
The increase in the realized crude oil price offset by the decline in production resulted in a net revenue increase of $14.5 million, excluding the unrealized impact of derivative instruments. The decrease in oil production is primarily the result of decreased Gulf Coast production from the 2006 south Louisiana and offshore properties sale in the third quarter of 2006 and the continued natural decline of the CL&F lease in south Louisiana, which was part of the sale. For the year ended December 31, 2006, crude oil and condensate volumes from the properties sold in the third quarter disposition were 707 Mbbls and crude oil and condensate revenues from those properties were approximately $47.4 million.
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Table of ContentsIndex to Financial StatementsImpact of Derivative Instruments on Operating Revenues The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:
We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Operating Expenses Total costs and expenses from operations increased by $41.0 million for the year ended December 31, 2006 compared to the year ended December 31, 2005. The primary reasons for this fluctuation were as follows:
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Table of ContentsIndex to Financial Statements
Interest Expense, Net Interest expense, net decreased by $3.4 million due to lower borrowings on our 7.19% fixed rate debt and increased interest on our short term investments as well as the commencement of regulatory interest capitalization on our pipeline in the East region, offset partially by higher average credit facility borrowings as well as an increasing interest rate environment. Weighted-average borrowings based on daily balances were approximately $61 million during 2006 compared to $32 million during 2005. In addition, the weighted-average effective interest rate on the credit facility increased to 7.9% during 2006 from 6.9% during the prior year. Income Tax Expense Income tax expense increased by $101.5 million due to a comparable increase in our pre-tax income, primarily as a result of the gain on the sale of assets recorded in the third quarter of 2006. The effective tax rates for 2006 and 2005 were 37.1% and 37.2%, respectively.
Derivative Instruments and Hedging Activity Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to us of increases in prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please read the discussion below as well as Note 11 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our hedging arrangements. Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. Under our revolving credit agreement, the aggregate level of commodity hedging must not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. At December 31, 2007, we had 16 cash flow hedges open: 12 natural gas price collar arrangements, three natural gas swap arrangements and one crude oil price collar arrangement. At December 31, 2007, a $7.3 million ($4.6 million, net of tax) unrealized gain was recorded in Accumulated Other Comprehensive Income, along with a $12.7 million short-term derivative receivable and a $5.4 million short-term derivative liability. The change in the fair value of derivatives designated as hedges that is effective is initially recorded to Accumulated Other Comprehensive Income. The ineffective
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Table of ContentsIndex to Financial Statementsportion, if any, of the change in the fair value of derivatives designated as hedges, and the change in fair value of all other derivatives, is recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue, as appropriate. During 2007 and 2006, there was no ineffectiveness recorded in the Consolidated Statement of Operations. For 2005, a $6.6 million gain was recorded as a component of revenue, which reflected the ineffective portion of the change in fair value of derivatives designated as hedges and the change in the fair value of all other derivatives. Assuming no change in commodity prices, after December 31, 2007 we would expect to reclassify to the Consolidated Statement of Operations, over the next 12 months, $4.6 million in after-tax income associated with commodity hedges. This reclassification represents the net short-term receivable associated with open positions currently not reflected in earnings at December 31, 2007 related to anticipated 2008 production. Hedges on Production – Swaps From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These cash flow hedges are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. During 2007, we did not enter into any natural gas price swaps covering our 2007 production. At December 31, 2007, we had open natural gas price swap contracts covering a portion of our 2008 production as follows:
Hedges on Production – Options From time to time, we enter into natural gas and crude oil collar agreements with counterparties to hedge price risk associated with a portion of our production. These cash flow hedges are not held for trading purposes. Under the collar arrangements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. During 2007, natural gas price collars covered 42,533 Mmcf of our gas production, or 53%, of our gas production, with a weighted-average floor of $8.99 per Mcf and a weighted-average ceiling of $12.19 per Mcf.
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Table of ContentsIndex to Financial StatementsAt December 31, 2007, we had open natural gas price collar contracts covering a portion of our 2008 production as follows:
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Table of ContentsIndex to Financial StatementsDuring 2007, an oil price collar covered 365 Mbbls of our crude oil production, or 44%, of our crude oil production, with a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl. At December 31, 2007, we had one open crude oil price collar contract covering a portion of our 2008 production as follows:
We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See “Forward-Looking Information” for further details. Fair Market Value of Financial Instruments The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value. We use available marketing data and valuation methodologies to estimate the fair value of debt. This disclosure is presented in accordance with SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” and does not impact our financial position, results of operations or cash flows. Long-Term Debt
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