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, 20042007
Commission file number 1-10447
CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 04-3072771 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) |
1200 Enclave Parkway, Houston, Texas 77077
(Address of principal executive offices including ZIP code)
(281) 589-4600
(Registrant’s telephone number)number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |
| Common Stock, par value $.10 per share | New York Stock Exchange | |
| Rights to Purchase Preferred Stock | New York Stock Exchange |
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. 10-K x¨.
(continued)
Indicate 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):
| Large accelerated filer x | Accelerated filer ¨ | |
| Non-accelerated filer ¨ | Smaller reporting company ¨ |
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is an accelerated filera shell company (as defined in Rule 12b-2 of the Exchange Act). Yes x¨ 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 30, 2004), the last business day of registrant’s most recently completed second fiscal quarter29, 2007) was approximately $1.4$3.6 billion.
As of January 31, 2005,February 25, 2008, there were 32,414,76097,768,036 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held April 28, 200530, 2008 are incorporated by reference into Part III of this report.
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ITEM 1 | ||||||
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ITEM 2 | Properties | 31 | ||||
| ITEM 3 | Legal Proceedings | 31 | ||||
| ITEM 4 | ||||||
| PART II | ||||||
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ITEM 6 | ||||||
ITEM 7 | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||
ITEM 7A | ||||||
ITEM 8 | ||||||
ITEM 9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | |||||
ITEM 9A | ||||||
ITEM 9B | ||||||
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ITEM 10 | Directors, | |||||
ITEM 11 | ||||||
ITEM 12 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | |||||
ITEM 13 | Certain Relationships and Related Transactions, and Director Independence | |||||
ITEM 14 | ||||||
ITEM 15 | Exhibits and Financial Statement Schedules | |||||
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The 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:
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| Abbreviated Term | Definition | |
| Mcf | Thousand cubic feet | |
| Mmcf | Million cubic feet | |
| Bcf | Billion cubic feet | |
| Bbl | Barrel | |
| Mbbls | Thousand barrels | |
| Mcfe | Thousand cubic feet of natural gas equivalents | |
| Mmcfe | Million cubic feet of natural gas equivalents | |
| Bcfe | Billion cubic feet of natural gas equivalents | |
| Mmbtu | Million British thermal units | |
| NGL | Natural gas liquids |
| ITEM 1. | BUSINESS |
OVERVIEW
Cabot Oil & Gas Corporation is an independent oil and gas company engaged in the exploration, development, acquisitionexploitation and exploitationexploration of oil and gas properties located in North America. TheOur 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 onshore and offshore the Texas and Louisiana Gulf Coast, and the deep gas basin of WestWestern 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 East region,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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Operating 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, which is comprised of the Rocky MountainsEast region and Mid-Continent areas,Canada, partially offset by decreased natural gas production in the Gulf Coast region as a result of the 2006 south Louisiana and Canada.
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 2004,2007, energy commodity prices remained strong throughout the year. This strongOur 2007 average realized natural gas price environmentwas $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 largest organic capital2008 program ever while still maintaining our financial flexibility. This flexibility should provide us the ability to take advantage of attractive acquisition opportunities that may arise. At December 31, 2004, our debt to total capital ratio was 37%, down from 43% at the end of 2003. Natural gas production increased to 72.8 Bcf in 2004 from 71.9 Bcf in 2003. This growth was directly related to our 2003 drilling program which focused on natural gas projects. and evaluate other opportunities.
On an equivalent basis, our production level in 2004 was down slightly2007 decreased by three percent from 2003.2006. We produced 84.885.5 Bcfe, or 232.3 Mmcfe per day, this year, as compared to 89.0 Bcfe, or 243.8234.1 Mmcfe per day, in 2003. The growth2007, 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 was offsetsold 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 loss2006 south Louisiana and offshore properties sale. Excluding 9.0 Bcf of production associated withsold in that sale, Gulf Coast production would have increased 28% in 2007 over 2006, primarily due to increased drilling in the late 2003 saleMinden, 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 non-strategic properties and natural decline incrude 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 south Louisiana. Our 2004 realized natural gas price was $5.20 per Mcf, compareddrilling and workover activity in the McCampbell field and, to a 2003 pricelesser 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 $4.51. Our realized crude oil price was $31.55 per Bbl, compared to a 2003 price of $29.55. Our average hedged prices on natural gasequivalent production sold in the 2006 south Louisiana and crude oil for 2005 anticipatedoffshore properties sale, total equivalent production are expected to be higher than comparable prices realized from hedging in 2004. To lock in prices above historical levels for awould have increased by 10.6 Bcfe, or 14%.
A portion of our production as a result of the strong commodity prices, we layered inwas covered by oil and gas hedge instruments throughout 20042006 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 in 2004 and 2005.had a weighted-average floor of $8.99 per Mcf and a weighted-average ceiling of $12.19 per Mcf. At December 31, 2004, 44%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 25%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 andproduction with a weighted-average price of $7.44 per Mcf. For 2007, collars covered 44% of crude oil anticipated production respectively, are hedged for 2005 through the usewith a floor of derivatives that qualify for hedge accounting. Including our range swaps, which do not qualify for hedge accounting, 75%$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 2005. No2008 with a floor of
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$60.00 per Bbl and a ceiling of $80.00 per Bbl. As of December 31, 2007, no derivatives are in place for 2006.2009. Our decision to hedge 20052008 production fits with our risk management strategy and allows the Companyus to lock in the benefit of high commodity prices on a portion of our anticipated production.
Net income of $88.4 million or $2.72 per share exceeded last year by $67.2 million or $2.06 per share. The year over year net income increase was achieved due to higher natural gas revenues from higher commodity prices. Operating Revenues increased by $21.0 million or 4% due to strong commodity prices. Natural gas production revenues increased by $57.1 million over the prior year; this increase was partially offset by a decrease in crude oil and condensate revenues of $21.0 million and a decrease in brokered natural gas revenues of $11.4 million. In addition, operating expenses decreased between 2004 and 2003 as a result of the 2003 non-cash pre-tax impairment charge of $93.8 million. Also contributing to the decrease were lower brokered natural gas cost and lower exploration expense. Net income in 2003 was also reduced by a $6.8 million cumulative effect of accounting change related to SFAS 143.
For the year ended December 31, 2004,2007, we drilled 256461 gross wells (391 net) with a success rate of 95%96% compared to 173387 gross wells (307 net) with a success rate of 89%96% for the comparable period of 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 20042007 capital and exploration spending was $259.5$636.2 million compared to $188.2$537.5 million of total capital and exploration spending in 2003.2006. 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 concentrated our 2004 capital spending program on projects balancing acceptable risk with the strongest economics. In the past, we have used a portionplan to continue such method of allocation in 2008. Funding of the program is expected to be provided by operating cash flow, fromexisting cash and increased borrowings, if required. We remain focused on our long-lived Eaststrategies of pursuing lower risk drilling opportunities that provide more predictable results and Mid-Continent natural gas reserves to fundselectively pursuing impact exploration opportunities as we accelerate drilling on our exploration and development efforts inaccumulated 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 Rocky Mountain areas. In 2004, we continued that practice to a lesser extent as we increased our capital expendituresCanada. We believe these strategies are appropriate in the East in responsecurrent industry environment and will continue to add shareholder value over the success of the 2003 drilling program. The main recipient of these dollars was Canada where we commenced our drilling program with a $16.2 million investment.long term. In 2005,2008, we plan to spend approximately $280$490 million which includes a layer of investment for new projects or property acquisitions that may arise during 2005.
on capital and exploration activities.
Our proved reserves totaled approximately 1,2021,616 Bcfe at December 31, 2004,2007, of which 94%97% was natural gas. This reserve level was up slightlyby 14 percent from 1,1421,416 Bcfe at December 31, 20032006 on the strength of results from our drilling program and the lack of reserve sales during the year.increase in our capital spending.
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The following table presents certain reserve, production and well information as of December 31, 2004.2007.
| West | |||||||||||||||||||||
| East | Rocky Mountains | Mid- Continent | Total | Gulf Coast | Canada | Total | |||||||||||||||
Proved Reserves at Year End (Bcfe) | |||||||||||||||||||||
Developed | 398.9 | 187.4 | 167.6 | 355.0 | 149.4 | 6.4 | 909.7 | ||||||||||||||
Undeveloped | 151.6 | 50.2 | 21.7 | 71.9 | 67.7 | 1.5 | 292.7 | ||||||||||||||
Total | 550.5 | 237.6 | 189.3 | 426.9 | 217.1 | 7.9 | 1,202.4 | ||||||||||||||
Average Daily Production (Mmcfe per day) | 53.6 | 35.9 | 26.5 | 62.4 | 115.3 | 1.0 | 232.3 | ||||||||||||||
Reserve Life Index (in years)(1) | 28.1 | 18.1 | 19.5 | 18.7 | 5.1 | N/A | 14.1 | ||||||||||||||
Gross Wells | 2,584 | 533 | 650 | 1,183 | 751 | 14 | 4,532 | ||||||||||||||
Net Wells(2) | 2,393.3 | 242.6 | 452.9 | 695.5 | 495.4 | 1.5 | 3,585.7 | ||||||||||||||
Percent Wells Operated (Gross) | 96.6 | % | 52.9 | % | 78.2 | % | 66.8 | % | 74.3 | % | 21.4 | % | 84.9 | % | |||||||
| West | |||||||||||||||||||||
| East | Gulf Coast | Rocky Mountains | Mid- Continent | Total | Canada | Total | |||||||||||||||
Proved Reserves at Year End(Bcfe) | |||||||||||||||||||||
Developed | 551.2 | 207.9 | 206.6 | 177.8 | 384.4 | 32.6 | 1,176.1 | ||||||||||||||
Undeveloped | 227.2 | 116.3 | 65.0 | 28.1 | 93.1 | 3.2 | 439.8 | ||||||||||||||
Total | 778.4 | 324.2 | 271.6 | 205.9 | 477.5 | 35.8 | 1,615.9 | ||||||||||||||
Average Daily Production(Mmcfe per day) | 67.1 | 83.4 | 41.4 | 31.2 | 72.6 | 11.0 | 234.1 | ||||||||||||||
Reserve Life Index(In years)(1) | 31.8 | 10.7 | 18.0 | 18.1 | 18.0 | 8.9 | 18.9 | ||||||||||||||
Gross Wells | 3,178 | 685 | 677 | 778 | 1,455 | 38 | 5,356 | ||||||||||||||
Net Wells (2) | 2,962.2 | 464.1 | 302.0 | 541.8 | 843.8 | 13.4 | 4,283.5 | ||||||||||||||
Percent Wells Operated(Gross) | 97.1 | % | 73.3 | % | 50.2 | % | 77.8 | % | 64.9 | % | 55.3 | % | 85.0 | % | |||||||
(1) | Reserve Life Index is equal to year-end reserves divided by annual production. |
(2) | The term “net” as used in “net acreage” or “net production” throughout this document refers to amounts that include only acreage or production that is owned by |
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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held 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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EAST REGION
Our East region activities are concentrated primarily in West Virginia, and to a lesser extentVirginia. This region is managed from our office in New York.Charleston, West Virginia. In this region, our assets include a large undeveloped acreage position, a high concentration of wells, natural gas gathering and pipeline systems, and storage capacity.
Capital and exploration expenditures for 2007 were $75.2$178.6 million, for 2004, or 29%28% of our total 20042007 capital spending, and $40.6exploration expenditures, compared to $145.4 million for 2003.2006, 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 2005,2008, we have budgeted $75.3approximately $189 million for capital and exploration expenditures in the region.
At December 31, 2004,2007, we had 2,5843,178 wells (2,393.3(2,962.2 net), of which 2,4973,085 wells are operated by us. There are multiple producing intervals that include the Big Lime, Weir, Berea and Devonian Shale and Oriskany 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 20042007 was 53.667.1 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, 2004,2007, we had 550.5778.4 Bcfe of proved reserves (substantially all natural gas) in the East region, constituting 46%48% of our total proved reserves. ThisDeveloped and undeveloped reserves made up 551.2 Bcfe and 227.2 Bcfe of the total proved reserves for the East region, is managed fromrespectively. While no properties are individually significant to our officecompany as a whole, the Sissonville, Pineville, Logan-Holden-Dingess, Big Creek, Hernshaw-Bullcreek and Huff Creek fields in Charleston, West Virginia.
Virginia are included in our ten largest fields and together contain approximately 29% of our total company proved equivalent reserves.
In 2004,2007, we drilled 171254 wells (167.5(244.6 net) in the East region, of which 166250 wells (163(240.8 net) were development and extension wells. In 2005,2008, we plan to drill approximately 200 wells.
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 2004,2007, we produced and marketed approximately 8071 barrels of crude oil/condensate per day in the East region at market responsive prices.
Ancillary to our exploration, development and production operations, we operateoperated 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 2004.2007. 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.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.
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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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The 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. Cabot Oil & Gas Marketing, our subsidiary, purchases gas from local third-party producers and other suppliers to aggregate larger volumes of gas for resale.
Approximately 65%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 2%two percent of East production is sold on fixed price contracts that typically renew annually.
WEST REGION
Our activities in the West region are managed by a regional office in Denver. At December 31, 2004, we had 426.9 Bcfe of proved reserves (96% natural gas) in the West region, constituting 36% of our total proved reserves.
Rocky Mountains
Our Rocky Mountains activities are concentrated in the Green River, Wind River and Big Horn Basins in Wyoming and Paradox Basin in Colorado. At December 31, 2004, we had 237.6 Bcfe of proved reserves (95% natural gas) in the Rocky Mountain area, 20% of our total proved reserves. Capital and exploration expenditures in the Rocky Mountains were $41.5 million for 2004, or 16% of our total capital and exploration expenditures, and $22.3 million for 2003. Spending for 2004 included $30.5 million for drilling activity and $7.5 million of dry hole expense and geophysical and geological procedures. For 2005, we have budgeted $33.6 million for capital and exploration expenditures in the area.
We had 533 wells (242.6 net) in the Rocky Mountains area as of December 31, 2004, of which 282 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 5,500 to 15,000 feet. Average net daily production in the Rocky Mountains during 2004 was 35.9 Mmcfe.
In 2004, we drilled 29 wells (14.3 net) in the Rocky Mountains, of which 26 wells (13.0 net) were development wells. In 2005, we plan to drill 30 wells.
Mid-Continent
Our Mid-Continent activities are concentrated in the Anadarko Basin in southwest Kansas, Oklahoma and the panhandle of Texas. Capital and exploration expenditures were $12.1 million for 2004, or 5% of our total 2004 capital and exploration expenditures, and $11.2 million for 2003. For 2005, we have budgeted $8.5 million for capital and exploration expenditures in the area.
As of December 31, 2004, we had 650 wells (452.9 net) in the Mid-Continent area, of which 508 wells are operated by us. Principal producing intervals in the Mid-Continent are in the Chase, Morrow, Red Fork and Chester formations at depths ranging from 2,200 to 10,000 feet. Average net daily production in 2004 was 26.5 Mmcfe. At December 31, 2004, we had 189.3 Bcfe of proved reserves (97% natural gas) in the Mid-Continent area, 16% of our total proved reserves.
In 2004, we drilled 21 wells (18.9 net) in the Mid-Continent, all of which were development and extension wells. In 2005, we plan to drill 11 wells.
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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 75% 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 23% of the natural gas production is sold under short-term arrangements at index-based prices and the remaining 2% 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 2004, we produced and marketed approximately 450 barrels of crude oil/condensate per day in the West region at market responsive prices.
GULF COAST REGION
Our development, exploitation, exploration development and production activities in the Gulf Coast region are primarily concentrated in northeast and south Louisiana, south Texas and the Gulf of Mexico.north Louisiana. A regional office in Houston manages the operations. Principal producing intervals are in the Cotton Valley Hosston, Miocene and Frio ageJames Lime formations in north Louisiana and east Texas and the Frio, Vicksburg and Wilcox formations in south Texas at depths ranging from 3,0002,200 to 25,00017,700 feet, with an average depth of approximately 10,800 feet.
Capital and exploration expenditures were $112.6$291.5 million for 2004,2007, or 43%46% of our total 2007 capital and exploration expenditures, and $111.6compared to $234.8 million for 2003.2006, or 44% of our total 2006 capital and exploration expenditures. For 2005,2008, we have budgeted $105.0approximately $209 million of our total budget for capital and exploration expenditures in the region. Our 20052008 Gulf Coast drilling program will continue to emphasize impact exploration opportunities both on and offshore, augmented by development activity primarily in our focus areas of south Texas and throughout coastal Louisiana.east Texas.
In 2004, we drilled 31 wells (17.6 net) in the Gulf Coast region, of which 20 wells (12.4 net) were development wells. In 2005 we plan to drill 42 wells. We had 751685 wells (495.4(464.1 net) in the Gulf Coast region as of December 31, 2004,2007, of which 558502 wells are operated by us. Average daily production in 20042007 was 115.3 Mmcfe, compared to 124.1 Mmcfe in 2003. The decline is the result of lower83.4 Mmcfe. Natural gas and crude oil/condensate/NGL production from our properties in south Louisiana, offset partially by increased production from the coastal Texas area. for 2007 was 26.8 Bcf and 606 Mbbls, respectively.
At December 31, 2004,2007, we had 217.1324.2 Bcfe of proved reserves (78%(89% natural gas) in the Gulf Coast region, which represented 18%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 40%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 60%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 2004,2007, we produced and marketed approximately 5,0001,659 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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reserves 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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In 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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CANADA 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 ProvincesProvince of Alberta and British Columbia.Alberta. At December 31, 2004,2007, we had 7.935.8 Bcfe of proved reserves (91%(97% natural gas) in the Canada region, constituting less than 1%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 $16.2$55.1 million for 2004,2007, or 6%nine percent of our total 2007 capital and exploration expenditures, and $0.8compared to $49.0 million for 2003.2006, or nine percent of our total 2006 capital and exploration expenditures. For 2005,2008, we have budgeted $16.0approximately $13 million for capital and exploration expenditures in the area.
We had 1438 wells (1.5(13.4 net) in the Canada region as of December 31, 2004,2007, of which 321 wells are operated by us. Principal producing intervals in the Canada region are in the Falher, Bluesky, Cadomin, Dunvegan and the Swan HillsMountain Park formations at depths ranging from 9,5008,500 to 16,00014,500 feet, with an average depth of approximately 10,950 feet. Average net daily production in Canada during 20042007 was 1.011.0 Mmcfe.
Natural gas and crude oil/condensate/NGL production for 2007 was 3.9 Bcf and 18 Mbbls, respectively.
In 2004,2007, we drilled 410 wells (1.5(5.2 net) in Canada, of which 38 wells (1.1(4.0 net) were development and extension wells. In 2005,2008, we plan to drill 10 wells.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 2004,2007, we produced and marketed approximately 1048 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 20042007 we primarily employed natural gas price collar and swap agreements and crude oil price swapcollar agreements for portions of our 2007 and collar agreements2008 production to attempt to manage price risk more effectively. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of natural gas or crude oil for the period is greater or less than the fixed price established for that period when the swap is put in place. 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“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Commodity Price SwapsOperations” and Options“Quantitative and Qualitative Disclosures about Market Risk” for further discussion concerning our use of derivatives.
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RESERVES
Current Reserves
The following table presents our estimated proved reserves at December 31, 2004.2007.
| Natural Gas (Mmcf) | Liquids(1) (Mbbl) | Total(2) (Mmcfe) | ||||||||||||||||
| Developed | Undeveloped | Total | Developed | Undeveloped | Total | Developed | Undeveloped | Total | ||||||||||
East | 396,521 | 151,184 | 547,705 | 401 | 53 | 454 | 398,927 | 151,500 | 550,427 | |||||||||
Rocky Mountains | 177,454 | 47,911 | 225,365 | 1,657 | 384 | 2,041 | 187,395 | 50,216 | 237,611 | |||||||||
Mid-Continent | 162,625 | 21,491 | 184,116 | 831 | 39 | 870 | 167,609 | 21,728 | 189,337 | |||||||||
Gulf Coast | 115,528 | 54,216 | 169,744 | 5,648 | 2,240 | 7,888 | 149,417 | 67,653 | 217,070 | |||||||||
Canada | 5,706 | 1,445 | 7,151 | 115 | 16 | 131 | 6,399 | 1,539 | 7,938 | |||||||||
Total | 857,834 | 276,247 | 1,134,081 | 8,652 | 2,732 | 11,384 | 909,747 | 292,636 | 1,202,383 | |||||||||
| Natural Gas(Mmcf) | Liquids(1)(Mbbl) | Total(2)(Mmcfe) | ||||||||||||||||
| Developed | Undeveloped | Total | Developed | Undeveloped | Total | Developed | Undeveloped | Total | ||||||||||
East | 548,762 | 227,218 | 775,980 | 404 | — | 404 | 551,187 | 227,218 | 778,405 | |||||||||
Gulf Coast | 185,243 | 104,770 | 290,013 | 3,778 | 1,917 | 5,695 | 207,911 | 116,273 | 324,184 | |||||||||
Rocky Mountains | 196,543 | 63,100 | 259,643 | 1,668 | 317 | 1,985 | 206,548 | 65,000 | 271,548 | |||||||||
Mid-Continent | 171,819 | 27,869 | 199,688 | 1,001 | 41 | 1,042 | 177,825 | 28,118 | 205,943 | |||||||||
Canada | 31,570 | 3,059 | 34,629 | 175 | 27 | 202 | 32,620 | 3,219 | 35,839 | |||||||||
Total | 1,133,937 | 426,016 | 1,559,953 | 7,026 | 2,302 | 9,328 | 1,176,091 | 439,828 | 1,615,919 | |||||||||
(1) | Liquids include crude oil, condensate and natural gas |
(2) | Natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids. |
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 1) we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues, 2)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 3) 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 2004.2007. 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.
There are a number of uncertaintiesFor additional information about the risks inherent in estimating quantitiesour estimates of proved reserves, including many factors beyondsee “Risk Factors—Our proved reserves are estimates. Any material inaccuracies in our control such as commodity pricing. Therefore, the reserve information in this Form 10-K represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates are often different fromor underlying assumptions could cause the quantities and net present value of crude oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Exceptour reserves to the extent we acquire additional properties containing proved reservesbe overstated or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.understated” in Item 1A.
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Historical Reserves
The following table presents our estimated proved reserves for the periods indicated.
| Natural Gas (Mmcf) | Oil & Liquids (Mbbl) | Total (Mmcfe)(1) | |||||||
December 31, 2001 | 1,036,004 | 19,684 | 1,154,109 | ||||||
Revision of Prior Estimates | 14,405 | 1,871 | 25,631 | ||||||
Extensions, Discoveries and Other Additions | 64,945 | 851 | 70,053 | ||||||
Production | (73,670 | ) | (2,909 | ) | (91,126 | ) | |||
Purchases of Reserves in Place | 26,262 | 261 | 27,828 | ||||||
Sales of Reserves in Place | (6,987 | ) | (1,365 | ) | (15,179 | ) | |||
December 31, 2002 | 1,060,959 | 18,393 | 1,171,316 | ||||||
Revision of Prior Estimates | (6,122 | ) | 307 | (4,278 | ) | ||||
Extensions, Discoveries and Other Additions | 105,497 | 1,723 | 115,835 | ||||||
Production | (71,906 | ) | (2,846 | ) | (88,976 | ) | |||
Purchases of Reserves in Place | 1,590 | — | 1,591 | ||||||
Sales of Reserves in Place | (20,534 | ) | (5,474 | ) | (53,380 | ) | |||
December 31, 2003 | 1,069,484 | 12,103 | 1,142,108 | ||||||
Revision of Prior Estimates | (7,850 | ) | 185 | (6,739 | ) | ||||
Extensions, Discoveries and Other Additions | 140,986 | 1,074 | 147,426 | ||||||
Production | (72,833 | ) | (2,002 | ) | (84,847 | ) | |||
Purchases of Reserves in Place | 5,384 | 24 | 5,525 | ||||||
Sales of Reserves in Place | (1,090 | ) | — | (1,090 | ) | ||||
December 31, 2004 | 1,134,081 | 11,384 | 1,202,383 | ||||||
Proved Developed Reserves | |||||||||
December 31, 2001 | 804,646 | 15,328 | 896,612 | ||||||
December 31, 2002 | 819,412 | 13,267 | 899,016 | ||||||
December 31, 2003 | 812,280 | 9,405 | 868,712 | ||||||
December 31, 2004 | 857,834 | 8,652 | 909,747 |
| Natural Gas | Oil & Liquids | Total | |||||||
| (Mmcf) | (Mbbl) | (Mmcfe)(1) | |||||||
December 31, 2004 | 1,134,081 | 11,384 | 1,202,383 | ||||||
Revision of Prior Estimates | (1,543 | ) | 1,073 | 4,892 | |||||
Extensions, Discoveries and Other Additions | 185,884 | 334 | 187,891 | ||||||
Production | (73,879 | ) | (1,747 | ) | (84,361 | ) | |||
Purchases of Reserves in Place | 17,567 | 419 | 20,083 | ||||||
Sales of Reserves in Place | (14 | ) | — | (14 | ) | ||||
December 31, 2005 | 1,262,096 | 11,463 | 1,330,874 | ||||||
Revision of Prior Estimates(2) | (17,675 | ) | 673 | (13,640 | ) | ||||
Extensions, Discoveries and Other Additions | 246,197 | 1,066 | 252,594 | ||||||
Production | (79,722 | ) | (1,415 | ) | (88,212 | ) | |||
Purchases of Reserves in Place | 1,946 | 38 | 2,176 | ||||||
Sales of Reserves in Place | (44,549 | ) | (3,852 | ) | (67,663 | ) | |||
December 31, 2006 | 1,368,293 | 7,973 | 1,416,129 | ||||||
Revision of Prior Estimates | 2,604 | 771 | 7,228 | ||||||
Extensions, Discoveries and Other Additions | 265,830 | 1,381 | 274,114 | ||||||
Production | (80,475 | ) | (830 | ) | (85,451 | ) | |||
Purchases of Reserves in Place | 3,701 | 33 | 3,899 | ||||||
Sales of Reserves in Place | — | — | — | ||||||
December 31, 2007 | 1,559,953 | 9,328 | 1,615,919 | ||||||
Proved Developed Reserves | |||||||||
December 31, 2004 | 857,834 | 8,652 | 909,747 | ||||||
December 31, 2005 | 944,897 | 9,127 | 999,661 | ||||||
December 31, 2006 | 996,850 | 5,895 | 1,032,222 | ||||||
December 31, 2007 | 1,133,937 | 7,026 | 1,176,091 | ||||||
(1) | Includes natural gas and natural gas equivalents determined by using the ratio of 6 Mcfof natural gas to 1 Bbl of crude oil, condensate or natural gas liquids. |
(2) | The majority of the revisions were the result of the decrease in the natural gas price on December 31, 2006 from the price on December 31, 2005. |
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Volumes and Prices;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.
| Year Ended December 31, | |||||||||
| 2004 | 2003 | 2002 | |||||||
Net Wellhead Sales Volume | |||||||||
Natural Gas (Bcf) | |||||||||
Gulf Coast | 31.3 | 30.0 | 30.4 | ||||||
West | 21.9 | 23.8 | 25.3 | ||||||
East | 19.4 | 18.6 | 18.0 | ||||||
Canada | 0.2 | — | — | ||||||
Crude/Condensate/Ngl (Mbbl) | |||||||||
Gulf Coast | 1,809 | 2,625 | 2,655 | ||||||
West | 163 | 193 | 221 | ||||||
East | 27 | 27 | 33 | ||||||
Canada | 3 | — | — | ||||||
Produced Natural Gas Sales Price ($/Mcf)(1) | |||||||||
Gulf Coast | $ | 5.27 | $ | 4.78 | $ | 3.34 | |||
West | 4.75 | 3.67 | 2.39 | ||||||
East | 5.60 | 5.15 | 3.38 | ||||||
Canada | 4.69 | — | — | ||||||
Weighted Average | 5.20 | 4.51 | 3.02 | ||||||
Crude/Condensate Sales Price ($/Bbl)(1) | $ | 31.55 | $ | 29.55 | $ | 23.79 | |||
Production Costs ($/Mcfe)(2) | $ | 0.99 | $ | 0.87 | $ | 0.70 | |||
| Year Ended December 31, | |||||||||
| 2007 | 2006 | 2005 | |||||||
Net Wellhead Sales Volume | |||||||||
Natural Gas(Bcf) | |||||||||
East | 24.4 | 23.5 | 21.4 | ||||||
Gulf Coast | 26.8 | 30.0 | 28.1 | ||||||
West | 25.4 | 23.6 | 23.2 | ||||||
Canada | 3.9 | 2.6 | 1.2 | ||||||
Crude/Condensate/Ngl(Mbbl) | |||||||||
East | 26 | 24 | 27 | ||||||
Gulf Coast | 606 | 1,164 | 1,530 | ||||||
West | 180 | 214 | 172 | ||||||
Canada | 18 | 13 | 18 | ||||||
Produced Natural Gas Sales Price($/Mcf)(1) | |||||||||
East | $ | 7.78 | $ | 7.99 | $ | 8.02 | |||
Gulf Coast | 8.03 | 7.37 | 6.38 | ||||||
West | 6.13 | 6.05 | 6.00 | ||||||
Canada | 5.47 | 6.18 | 6.79 | ||||||
Weighted Average | 7.23 | 7.13 | 6.74 | ||||||
Produced Crude/Condensate Sales Price($/Bbl)(1) | |||||||||
East | $ | 66.97 | $ | 62.03 | $ | 53.84 | |||
Gulf Coast | 67.17 | 65.44 | 42.81 | ||||||
West | 67.86 | 63.36 | 55.37 | ||||||
Canada | 59.96 | 60.55 | 43.39 | ||||||
Weighted Average | 67.16 | 65.03 | 44.19 | ||||||
Production Costs($/Mcfe)(2) | |||||||||
East | $ | 1.37 | $ | 1.12 | $ | 1.09 | |||
Gulf Coast | 1.44 | 1.37 | 1.14 | ||||||
West | 1.27 | 1.34 | 1.36 | ||||||
Canada | 0.84 | 0.84 | 1.07 | ||||||
Weighted Average | 1.36 | 1.31 | 1.23 | ||||||
(1) | Represents the average realized sales price |
(2) | Production costs include direct lifting costs (labor, repairs and maintenance, materials and supplies), |
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Leasehold Acreage
| Developed | Undeveloped | Total | ||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||
State | ||||||||||||
Arkansas | 1,981 | 425 | 0 | 0 | 1,981 | 425 | ||||||
Colorado | 16,389 | 14,089 | 170,704 | 91,115 | 187,093 | 105,204 | ||||||
Kansas | 29,067 | 27,745 | 0 | 0 | 29,067 | 27,745 | ||||||
Louisiana | 49,541 | 39,784 | 47,366 | 45,235 | 96,907 | 85,019 | ||||||
Montana | 397 | 210 | 32,828 | 25,648 | 33,225 | 25,858 | ||||||
New York | 2,956 | 1,105 | 11,326 | 6,405 | 14,282 | 7,510 | ||||||
North Dakota | 0 | 0 | 870 | 96 | 870 | 96 | ||||||
Ohio | 6,259 | 2,422 | 1,613 | 428 | 7,872 | 2,850 | ||||||
Oklahoma | 167,679 | 117,118 | 13,698 | 9,059 | 181,377 | 126,177 | ||||||
Pennsylvania | 111,953 | 63,752 | 3,449 | 2,312 | 115,402 | 66,064 | ||||||
Texas | 107,754 | 74,051 | 66,149 | 48,130 | 173,903 | 122,181 | ||||||
Utah | 1,740 | 529 | 164,404 | 86,370 | 166,144 | 86,899 | ||||||
Virginia | 22,195 | 20,072 | 5,766 | 4,196 | 27,961 | 24,268 | ||||||
West Virginia | 576,944 | 544,737 | 162,033 | 146,605 | 738,977 | 691,342 | ||||||
Wyoming | 142,816 | 72,340 | 370,869 | 226,132 | 513,685 | 298,472 | ||||||
Federal Offshore | 10,933 | 2,218 | 120,244 | 88,673 | 131,177 | 90,891 | ||||||
Total | 1,248,604 | 980,597 | 1,171,319 | 780,404 | 2,419,923 | 1,761,001 | ||||||
Mineral FeeThe 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.
| Developed | Undeveloped | Total | Developed | Undeveloped | Total | |||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||
State | ||||||||||||||||||||||||
Leasehold Acreage by State | ||||||||||||||||||||||||
Alabama | 0 | 0 | 5,391 | 3,965 | 5,391 | 3,965 | ||||||||||||||||||
Arkansas | 1,981 | 425 | 0 | 0 | 1,981 | 425 | ||||||||||||||||||
Colorado | 0 | 0 | 2,899 | 271 | 2,899 | 271 | 16,268 | 14,053 | 200,334 | 128,450 | 216,602 | 142,503 | ||||||||||||
Kansas | 160 | 128 | 0 | 0 | 160 | 128 | 29,387 | 28,065 | 0 | 160 | 29,387 | 28,225 | ||||||||||||
Louisiana | 628 | 276 | 0 | 0 | 628 | 276 | 8,247 | 6,088 | 20,069 | 19,197 | 28,316 | 25,285 | ||||||||||||
Mississippi | 0 | 0 | 405,731 | 263,605 | 405,731 | 263,605 | ||||||||||||||||||
Montana | 397 | 210 | 9,031 | 8,654 | 9,428 | 8,864 | ||||||||||||||||||
New York | 2,379 | 961 | 621 | 256 | 3,000 | 1,217 | ||||||||||||||||||
Ohio | 6,260 | 2,384 | 21,405 | 20,216 | 27,665 | 22,600 | ||||||||||||||||||
Oklahoma | 184,447 | 129,436 | 30,902 | 23,882 | 215,349 | 153,318 | ||||||||||||||||||
Pennsylvania | 111,496 | 63,549 | 88,932 | 88,484 | 200,428 | 152,033 | ||||||||||||||||||
Texas | 111,866 | 79,605 | 68,970 | 49,727 | 180,836 | 129,332 | ||||||||||||||||||
Utah | 2,820 | 1,609 | 179,137 | 94,436 | 181,957 | 96,045 | ||||||||||||||||||
Virginia | 7,106 | 5,010 | 2,773 | 1,689 | 9,879 | 6,699 | ||||||||||||||||||
West Virginia | 597,793 | 564,969 | 266,953 | 244,435 | 864,746 | 809,404 | ||||||||||||||||||
Wyoming | 139,103 | 72,002 | 221,772 | 127,374 | 360,875 | 199,376 | ||||||||||||||||||
Total | 1,219,550 | 968,366 | 1,522,021 | 1,074,530 | 2,741,571 | 2,042,896 | ||||||||||||||||||
Mineral Fee Acreage by State | ||||||||||||||||||||||||
Colorado | 0 | 0 | 2,899 | 271 | 2,899 | 271 | ||||||||||||||||||
Kansas | 160 | 128 | 0 | 0 | 160 | 128 | ||||||||||||||||||
Montana | 0 | 0 | 589 | 75 | 589 | 75 | 0 | 0 | 589 | 75 | 589 | 75 | ||||||||||||
New York | 0 | 0 | 6,545 | 1,353 | 6,545 | 1,353 | 0 | 0 | 6,545 | 1,353 | 6,545 | 1,353 | ||||||||||||
Oklahoma | 16,580 | 13,979 | 730 | 179 | 17,310 | 14,158 | 16,580 | 13,979 | 730 | 179 | 17,310 | 14,158 | ||||||||||||
Pennsylvania | 524 | 524 | 1,573 | 502 | 2,097 | 1,026 | 524 | 524 | 1,573 | 502 | 2,097 | 1,026 | ||||||||||||
Texas | 327 | 177 | 754 | 327 | 1,081 | 504 | 207 | 135 | 1,012 | 511 | 1,219 | 646 | ||||||||||||
Virginia | 17,817 | 17,817 | 100 | 34 | 17,917 | 17,851 | 17,817 | 17,817 | 100 | 34 | 17,917 | 17,851 | ||||||||||||
West Virginia | 97,455 | 79,093 | 51,447 | 49,593 | 148,902 | 128,686 | 98,162 | 79,490 | 50,896 | 49,669 | 149,058 | 129,159 | ||||||||||||
Total | 133,491 | 111,994 | 64,637 | 52,334 | 198,128 | 164,328 | 133,450 | 112,073 | 64,344 | 52,594 | 197,794 | 164,667 | ||||||||||||
Aggregate Total | 1,382,095 | 1,092,591 | 1,235,956 | 832,738 | 2,618,051 | 1,925,329 | 1,353,000 | 1,080,439 | 1,586,365 | 1,127,124 | 2,939,365 | 2,207,563 | ||||||||||||
| Canada Leasehold Acreage | ||||||||||||||||||||||||
| Developed | Undeveloped | Total | ||||||||||||||||||||||
| Developed | Undeveloped | Total | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Province | ||||||||||||||||||||||||
Canada Leasehold Acreage by Province | ||||||||||||||||||||||||
Alberta | 2,560 | 621 | 4,489 | 1,407 | 7,049 | 2,028 | 14,240 | 6,917 | 102,984 | 35,110 | 117,224 | 42,027 | ||||||||||||
British Columbia | 0 | 0 | 7,778 | 3,889 | 7,778 | 3,889 | 700 | 280 | 11,988 | 4,730 | 12,688 | 5,010 | ||||||||||||
Saskatchewan | 0 | 0 | 4,549 | 1,365 | 4,549 | 1,365 | ||||||||||||||||||
Total | 2,560 | 621 | 12,267 | 5,296 | 14,827 | 5,917 | 14,940 | 7,197 | 119,521 | 41,205 | 134,461 | 48,402 | ||||||||||||
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Total Net Leasehold Acreage by Region of Operation
| Developed | Undeveloped | Total | ||||
Gulf Coast | 89,741 | 181,911 | 271,652 | |||
West | 273,328 | 439,399 | 712,727 | |||
East | 729,522 | 211,428 | 940,950 | |||
Canada | 621 | 5,296 | 5,917 | |||
Total | 1,093,212 | 838,034 | 1,931,246 | |||
| Developed | Undeveloped | Total | ||||
East | 636,873 | 355,080 | 991,953 | |||
Gulf Coast | 58,841 | 336,366 | 395,207 | |||
West | 272,652 | 383,084 | 655,736 | |||
Canada | 7,197 | 41,205 | 48,402 | |||
Total | 975,563 | 1,115,735 | 2,091,298 | |||
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, 2004.2007. The figures below assume no future successful development or renewal of undeveloped acreage.
| 2005 | 2006 | 2007 | ||||
Gulf Coast | 6,257 | 11,328 | 48,513 | |||
West | 75,595 | 42,591 | 34,395 | |||
East | 9,345 | 15,491 | 64,756 | |||
Total | 91,197 | 69,410 | 147,664 | |||
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| 2008 | 2009 | 2010 | ||||
East | 47,435 | 18,917 | 35,325 | |||
Gulf Coast | 33,605 | 65,970 | 162,843 | |||
West | 87,181 | 38,556 | 65,197 | |||
Canada | 13,975 | 4,656 | — | |||
Total | 182,196 | 128,099 | 263,365 | |||
Well Summary
The following table presents our ownership at December 31, 2004,2007, 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), in the East region (consisting of various fields located in West Virginia, Virginia and Ohio) and in the Canada region (consisting of various fields located in the ProvincesProvince of Alberta and British Columbia)Alberta). This summary includes natural gas and oil wells in which we have a working interest.
| Natural Gas | Oil | Total(1) | ||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||
Gulf Coast | 584 | 353.7 | 167 | 141.7 | 751 | 495.4 | ||||||
West | 1,127 | 663.1 | 56 | 32.4 | 1,183 | 695.5 | ||||||
East | 2,559 | 2,381.2 | 25 | 12.1 | 2,584 | 2,393.3 | ||||||
Canada | 14 | 1.5 | 0 | 0 | 14 | 1.5 | ||||||
Total | 4,284 | 3,399.5 | 248 | 186.2 | 4,532 | 3,585.7 | ||||||
| Natural Gas | Oil | Total(1) | ||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||
East | 3,153 | 2,950.2 | 25 | 12.0 | 3,178 | 2,962.2 | ||||||
Gulf Coast | 567 | 356.3 | 118 | 107.8 | 685 | 464.1 | ||||||
West | 1,400 | 810.6 | 55 | 33.2 | 1,455 | 843.8 | ||||||
Canada | 37 | 12.9 | 1 | 0.5 | 38 | 13.4 | ||||||
Total | 5,157 | 4,130.0 | 199 | 153.5 | 5,356 | 4,283.5 | ||||||
(1) | Total does not include service wells of |
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Drilling Activity
We drilled wells, participated in the drilling of wells, or acquired wells as indicated in the region tabletables below.
| Year Ended December 31, 2004 | ||||||||||||||||||||
| Gulf Coast | West | East | Canada | Total | ||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||
Development Wells | ||||||||||||||||||||
Successful | 16 | 9.5 | 45 | 30.8 | 164 | 161.0 | 2 | 0.6 | 227 | 201.9 | ||||||||||
Dry | 4 | 2.9 | 1 | 0.6 | 1 | 1.0 | 0 | 0.0 | 6 | 4.5 | ||||||||||
Extension Wells | ||||||||||||||||||||
Successful | 0 | 0.0 | 0 | 0.0 | 1 | 1.0 | 1 | 0.5 | 2 | 1.5 | ||||||||||
Dry | 0 | 0.0 | 1 | 0.5 | 0 | 0.0 | 0 | 0.0 | 1 | 0.5 | ||||||||||
Exploratory Wells | ||||||||||||||||||||
Successful | 7 | 2.9 | 3 | 1.3 | 4 | 4.0 | 1 | 0.4 | 15 | 8.6 | ||||||||||
Dry | 4 | 2.3 | 0 | 0.0 | 1 | 0.5 | 0 | 0.0 | 5 | 2.8 | ||||||||||
Total | 31 | 17.6 | 50 | 33.2 | 171 | 167.5 | 4 | 1.5 | 256 | 219.8 | ||||||||||
Wells Acquired(1) | 0 | 0.0 | 2 | 1.9 | 25 | 25.0 | 0 | 0.0 | 27 | 26.9 | ||||||||||
Wells in Progress at End of Year | 2 | 1.0 | 12 | 6.4 | 0 | 0.0 | 2 | 0.6 | 16 | 8.0 | ||||||||||
| Year Ended December 31, 2007 | ||||||||||||||||||||
| East | Gulf Coast | West | Canada | Total | ||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||
Development Wells | ||||||||||||||||||||
Successful | 248 | 238.8 | 80 | 61.0 | 96 | 63.1 | 5 | 2.8 | 429 | 365.7 | ||||||||||
Dry | 1 | 1.0 | 3 | 2.5 | 7 | 5.8 | 0 | 0.0 | 11 | 9.3 | ||||||||||
Extension Wells | ||||||||||||||||||||
Successful | 1 | 1.0 | 4 | 3.0 | 0 | 0.0 | 3 | 1.2 | 8 | 5.2 | ||||||||||
Dry | 0 | 0.0 | 0 | 0.0 | 0 | 0.0 | 0 | 0.0 | 0 | 0.0 | ||||||||||
Exploratory Wells | ||||||||||||||||||||
Successful | 3 | 2.8 | 1 | 0.5 | 0 | 0.0 | 2 | 1.2 | 6 | 4.5 | ||||||||||
Dry | 1 | 1.0 | 4 | 4.0 | 2 | 1.2 | 0 | 0.0 | 7 | 6.2 | ||||||||||
Total | 254 | 244.6 | 92 | 71.0 | 105 | 70.1 | 10 | 5.2 | 461 | 390.9 | ||||||||||
Wells Acquired | 0 | 0.0 | 1 | 0.9 | 1 | 1.0 | 0 | 0.0 | 2 | 1.9 | ||||||||||
Wells in Progress at End of Year | 2 | 2.0 | 9 | 5.2 | 2 | 1.1 | 1 | 0.2 | 14 | 8.5 | ||||||||||
| Year Ended December 31, 2006 | ||||||||||||||||||||
| East | Gulf Coast | West | Canada | Total | ||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||
Development Wells | ||||||||||||||||||||
Successful | 195 | 186.0 | 40 | 29.8 | 107 | 56.0 | 5 | 2.7 | 347 | 274.5 | ||||||||||
Dry | 2 | 2.0 | 2 | 1.9 | 3 | 2.3 | 1 | 0.2 | 8 | 6.4 | ||||||||||
Extension Wells | ||||||||||||||||||||
Successful | 0 | 0.0 | 10 | 9.7 | 1 | 0.1 | 0 | 0.0 | 11 | 9.8 | ||||||||||
Dry | 0 | 0.0 | 0 | 0.0 | 0 | 0.0 | 1 | 0.7 | 1 | 0.7 | ||||||||||
Exploratory Wells | ||||||||||||||||||||
Successful | 2 | 2.0 | 8 | 6.2 | 0 | 0.0 | 2 | 0.8 | 12 | 9.0 | ||||||||||
Dry | 1 | 0.7 | 4 | 3.2 | 2 | 1.7 | 1 | 1.0 | 8 | 6.6 | ||||||||||
Total | 200 | 190.7 | 64 | 50.8 | 113 | 60.1 | 10 | 5.4 | 387 | 307.0 | ||||||||||
Wells Acquired | 5 | 5.0 | 0 | 0.0 | 0 | 0.0 | 1 | 0.4 | 6 | 5.4 | ||||||||||
Wells in Progress at End of Year | 0 | 0.0 | 4 | 3.9 | 1 | 0.5 | 2 | 1.3 | 7 | 5.7 | ||||||||||
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| Year Ended December 31, 2005 | ||||||||||||||||||||
| East | West | Gulf Coast | Canada | Total | ||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||
Development Wells | ||||||||||||||||||||
Successful | 182 | 176.8 | 75 | 32.6 | 19 | 13.7 | 5 | 1.6 | 281 | 224.7 | ||||||||||
Dry | 0 | 0.0 | 3 | 1.8 | 0 | 0.0 | 0 | 0.0 | 3 | 1.8 | ||||||||||
Extension Wells | ||||||||||||||||||||
Successful | 0 | 0.0 | 1 | 0.4 | 3 | 2.7 | 0 | 0.0 | 4 | 3.1 | ||||||||||
Dry | 0 | 0.0 | 0 | 0.0 | 1 | 1.0 | 0 | 0.0 | 1 | 1.0 | ||||||||||
Exploratory Wells | ||||||||||||||||||||
Successful | 3 | 3.0 | 1 | 0.7 | 10 | 6.0 | 1 | 0.7 | 15 | 10.4 | ||||||||||
Dry | 0 | 0.0 | 3 | 2.1 | 6 | 2.8 | 3 | 1.2 | 12 | 6.1 | ||||||||||
Total | 185 | 179.8 | 83 | 37.6 | 39 | 26.2 | 9 | 3.5 | 316 | 247.1 | ||||||||||
Wells Acquired | 0 | 0.0 | 0 | 0.0 | 16 | 2.8 | 0 | 0.0 | 16 | 2.8 | ||||||||||
Wells in Progress at End of Year | 3 | 3.0 | 3 | 2.0 | 5 | 3.0 | 3 | 1.1 | 14 | 9.1 | ||||||||||
Competition
Competition in our primary producing areas is intense. Price, contract terms and quality of service, including pipeline connection times and distribution efficiencies, and reliable delivery records, 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 in the East region who do not have similar systems or facilities in place. We also believe that our competitive position in the East region is enhanced by the lack of significant competition from major oil and gas companies. We also actively compete against other companies with substantially larger financial and other resources, particularly in the West and Gulf Coast regions and Canada.
resources.
OTHER BUSINESS MATTERS
Major Customer
In 2004,2007 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. In 2003 and 2002, approximately 11% and 14%, respectively, of our total sales were made to one customer. In 2002, this customer operated certain properties in which we have interests in the Gulf Coast and purchased all of the production from these wells. This customer would resell the natural gas and oil to third parties with whom we would deal directly if the customer either ceased to exist or stopped buying our portion of the production.
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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and 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.
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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 developedestablished interim rules governing the relationship of the 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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establish 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.
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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. These regulations have generally been approved on judicial review. 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. The first such review was completed in December 2000, whereIn March 2006, to implement this required five-year re-determination, the FERC concludedestablished an upward adjustment in the index to track oil pipeline cost changes and determined that the rateProducer Price Index for Finished Goods plus 1.3 percent should be the oil pricing index reasonably reflected actual pipeline costs. Upon judicial review,for the pipeline transportation rates established under the index were increased slightly. The next review is scheduled infive-year period beginning July 2005. 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 relatively new federal regulations, or of the periodic reviewreviews by the FERC of the pipeline index, or the ongoing review of the application of the FERC’s new policy on income tax allowance.
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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Also, 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.
Outer Continental Shelf Lands Act.The federal Outer Continental Shelf Lands Act (OCSLA) and regulations promulgated pursuant thereto impose a variety of regulations relating to safety and environmental protection applicable to lessees, permits and other parties operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to the Outer Continental Shelf Lands Act can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or citizen prosecution. We believe that we substantially comply with the OCSLA and its regulations.
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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 federalFederal 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 (FWPCA or Clean(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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sources 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, 2004, Cabot Oil & Gas2007, we had 346404 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.
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Website Access to Company Reports
We make available free of charge through our website,www.cabotog.com, our annual reportreports 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.Commission (SEC). Information on our website is not a part of this report. In addition, the SEC maintains an Internet site atwww.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 atwww.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.
| ITEM 1A. | RISK FACTORS |
OtherNatural 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.
Our profitability depends on certainPrices 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:
the level of consumer product demand;
weather conditions;
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political conditions in natural gas and oil producing regions, including the Middle East;
the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
the price of foreign imports;
actions of governmental authorities;
pipeline availability and capacity constraints;
inventory storage levels;
domestic and foreign governmental regulations;
the price, availability and acceptance of alternative fuels; and
overall economic conditions.
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:
unexpected drilling conditions, pressure or irregularities in formations;
equipment failures or accidents;
adverse weather conditions;
compliance with governmental requirements; and
shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.
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:
the results of exploration efforts and the acquisition, review and analysis of the seismic data;
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the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
the approval of the prospects by other participants after additional data has been compiled;
economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews;
our financial resources and results; and
the availability of leases and permits on reasonable terms for the prospects.
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These 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 prices. Please see Items 7that are ultimately recovered, and 7A. 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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Our 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 including:
blowouts, cratering explosions and fires, explosions;
mechanical problems, problems;
uncontrolled flows of oil, natural gas, oil or well fluids, fluids;
fires;
formations with abnormal pressures, pressures;
pollution and other environmental risks,risks; and
natural disasters. We
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. Any of these events could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. In accordance with customary industry practice,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 any of these eventsan event not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The costs
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We have limited control over the activities on properties we do not operate.
Other companies operate some of these insurance policies are somewhat dependent on our historical claims experience and also the areasproperties in which we choose to operate. During the past few years, we have invested a higher percentagean interest. Non-operated wells represented approximately 15% of our drilling dollars in the Gulf Coast, where insurance rates are significantly higher than in other regions suchtotal owned gross wells, or approximately 4.7% of our owned net wells, as the East. Atof December 31, 2004,2007. 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 ownedare 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 operated approximately 3,300 milesan 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 gathering and transmission pipeline systems throughoutoil, 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. As partThe U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our normal maintenance program,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 have identified certain segments of our pipelines that we believe may require repair, replacement or additional maintenance,fail to obtain adequate services such as transportation and we schedule this maintenance as appropriate.
processing.
The sale of our oilnatural gas and gasoil production depends on a number of factors beyond our control. The factors includecontrol, including the availability and capacity of transportation and processing facilities. Our failure to access these facilities and 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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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. 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:
a counterparty is unable to satisfy its obligations;
production is less than expected; or
there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.
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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The 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:
for any breach of their duty of loyalty to the company or our stockholders;
for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;
under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and
for any transaction from which the director derived an improper personal benefit.
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.
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
| ITEM 2. | PROPERTIES |
See Item 1. Business.
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| ITEM 3. | LEGAL PROCEEDINGS |
We are a party todefendant in various legal proceedings arising in the normal course of our business. All known liabilities are fully 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.position or cash flow. Operating results, and cash flow, however, could be significantly impacted in the reporting periods in which such matters are resolved.
Wyoming Royalty Litigation
In June 2000, we were sued by two overriding royalty owners in Wyoming state court for unspecified damages. The plaintiffs requested class certification and alleged that we had improperly deducted costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claimed that we had failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. At a mediation held in April 2003, the plaintiffs in this case claimed total damages of $9.5 million plus attorney fees. We settled the case for a total of $2.25 million and the State District Court Judge entered his order approving the settlement in the fourth quarter of 2003. The class included all private fee royalty and overriding royalty owners of the Company in the State of Wyoming except those in the suit discussed below and one owner who opted out of the settlement. It also includes provisions for the method of valuation of gas for royalty payment purposes going forward and for reporting of royalty payments, which should prevent further litigation of these issues by the class members.
In January 2002, 13 overriding royalty owners sued us in Wyoming federal district court. The plaintiffs in the federal case have made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court case but have not asked for class certification.
The federal district court judge certified two questions of state law for decision by the Wyoming State Supreme Court, which recently answered both questions. The Wyoming Supreme Court ruled that certain deductions taken by us from the plaintiffs were not proper and that the statutes of limitations advanced by us are discovery statutes and accordingly do not begin to run until the plaintiffs knew, or had reason to know, of the violation. We believe we have properly reported to the plaintiffs and, that if we did not, the plaintiffs knew or should have known the reporting was improper and the nature of the deductions, thus triggering the statutes of limitations. We still intend to raise defenses to the alleged failure to report claims. There is also a dispute as to how the interest should be calculated.
The federal judge refused to certify a question relating to the issue of the proper calculation of damages for failure to provide certain information required by statute on overriding royalty owner check stubs that had been decided adversely to our position in a state district court letter decision in a separate case. After the federal judge’s refusal to certify this issue, the plaintiffs reduced the damages they were claiming. Based upon recent communication from the plaintiffs, they are now claiming $26.2 million in total damages which consists of $20.3 million for alleged violations of the check stub reporting statute and $5.9 million for all other damages.
In the opinion of our outside counsel, Brown, Drew & Massey, LLP, the likelihood of the plaintiffs recovering $20.3 million for the check stub reporting statute is remote. However, a reserve that management believes is adequate to provide for the check stub reporting statute and all other damages has been established based on management’s estimate at this time of the probable outcome of this case.
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 have requested class certification under the West Virginia Rules of Civil Procedure and allegealleged that we failed to pay royalty based upon the wholesale market value of the gas, produced, that itwe had taken improper deductions from the royalty and that we failed to properly inform royalty owners of the plaintiffs and other similarly situated persons of deductions taken from the royalty.deductions. The plaintiffs have also claimed that they are entitled to a 1/8th 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 1995 Columbia Gas Transmission Corporation bankruptcy proceeding.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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Discoverywould be required to account for production from new wells that came on-line during the process of settlement negotiations and pleadings necessarywere not included in the volumes upon which the $11.6 million settlement was reached. The additional funds bring the total to placebe paid by us to $12.0 million.
In the tentative settlement, we also agreed with the class certification issue beforemembers to a methodology for payment of future royalties and the state court have been ongoing. Areporting format such methodology will take. The tentative settlement was not to be final or binding until approved by the Court. The hearing onfor final approval of the plaintiffs’ motion for class certificationsettlement was held on October 20, 2003, and proposed findingsFebruary 12, 2008. The Court approved the final settlement at the hearing. Upon filing of fact and conclusionsthe written Order of law were submitted toApproval by the court on December 5, 2003. A status conference was held withCourt, the court andprocess will begin for distribution of the court advised it intends to issue a ruling onsettlement proceeds from the class certification motion. The court was expected to rule by December 2004, and we are still awaiting a decision. Discovery is proceeding on the claims pending the ruling on the class certification motion. Discovery is to be completed by April 1, 2005, and the trial is currently scheduled for August 15, 2005. If a class is certified it is expected this trial date will be continued to a later date.
The investigation into this claim continues and it is in the discovery phase.trust. We are vigorously defending the case. We havehad provided a reserve that management believes is adequate based on its estimate atsufficient to cover the amount agreed upon to settle this time of the probable outcome of this case.
Texas Title Litigation
On January 6, 2003, we were served with Plaintiffs’ Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs filed their First Supplemental Original Petition on March 17, 2004 and their Second Supplemental Petition on November 12, 2004. The significant change in the second Supplemental Petition is that plaintiffs appear to limit their claim to the mineral estate, rather than making claims to both the surface and mineral estate. The plaintiffs allege that they are the rightful owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. As Cody Energy, LLC, we acquired certain leases and wells from Wynn-Crosby 1996, Ltd. in 1997 and 1998 and we subsequently acquired a 320 acre lease from Hector and Gloria Lopez in 2001. The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in minerals and all improvements on the lands on which we acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass, conversion, all for unspecified actual and exemplary damages. The original trial date of May 19, 2003 was cancelled and a new trial date has not been set. We have not had the opportunity to conduct discovery in this matter. We estimate that production revenue from this field since its predecessor, Cody Energy, LLC, acquired title and since we acquired its lease is approximately $14.9 million. The carrying value of this property is approximately $34 million. Co-defendants Shell Oil Company and Shell Western E&P filed a motion for summary judgment seeking dismissal of plaintiffs’ causes of action on multiple grounds. The original plaintiffs’ attorneys asked permission from the Court to withdraw from the representation. The Court granted that request, and new attorneys for some, but not all of the plaintiffs have recently entered the case. The motion for summary judgment was reset and a hearing was held in December of 2003. We joined in the motion. After a second hearing, the Court denied the motion for summary judgment. The defendants have moved to add parties whose title interests are being challenged by the plaintiffs, and who are therefore necessary to the case, or in the alternative, abate the proceeding until the plaintiffs join all parties whose interests may be affected by plaintiffs’ claims.
Although the investigation into this claim is in its early stages, we intend to vigorously defend the case. Should we receive an adverse ruling in this case, an impairment review would be assessed to ensure the carrying value of the property is recoverable. Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.
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Raymondville Area
In April 2004, our wholly owned subsidiary, Cody Energy, LLC, filed suit in Willacy County, Texas against certain of our co-working interest owners in the Raymondville Area, located in Kenedy and Willacy Counties. In early 2003, Cody had proposed a new prospect to certain of these co-working interest owners located within jointly owned oil and gas leases. Some of the co-working interest owners elected to participate and some did not. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.
In December 2003, certain of the co-working interest owners who elected not to participate in the initial well notified Cody that they believed that they had the right to participate in subsequent wells. Cody contends that, under the terms of the agreements between the parties, the co-working interest owners that elected not to participate in the initial well in the prospect were required to assign their interest in the proposed prospect to those who elected to participate. Alternatively, Cody contends that such owners lost their right to participate in subsequent wells within a 1,200 foot radius of the initial well.
The defendants have filed a counter claim against us and one of the defendants has filed a lien against Cody’s interest in the leases in the Raymondville Area. Cody contends that this lien is improper and has sought damages for its filing. Cody is vigorously prosecuting this case which is in its early stage of discovery. No trial date has been set by the court.
Certain of the defendants filed a Motion for Partial Summary Judgment contending that they did not have adequate notice of the prospect proposal. Cody is contesting this Motion. In addition, in late December 2004, Cody filed a Motion for Final Summary Judgment asking the court to find that, under the terms of the agreements, Cody and the participating working interest owners are entitled to an assignment of the interests of the co-working interest owners who elected not to participate in the prospect. No hearing date has been set by the court.
Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.
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 $11.1$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.position or cash flow. Operating results, and cash flow, however, could be significantly impacted in the reporting periods in which such matters are resolved.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
| ITEM 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
No matters were submitted to a vote of security holders during the fourth quarter of 2004.2007.
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EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information as of February 15, 2008 about our executive officers, as of February 18, 2005, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.
Name | Age | Position | Officer Since | |||
Dan O. Dinges | 51 | Chairman, President and Chief Executive Officer | 2001 | |||
Michael B. Walen | 56 | Senior Vice President, Exploration and Production | 1998 | |||
Scott C. Schroeder | 42 | Vice President and Chief Financial Officer | 1997 | |||
J. Scott Arnold | 51 | Vice President, Land and Associate General Counsel | 1998 | |||
R. Scott Butler | 50 | Vice President, Regional Manager, West Region | 2001 | |||
Robert G. Drake | 57 | Vice President, Information Services and Operational Accounting | 1998 | |||
Abraham D. Garza | 58 | Vice President, Human Resources | 1998 | |||
Jeffrey W. Hutton | 49 | Vice President, Marketing | 1995 | |||
Thomas S. Liberatore | 48 | Vice President, Regional Manager, East Region | 2003 | |||
Lisa A. Machesney | 49 | Vice President, Managing Counsel and Corporate Secretary | 1995 | |||
Henry C. Smyth | 58 | Vice President, Controller and Treasurer | 1998 |
Name | Age | Position | Officer Since | |||
| Dan O. Dinges | 54 | Chairman, President and Chief Executive Officer | 2001 | |||
| Michael B. Walen | 59 | Senior Vice President, Chief Operating Officer | 1998 | |||
| Scott C. Schroeder | 45 | Vice President and Chief Financial Officer | 1997 | |||
| J. Scott Arnold | 54 | Vice President, Land and Associate General Counsel | 1998 | |||
| Robert G. Drake | 60 | Vice President, Information Services and Operational Accounting | 1998 | |||
| Abraham D. Garza | 61 | Vice President, Human Resources | 1998 | |||
| Jeffrey W. Hutton | 52 | Vice President, Marketing | 1995 | |||
| Thomas S. Liberatore | 51 | Vice President, Regional Manager, East Region | 2003 | |||
| Lisa A. Machesney | 52 | Vice President, Managing Counsel and Corporate Secretary | 1995 | |||
| Henry C. Smyth | 61 | Vice President, Controller and Treasurer | 1998 |
All officers are elected annually by our Board of Directors. Except for the following, allAll of the executive officers have been employed by Cabot Oil & Gas Corporation for at least the last five years.
Dan O. Dinges joined Cabot Oil & Gas Corporation as President and Chief Operating Officer and as a member of the Board of Directors in September 2001. He was promoted to his current position of Chairman, President and Chief Executive Officer in May 2002. Mr. Dinges came to Cabot after a 20-year career with Samedan Oil Corporation, a subsidiary of Noble Affiliates, Inc. The last three years, Mr. Dinges served as Samedan’s Senior Vice President, as well as Division General Manager for the Offshore Division, a position he held since August 1996. He also served as a member of the Executive Operating Committee for Samedan. Mr. Dinges started his career as a Landman for Mobil Oil Corporation covering Louisiana, Arkansas and the central Gulf of Mexico. After four years of expanding responsibilities at Mobil he joined Samedan as a Division Landman – Offshore. Over the years, Mr. Dinges held positions of increasing responsibility at Samedan including Division Manager, Vice President and ultimately Senior Vice President. Mr. Dinges received his BBA degree in Petroleum Land Management from The University of Texas.
Thomas S. Liberatore joined Cabot in January 2002 as Regional Manager, East and was promoted to his current position in July 2003. Prior to joining the Company, Liberatore served as vice president exploration and production for North Coast Energy. He began his career as a geologist and has held various positions of increasing responsibility for Presidio Oil Company and Belden & Blake Corporation. Liberatore received his B.S. in Geology from West Virginia University.
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ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
The Common Stockcommon stock is listed and principally traded on the New York Stock Exchange under the ticker symbol “COG”.“COG.” The following table presents the high and low closing sales prices per share of the Common Stockcommon stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the Common Stockcommon 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.
| High | Low | Cash Dividends | |||||||
2004 | |||||||||
First Quarter | $ | 32.90 | $ | 28.76 | $ | 0.04 | |||
Second Quarter | 42.30 | 30.13 | 0.04 | ||||||
Third Quarter | 45.08 | 38.80 | 0.04 | ||||||
Fourth Quarter | 48.38 | 40.90 | 0.04 | ||||||
2003 | |||||||||
First Quarter | $ | 29.46 | $ | 24.40 | $ | 0.04 | |||
Second Quarter | 27.96 | 24.45 | 0.04 | ||||||
Third Quarter | 30.46 | 26.65 | 0.04 | ||||||
Fourth Quarter | 30.26 | 25.35 | 0.04 | ||||||
| High | Low | Dividends | |||||||
2007 | |||||||||
First Quarter | $ | 35.29 | $ | 28.06 | $ | 0.02 | |||
Second Quarter | $ | 41.88 | $ | 34.55 | $ | 0.03 | |||
Third Quarter | $ | 38.39 | $ | 31.55 | $ | 0.03 | |||
Fourth Quarter | $ | 40.90 | $ | 33.59 | $ | 0.03 | |||
2006 | |||||||||
First Quarter | $ | 26.01 | $ | 21.59 | $ | 0.02 | |||
Second Quarter | $ | 27.22 | $ | 19.21 | $ | 0.02 | |||
Third Quarter | $ | 27.58 | $ | 22.08 | $ | 0.02 | |||
Fourth Quarter | $ | 32.86 | $ | 22.19 | $ | 0.02 | |||
As of January 31, 2005,2007, there were 693574 registered holders of the Common Stock.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
On February 28, 2005, the Company announced that theOur Board of Directors had declaredhas authorized a 3-for-2 split on the Company’s Common Stock in the form of a stock distribution. The stock dividend will be distributed on March 31, 2005 to shareholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company will pay cash based on the closing price of the Common stock on the record date.
Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
Issuer Purchases of Equity Securities (1)
Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate of Shares that | |||||
October 2004 | — | — | — | 1,453,300 | |||||
November 2004 | 136,000 | $ | 42.64 | 136,000 | 1,317,300 | ||||
December 2004 | 25,000 | $ | 43.96 | 25,000 | 1,292,300 | ||||
Total | 161,000 | $ | 42.84 | ||||||
(1) On August 13, 1998, the Company announced that its Board of Directors authorized theshare repurchase of two millionprogram under which we may purchase shares of the Company’scommon stock in the open market or in negotiated transactions. All purchases executed have been through open market transactions. There is no expiration date associated with the authorizationauthorization. During 2007, we did not repurchase any shares of common stock. All purchases executed to repurchase securitiesdate have been through open market transactions. The maximum number of shares that may yet be purchased under the Company.plan as of December 31, 2007 was 4,795,300.
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ITEM 6. SELECTED HISTORICAL FINANCIAL DATAPERFORMANCE 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.
| 2002 | 2003 | 2004 | 2005 | 2006 | 2007 | |||||||
CALCULATED VALUES | ||||||||||||
S&P 500 | 100.0 | 128.7 | 142.7 | 149.7 | 173.3 | 182.9 | ||||||
COG | 100.0 | 119.2 | 180.5 | 277.1 | 373.8 | 499.1 | ||||||
Dow Jones US Exploration & Production | 100.0 | 131.1 | 185.9 | 307.4 | 323.9 | 465.4 |
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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| ITEM 6. | SELECTED FINANCIAL DATA |
The following table summarizes our selected consolidated financial data for Cabot Oil & Gas 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.Notes in Item 8.
| Year Ended December 31, | |||||||||||||||
(In thousands, except per share amounts) | 2004 | 2003 | 2002 | 2001 | 2000 | ||||||||||
Statement of Operations Data | |||||||||||||||
Operating Revenues | $ | 530,408 | $ | 509,391 | $ | 353,756 | $ | 447,042 | $ | 368,651 | |||||
Impairment of Oil and Gas Properties(1) | 3,458 | 93,796 | 2,720 | 6,852 | 9,143 | ||||||||||
Income from Operations | 160,653 | 66,587 | 49,088 | 95,366 | 64,817 | ||||||||||
Net Income | 88,378 | 21,132 | 16,103 | 47,084 | 29,221 | ||||||||||
Basic Earnings per Share | $ | 2.72 | $ | 0.66 | $ | 0.51 | $ | 1.56 | $ | 1.07 | |||||
Dividends per Common Share | $ | 0.16 | $ | 0.16 | $ | 0.16 | $ | 0.16 | $ | 0.16 | |||||
Balance Sheet Data | |||||||||||||||
Properties and Equipment, Net | $ | 994,081 | $ | 895,955 | $ | 971,754 | $ | 981,338 | $ | 623,174 | |||||
Total Assets | 1,210,956 | 1,055,056 | 1,100,947 | 1,092,810 | 776,353 | ||||||||||
Current Maturities of Long-Term Debt | 20,000 | — | — | — | 16,000 | ||||||||||
Long-Term Debt | 250,000 | 270,000 | 365,000 | 393,000 | 253,000 | ||||||||||
Stockholders’ Equity | 455,662 | 365,197 | 350,657 | 346,552 | 242,505 | ||||||||||
| Year Ended December 31, | ||||||||||||||||
(In thousands, except per share amounts) | 2007 | 2006 | 2005 | 2004 | 2003 | |||||||||||
Statement of Operations Data | ||||||||||||||||
Operating Revenues | $ | 732,170 | $ | 761,988 | $ | 682,797 | $ | 530,408 | $ | 509,391 | ||||||
Impairment of Oil and Gas Properties (1) | 4,614 | 3,886 | — | 3,458 | 93,796 | |||||||||||
Gain / (Loss) on Sale of Assets (2) | 13,448 | 232,017 | 74 | (124 | ) | 12,173 | ||||||||||
Income from Operations | 274,693 | 528,946 | 258,731 | 160,653 | 66,587 | |||||||||||
Net Income | 167,423 | 321,175 | 148,445 | 88,378 | 21,132 | |||||||||||
Basic Earnings per Share(3) (4) | $ | 1.73 | $ | 3.32 | $ | 1.52 | $ | 0.91 | $ | 0.22 | ||||||
Diluted Earnings per Share(3) (4) | $ | 1.71 | $ | 3.26 | $ | 1.49 | $ | 0.90 | $ | 0.22 | ||||||
Dividends per Common Share(3) | $ | 0.110 | $ | 0.080 | $ | 0.074 | $ | 0.054 | $ | 0.054 | ||||||
Balance Sheet Data | ||||||||||||||||
Properties and Equipment, Net | $ | 1,908,117 | $ | 1,480,201 | $ | 1,238,055 | $ | 994,081 | $ | 895,955 | ||||||
Total Assets | 2,208,594 | 1,834,491 | 1,495,370 | 1,210,956 | 1,055,056 | |||||||||||
Current Portion of Long-Term Debt | 20,000 | 20,000 | 20,000 | 20,000 | — | |||||||||||
Long-Term Debt | 330,000 | 220,000 | 320,000 | 250,000 | 270,000 | |||||||||||
Stockholders’ Equity | 1,070,257 | 945,198 | 600,211 | 455,662 | 365,197 | |||||||||||
(1) | For discussion of impairment of oil and gas properties, refer to Note |
(2) | Gain on Sale of Assets for 2007 and 2006 reflects $12.3 million and $231.2 million, respectively, related to the 2006 south Louisiana and offshore properties sale, which was substantially completed in the third quarter of 2006. |
(3) | All Earnings per Share and Dividends per Common Share figures have been retroactively adjusted for the 2-for-1 split of our common stock effective March 31, 2007 as well as the 3-for-2 split of our common stock effective March 31, 2005. |
(4) | Year 2003 includes a cumulative effect of a change in accounting principle loss of $0.07 per share related to the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations.” |
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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 notesNotes 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 on page 36.
“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 development.
Canada.
OVERVIEW
Cabot Oil & Gas isand its subsidiaries are a leading independent oil and gas company engaged in the development, exploitation, exploration, developmentproduction and exploitationmarketing 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 constantly compete for available capital. These includecapital: drilling opportunities, acquisition opportunities and financial opportunities such as debt repayment or repurchase of common stock.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 20032006 and 2004,2007, the futures market reported unprecedentedstrong natural gas and crude oil contract prices. Our realized natural gas and crude oil price net of the impact of derivative instruments, was $5.20$7.23 per Mcf and $31.55$67.16 per Bbl, respectively, in 2004. To ensure a certain rate2007. These realized prices include the realized impact of return for our program,derivative instruments. In an effort to manage commodity price risk, we entered into a series of crude oil and natural gas price collars and swaps.collars. These financial instruments are an integralimportant element of our risk management strategy but prevented usand assisted in the increase in our realized natural gas price from realizing the full impact of the price environment.
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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The tables below illustrate how natural gas prices have fluctuated by month over the course of 20032006 and 2004.2007. “Index” represents the first of the month Henry Hub index price per Mmbtu. The “2003”“2006” and “2004”“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:
| Natural Gas Prices by Month - 2007 | ||||||||||||||||||||||||||||||||||||
| Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | |||||||||||||||||||||||||
Index | $ | 5.84 | $ | 6.93 | $ | 7.55 | $ | 7.56 | $ | 7.51 | $ | 7.59 | $ | 6.93 | $ | 6.11 | $ | 5.43 | $ | 6.43 | $ | 7.27 | $ | 7.21 | ||||||||||||
2007 | $ | 7.05 | $ | 7.61 | $ | 7.63 | $ | 7.04 | $ | 7.30 | $ | 7.38 | $ | 7.05 | $ | 6.94 | $ | 6.41 | $ | 7.06 | $ | 7.44 | $ | 7.87 | ||||||||||||
| Natural Gas Prices by Month - 2006 | ||||||||||||||||||||||||||||||||||||
| Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | |||||||||||||||||||||||||
Index | $ | 11.45 | $ | 8.46 | $ | 7.13 | $ | 7.25 | $ | 7.22 | $ | 5.93 | $ | 5.89 | $ | 7.04 | $ | 6.82 | $ | 4.20 | $ | 7.16 | $ | 8.33 | ||||||||||||
2006 | $ | 9.79 | $ | 7.83 | $ | 7.11 | $ | 6.90 | $ | 7.02 | $ | 6.37 | $ | 6.49 | $ | 7.10 | $ | 6.71 | $ | 5.45 | $ | 7.27 | $ | 7.64 | ||||||||||||
| Prices for crude oil have maintained strength in 2006 and rose further in 2007. The tables below contain the NYMEX monthly average crude oil price (Index) and our realized per barrel (Bbl) crude oil prices by month for 2006 and 2007. The “2006” and “2007” price is the crude oil price per Bbl realized by us and includes the realized impact of our crude oil derivative arrangements: | ||||||||||||||||||||||||||||||||||||
| Crude Oil Prices by Month - 2007 | ||||||||||||||||||||||||||||||||||||
| Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | |||||||||||||||||||||||||
Index | $ | 54.67 | $ | 59.39 | $ | 60.74 | $ | 64.04 | $ | 63.53 | $ | 67.53 | $ | 74.15 | $ | 72.36 | $ | 79.63 | $ | 85.66 | $ | 94.63 | $ | 91.74 | ||||||||||||
2007 | $ | 51.59 | $ | 53.17 | $ | 55.54 | $ | 61.31 | $ | 63.35 | $ | 61.42 | $ | 70.68 | $ | 70.03 | $ | 71.90 | $ | 83.97 | $ | 84.38 | $ | 82.65 | ||||||||||||
| Crude Oil Prices by Month - 2006 | ||||||||||||||||||||||||||||||||||||
| Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | |||||||||||||||||||||||||
Index | $ | 65.54 | $ | 61.93 | $ | 62.97 | $ | 70.16 | $ | 70.96 | $ | 70.97 | $ | 74.46 | $ | 73.08 | $ | 63.90 | $ | 59.14 | $ | 59.40 | $ | 62.09 | ||||||||||||
2006 | $ | 63.53 | $ | 60.83 | $ | 59.28 | $ | 68.27 | $ | 68.56 | $ | 68.12 | $ | 74.03 | $ | 73.01 | $ | 60.87 | $ | 53.88 | $ | 55.97 | $ | 59.47 | ||||||||||||
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(in $ per Mcf) | Natural Gas Prices by Month - 2004 | |||||||||||||||||||||||||||||||||||
| Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | |||||||||||||||||||||||||
Index | $ | 6.15 | $ | 5.77 | $ | 5.15 | $ | 5.37 | $ | 5.94 | $ | 6.68 | $ | 6.14 | $ | 6.04 | $ | 5.08 | $ | 5.79 | $ | 7.63 | $ | 7.78 | ||||||||||||
2004 | $ | 5.23 | $ | 5.23 | $ | 5.17 | $ | 4.88 | $ | 4.96 | $ | 5.23 | $ | 5.39 | $ | 5.21 | $ | 4.54 | $ | 5.29 | $ | 5.63 | $ | 5.55 | ||||||||||||
(in $ per Mcf) | Natural Gas Prices by Month - 2003 | |||||||||||||||||||||||||||||||||||
| Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | |||||||||||||||||||||||||
Index | $ | 4.96 | $ | 5.66 | $ | 9.11 | $ | 5.14 | $ | 5.12 | $ | 5.95 | $ | 5.30 | $ | 4.69 | $ | 4.93 | $ | 4.44 | $ | 4.45 | $ | 4.86 | ||||||||||||
2003 | $ | 4.33 | $ | 4.62 | $ | 4.71 | $ | 4.48 | $ | 4.44 | $ | 4.57 | $ | 4.65 | $ | 4.43 | $ | 4.53 | $ | 4.33 | $ | 4.34 | $ | 4.67 | ||||||||||||
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, for crude oil have followed a similar path as the commodity price continued to maintain strength in 2003 and rose further in 2004. The tables below contain the NYMEX average crude oil price (Index) and our realized per barrel (Bbl) crude oil prices by month for 2003 and 2004. The “2003” and “2004” price is the crude oil price per Bbl realized by us and includesincluding the realized impact of our crude oil derivative arrangements:
(in $ per Bbl) | Crude Oil Prices by Month - 2004 | |||||||||||||||||||||||||||||||||||
| Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | |||||||||||||||||||||||||
Index | $ | 34.23 | $ | 34.50 | $ | 36.72 | $ | 36.62 | $ | 40.28 | $ | 38.05 | $ | 40.81 | $ | 44.88 | $ | 45.94 | $ | 53.09 | $ | 48.48 | $ | 43.26 | ||||||||||||
2004 | $ | 30.62 | $ | 30.66 | $ | 31.62 | $ | 30.97 | $ | 30.80 | $ | 31.51 | $ | 31.43 | $ | 33.00 | $ | 31.61 | $ | 32.87 | $ | 33.15 | $ | 30.46 | ||||||||||||
(in $ per Bbl) | Crude Oil Prices by Month - 2003 | |||||||||||||||||||||||||||||||||||
| Jan | Feb | Mar | Apr | May | Jun | Jul | Aug | Sep | Oct | Nov | Dec | |||||||||||||||||||||||||
Index | $ | 32.70 | $ | 35.73 | $ | 33.16 | $ | 28.14 | $ | 28.07 | $ | 30.52 | $ | 30.70 | $ | 31.60 | $ | 28.31 | $ | 30.35 | $ | 31.06 | $ | 32.14 | ||||||||||||
2003 | $ | 29.81 | $ | 31.47 | $ | 31.35 | $ | 29.65 | $ | 29.18 | $ | 28.95 | $ | 30.11 | $ | 28.82 | $ | 26.46 | $ | 27.17 | $ | 29.43 | $ | 32.93 | ||||||||||||
We reported earnings of $2.72 per share, or $88.4 million, for 2004. This is up from the $0.66 per share, or $21.1 million, reported in 2003. The decline in impairments of oil and gas properties was the driving factor in this improvement. In 2003, there was an after-tax impairment of $54.4 million related to our Kurten field (seeLimited Partnership for discussion of the impairment). In addition, the stronger price environment contributed to the earnings increase. Prices, including the impact of the hedge arrangements, rose 15%instruments, increased by one percent for natural gas and 7%three percent for oil.
We drilled 256461 gross wells with a success rate of 95%96% in 20042007 compared to 173387 gross wells with an 89%a success rate of 96% in 2003.2006. Total capital and exploration expenditures increased $71.3by $98.7 million to $259.5$636.2 million in 20042007 compared to $188.2$537.5 million for 2003.in 2006. We believe our cash on hand and operating cash flow in 20052008 will be sufficient to fund a substantial portion of our budgeted capital and exploration budgeted spending of approximately $280 million and again provide excess cash flow.$490 million. Any excess cash flow mayadditional needs will be used for acquisitions, to pay current debt due, repurchase common stock, expandfunded by borrowings from our capital program or other opportunities.
credit facility.
Our 20052008 strategy will remain consistent with 2004 focusing2007. We will remain focused on a disciplined approachour strategy of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we will continue to investmentadd 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 balancesthese strategies are appropriate for our drilling effort between exploration opportunitiesportfolio of projects and the development program, along with acquisition opportunitiescurrent industry environment and a continued financial focus including stock buyback and debt repayment.
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 on page 36.“Forward-Looking Information” for further details.
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FINANCIAL CONDITION
Capital Resources and Liquidity
Our primary sourcesources of cash in 2004 was2007 were from funds generated from operations. Proceeds from the sale of common stocknatural gas and crude oil production and borrowings under stock option plans during 2004 roughly offset our repurchaserevolving 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 405,100 treasury shares of Company stock at a weighted average purchase price of $38.58. The Company generatescash 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 subject tovolatile, 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. Working capital is substantially influenced by these variables. FluctuationIn addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See Results“Results of OperationsOperations” for a review of the impact of prices and volumes on sales. Cash flows provided
Working capital is also substantially influenced by operating activities were primarily usedthese variables discussed above. From time to fund exploration and development expenditures, purchase treasury stock and pay dividends. See below for additional discussion and analysis of cash flow.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.
| Year-Ended December 31, | ||||||||||||
| 2004 | 2003 | 2002 | ||||||||||
Cash Flows Provided by Operating Activities | $ | 273,022 | $ | 241,638 | $ | 164,182 | ||||||
Cash Flows Used by Investing Activities | (255,357 | ) | (151,856 | ) | (138,668 | ) | ||||||
Cash Flows Used by Financing Activities | (8,363 | ) | (90,660 | ) | (27,364 | ) | ||||||
Net Increase (Decrease) in Cash and Cash Equivalents | $ | 9,302 | $ | (878 | ) | $ | (1,850 | ) | ||||
| Year Ended December 31, | ||||||||||||
(In thousands) | 2007 | 2006 | 2005 | |||||||||
Cash Flows Provided by Operating Activities | $ | 462,137 | $ | 357,104 | $ | 364,560 | ||||||
Cash Flows Used in Investing Activities | (589,922 | ) | (187,353 | ) | (412,150 | ) | ||||||
Cash Flows Provided by / (Used in) Financing Activities | 104,429 | (138,523 | ) | 48,190 | ||||||||
Net (Decrease) / Increase in Cash and Cash Equivalents | $ | (23,356 | ) | $ | 31,228 | $ | 600 | |||||
Operating Activities. Net cash provided by operating activities in 20042007 increased $31.4by $105.0 million over 2003.2006. This increase iswas mainly due to a decrease in cash paid for current income taxes from 2006 to 2007 primarily due to higher commodity prices.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 drivers ofcomponents impacting net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased 15%by one percent in 2007 over 2003, while2006 and average crude oil realized prices increased 7%by three percent over the same period. Production volumes declined slightly, with a 5Equivalent production decreased by three percent reduction of equivalent production in 20042007 compared to 2003. While we believe 2005 commodity2006 as a result of a decrease in crude oil production, may exceed 2004 levels, weoffset 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 2003 increased $77.52006 decreased by $7.5 million over 2002.2005. 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 higher commodity prices. Key driversthe 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 49%six percent over 2002,2005, while crude oil realized prices increased 24%47% over the same period. Production volumes declined slightly with a 2% reduction of equivalentEquivalent production increased by five percent in 20032006 compared to 2002. 2005.
See page 25“Results of Operations” for a discussion on commodity prices and Results of Operations for a review of the impact of prices and volumes on sales revenue.
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Investing Activities. The primary driveruses of cash used byin investing activities iswere capital spending and exploration expense.expenses. We establishestablished 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 budgetcapital expenditures may be periodically adjusted during any given year. Cash flows used in investing activities increased for the years ended December 31, 2004by $402.6 million from 2006 to 2007 and 2003 in the amounts of $103.5decreased by $224.8 million and $13.2 million.from 2005 to 2006. The increase from 20032006 to 2004 is primarily2007 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 drilling activity as a result2007 in capital expenditures, partially offset by reduced exploration expenses of $9.6 million.
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Cash 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 largely occurredof $103.7 million in our East region and the Rocky Mountain area of our West region. Our initial drilling activity in Canada also contributed to the increase. Cash flows used in investing activities increased from 2002 to 2003 due to an increaseinvestments in capital spending and exploration expense in response to higher commodity prices and exploitation of acquired properties. This increaseexpenses was partiallyentirely offset by the increase of $328.5 million in proceeds received from the sale of certain non-strategic assets.
assets, primarily as a result of the 2006 south Louisiana and offshore properties sale.
Financing Activities. Cash flows usedprovided by financing activities were $8.4$104.4 million for the year ended December 31, 2004. This is the result of2007, 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 sharesstock and dividend payments. Cash flows used by financing activities for the year ended
At December 31, 2003 was $90.7 million. This is substantially due to a net repayment on2007, we had $140 million of borrowings outstanding under our revolving credit facility in the amountat a weighted-average interest rate of $95.0 million. Cash utilized for the repayments was generated from operating cash flows.6.9%. The cash flows used by financing activities in 2002 is primarily due to a net repayment on our revolving credit facility of $25.0 million.
Theprovides for an available credit line under our revolving credit facility, which wasof $250 million, at year end, butwhich 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 bank’sbanks’ petroleum engineer) and other assets. At December 31, 2004, we had no outstanding balance on the credit facility. 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 thea share repurchase of two millionprogram under which we may purchase shares of our common stock in the open market or in negotiated transactions. All purchases executed have been through open market transactions. There is no expiration date associated with the authorizationauthorization. We did not repurchase any shares of our common stock during 2007. All purchases executed to repurchase securitiesdate have been through open market transactions. The maximum number of shares that may yet be purchased under the Company.plan as of December 31, 2007 was 4,795,300. See “Issuer Purchases of Equity Securities” in Item 5 “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer RepurchasesPurchases of Equity Securities” for additional information.
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Capitalization
Information about our capitalization is as follows:
| December 31, | ||||||||
| 2004 | 2003 | |||||||
| (In millions) | ||||||||
Debt(1) | $ | 270.0 | $ | 270.0 | ||||
Stockholders’ Equity (2) (3) | 455.7 | 365.2 | ||||||
Total Capitalization | $ | 725.7 | $ | 635.2 | ||||
Debt to Capitalization(3) | 37 | % | 43 | % | ||||
Cash and Cash Equivalents | $ | 10.0 | $ | 0.7 | ||||
| December 31, | ||||||||
(Dollars in millions) | 2007 | 2006 | ||||||
Debt(1) | $ | 350.0 | $ | 240.0 | ||||
Stockholders’ Equity | 1,070.3 | 945.2 | ||||||
Total Capitalization | $ | 1,420.3 | $ | 1,185.2 | ||||
Debt to Capitalization | 25 | % | 20 | % | ||||
Cash and Cash Equivalents | $ | 18.5 | $ | 41.9 | ||||
(1) | Includes $20.0 million of current portion of |
| at both December 31, 2007 and 2006. Includes |
For the year ended December 31, 2004,2007, we paid dividends of $5.2$10.7 million on our common stock. A regular dividend of $0.04 per share of common stock has been declared for each quarter since we became a public company.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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Increase 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 majorany 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, 2004.2007.
(In millions) | 2004 | 2003 | 2002 | ||||||
Capital Expenditures | |||||||||
Drilling and Facilities | $ | 174.0 | $ | 102.0 | $ | 67.0 | |||
Leasehold Acquisitions | 18.3 | 14.1 | 4.8 | ||||||
Pipeline and Gathering | 13.5 | 10.6 | 4.1 | ||||||
Other | 1.6 | 1.8 | 1.4 | ||||||
| 207.4 | 128.5 | 77.3 | |||||||
Proved Property Acquisitions | 4.0 | 1.5 | 8.8 | ||||||
Exploration Expense | 48.1 | 58.2 | 40.2 | ||||||
Total | $ | 259.5 | $ | 188.2 | $ | 126.3 | |||
(In millions) | 2007 | 2006 | 2005 | ||||||
Capital Expenditures | |||||||||
Drilling and Facilities | $ | 524.7 | $ | 406.9 | $ | 249.3 | |||
Leasehold Acquisitions | 22.2 | 42.6 | 22.1 | ||||||
Pipeline and Gathering | 28.2 | 24.2 | 17.9 | ||||||
Other | 17.3 | 7.7 | 1.4 | ||||||
| 592.4 | 481.4 | 290.7 | |||||||
Proved Property Acquisitions | 4.0 | 6.7 | 73.1 | ||||||
Exploration Expense | 39.8 | 49.4 | 61.8 | ||||||
Total | $ | 636.2 | $ | 537.5 | $ | 425.6 | |||
We plan to drill about 300approximately 419 gross wells (366 net) in 20052008 compared with 256461 gross wells (391 net) drilled in 2004.2007. 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 20052008 drilling program includes approximately $280.0$490 million in total capital and exploration expenditures, updown from $259.5$636.2 million in 2004.2007. 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 20052008, management expects an increase in our depreciation, depletion and amortizationDD&A rate due to production declines and higher capital costs.costs, partially as a result of inflationary cost pressures in the industry over the last four years. This change may result in an increase of depreciation, depletion and amortization of 5%is currently estimated to 10%be approximately five percent greater than 20042007 levels. This increase will not have an impact on our cash flows.
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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,obligations.
During 2006, we assisted certain non-executive employees in obtaining loans to purchase interests offered under our Mineral, Royalty and we have not guaranteedOverriding Royalty Interest Plan by providing a guarantee of repayment should the debtnon-executive employee fail to repay the loan. The repayment term for all of any other party.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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A summary of our known contractual obligations as of December 31, 20042007 are set forth in the following table:
| Payments Due by Year | |||||||||||||||
(In thousands) | Total | 2005 | 2006 to 2007 | 2008 to 2009 | 2010 & Beyond | ||||||||||
Long-Term Debt(1) | $ | 270,000 | $ | 20,000 | $ | 40,000 | $ | 40,000 | $ | 170,000 | |||||
Interest on Long-Term Debt(2) | 126,405 | 19,545 | 34,776 | 29,024 | 43,060 | ||||||||||
Firm Gas Transportation Agreements | 87,888 | 8,117 | 13,321 | 7,565 | 58,885 | ||||||||||
Operating Leases | 17,000 | 4,889 | 8,882 | 2,847 | 382 | ||||||||||
Total Contractual Cash Obligations | $ | 501,293 | $ | 52,551 | $ | 96,979 | $ | 79,436 | $ | 272,327 | |||||
| Payments Due by Year | |||||||||||||||
(In thousands) | Total | 2008 | 2009 to 2010 | 2011 to 2012 | 2013 & Beyond | ||||||||||
Long-Term Debt(1) | $ | 350,000 | $ | 20,000 | $ | 160,000 | $ | 75,000 | $ | 95,000 | |||||
Interest on Long-Term Debt (2) | 91,960 | 24,992 | 36,011 | 19,469 | 11,488 | ||||||||||
Firm Gas Transportation Agreements(3) | 82,165 | 9,937 | 16,859 | 7,876 | 47,493 | ||||||||||
Drilling Rig Commitments (3) | 71,332 | 41,180 | 30,152 | — | — | ||||||||||
Operating Leases(3) | 11,512 | 5,414 | 5,387 | 711 | — | ||||||||||
Total Contractual Cash Obligations | $ | 606,969 | $ | 101,523 | $ | 248,409 | $ | 103,056 | $ | 153,981 | |||||
(1) | Including current portion. |
(2) | Interest payments have been calculated utilizing the fixed rates of our $210 million long-term debt outstanding at December 31, 2007. Interest payments on our revolving credit facility were calculated by assuming that the December 31, 2007 outstanding balance of $140 million will be outstanding through the 2009 maturity date and by assuming a constant interest rate of 6.9%, which was the December 31, 2007 weighted-average interest rate. Actual results will likely differ from these estimates and assumptions. |
(3) | For further information on our obligations under firm gas transportation agreements, drilling rig commitments and operating leases, see Note 7 of the Notes to the Consolidated Financial Statements. |
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, 2004 is $40.4 million.
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 uncertain,imprecise, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysic,geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The degree of uncertainty varies among the three regions in which we operate. The estimation of reserves in the Gulf Coast region requires more estimates than the East and West regions and inherently has more uncertainty surrounding reserve estimation. The differences in the reserve estimation process are substantially due to the geological conditions in which the wells are drilled. 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. The accuracy of a reserve estimate is a function of:
In 2004, 2003 and 2002,Since 1990, 100% of our reserves were subject to an external reviewhave 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. Additionally, in 2004, 2003 and 2002, we didWe have not havebeen required to record a significant reserve revision recorded.in the past three years. For more information regarding reserve estimation, including historical reserve revisions, refer to the Supplemental“Supplemental Oil and Gas Disclosure beginning on page 85.Information.”
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Our rate of recording depreciation, depletion and amortizationDD&A expense (DD&A) 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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market 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 $0.04$0.08 to $0.05$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 SFASStatement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived AssetsAssets.”. 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 2002 there were no unusual or unexpected occurrences that caused significant revisions in estimated cash flows which were utilized in our impairment test. In 2003 we significantly revised the estimated cash flow utilized in our impairment review of the Kurten field due to a loss of a reversionary interest in the field. In December 2003 our remaining interest in the field was sold. For additional discussion on the Kurten field impairment see Note 2 to the consolidated financial statements. In 20042007, 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,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. However, if the average property life increases, the amount of the amortization charge in a given reporting period will decrease. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $2.3$8.6 million or decrease by approximately $1.9$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 East and West regions have been six, four six and sixseven 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.
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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 an effective hedge.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. AnyThe ineffective portion, if any, of the gains or losses that are considered ineffective underchange in the SFAS 133 test arefair value of derivatives designated as hedges, and the change in fair value of all other derivatives, is recorded immediatelycurrently in earnings as a component of operating revenue onNatural Gas Production and Crude Oil and Condensate Revenue, as appropriate in the statementConsolidated Statement of operations.Operations.
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Long-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, 2004,2007, the assumed rate of increase was 10.0%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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invested 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 BasedStock-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 the issuance of SFAS 123R “Share Based Payment”, there were two alternative methods that could be used to accountJanuary 1, 2006, we accounted for stock-based compensation. The firstcompensation in accordance with the intrinsic value based method is the Intrinsic Valueprescribed by Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.” Under this method, and recognizeswe 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. The secondIn 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 is the Fair Value 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. Currently, we account for stock-based compensation in accordance with the Intrinsic Value method. SFAS 123R requires that the fair value of stock options and any other equity-based compensation must be expensed at the grant date. To calculate the fair value, either a binomial or Black-Scholes valuation model may be used. We currently
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; however, beginningawards. 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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share 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 requiredsustained 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 expense all stock based compensation. Further discussionNote 6 of SFAS 123R and stock compensation is included in “Recently Issued Accounting Pronouncements” on page 35.the Notes to the Consolidated Financial Statements.
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OTHER ISSUES AND CONTINGENCIES
Corporate Income Tax. We generated tax credits for the production of certain qualified fuels, including natural gas produced from tight sands formations and Devonian Shale. The credit for natural gas from a tight sand formation (tight gas sands) amounted to $0.52 per Mmbtu for natural gas sold prior to 2003 from qualified wells drilled in 1991 and 1992. A number of wells drilled in the East region and Rocky Mountains during 1991 and 1992 qualified for the tight gas sands tax credit. The credit for natural gas produced from Devonian Shale was $1.09 per Mmbtu in 2002. In 1995 and 1996, we completed three transactions to monetize the value of these tax credits, resulting in revenues of $2.0 million in 2002. The tax credit wells were repurchased in December 2002 and no tax credits were generated in 2003 or 2004 as the credits expired in 2002. See Note 13 of the Notes to the Consolidated Financial Statements for further discussion.
We have benefited in the past and may benefit in the future from the alternative minimum
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tax (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.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 can notcannot 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 ProductionExploration and Transportation”Production,” “Natural Gas Marketing, Gathering and Transportation,” “Federal Regulation of Petroleum” and “Environmental Regulations” in the “Other Business Matters” section of Item 1 “Business” 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 the Company’sour various debt instruments. Among other requirements, our Revolving Credit Agreementrevolving credit agreement and the Notesour 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, 2004,2007, we are in compliance in all material respects with all restrictive covenants on both the Revolving Credit Agreementrevolving credit agreement and the Notes.notes. In the unforeseen event that we fail to comply with these covenants, the Companywe 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“Capital Resources and Liquidity.”
Limited Partnership.As part of the 2001 Cody acquisition, we acquired an interest in certain oil and gas properties in the Kurten field, as general partner of a partnership and as an operator. We had approximately a 25% interest in the field, including a one percent interest in the partnership. Under the partnership agreement, we had the right to a reversionary working interest that would bring our ultimate interest to 50% upon the limited partner reaching payout. Based on the addition of this reversionary interest, and because the field has over a 40-year reserve life, approximately $91 million was allocated to this field under purchase accounting at the time of the acquisition. Additionally, the limited partner had the sole option to trigger a liquidation of the partnership.
Effective February 13, 2003, liquidation of the partnership commenced at the election of the limited partner. The limited partner was a financial entity and not an industry operator. Their decision to liquidate was based upon their perception that the value of their investment in the partnership had increased due to an increase in underlying commodity prices, primarily oil, since their investment in 1999. We proceeded with the liquidation to avoid having a minority interest in a non-operated water flood field for which the new operator was not designated at the time of liquidation. In connection with the liquidation, an appraisal was required to be obtained to allocate the interest in the partnership assets. Additionally, we were required to test the field for recoverability in accordance with FAS 144. Pursuant to the terms of the partnership agreement and based on the appraised value of the partnership assets it was not possible for us to obtain the reversionary interest as part of the liquidation. Due to the impact of the loss of the reversionary interest on future estimated net cash flows of the Kurten field, the limited partner’s decision and our decision to proceed with the liquidation, an impairment review was performed which required an after-tax impairment charge in the first quarter of 2003 of $54.4 million. This impairment charge is reflected in the 2003 Statement of Operations as an operating expense but did not impact our cash flows.
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Operating Risks and Insurance Coverage.Our business involves a variety of operating risks. See “Risk Factors—We face a variety of hazards and risks including:
The operation of our 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,that could increase these risks. Any of these events could resultcause substantial financial losses” in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us.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 materially adversely affecthave 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“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 collarcollars 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 the Companyour not being able to realize the full benefit of a market improvement.
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Recently Issued Accounting Pronouncements
In May 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” This FSP provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) for employers that sponsor postretirement health care plans that provide prescription drug benefits. This FSP also requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Act (the subsidy). This FSP supersedes FSP 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” and is effective for the first interim period beginning after June 15, 2004. Our current accumulated projected benefit obligation and net periodic postretirement benefit cost does not reflect any amount associated with the subsidy. Furthermore, in 2004, we amended our postretirement benefit plan to exclude prescription drug benefits for participants age 65 and older effective January 1, 2006. The adoption of this FSP is not expected to impact our operating results, financial position or cash flows.
In November 2004, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 151, “Inventory Costs—an amendment of ARB No. 43, Chapter 4” in an effort to unite the United States accounting standards for inventories with International Accounting Standards leading to consistent application of certain accounting requirements. FAS 151 addresses accounting for abnormal amounts of freight, handling costs, idle facility expense and spoilage (wasted material) and requires that these costs be recognized as current period expenses. Previously, these costs had to be categorized as “so abnormal as to require treatment as current period charges.” In addition, allocation of fixed production overheads to the costs of conversion must be based on the normal capacity of the production facilities. FAS 151 will be effective for fiscal periods beginning after June 15, 2005. The adoption of this statement is not expected to impact our operating results, financial position or cash flows.
In December 2004, the FASB issued SFAS 153 “Exchanges of Nonmonetary Assets – an amendment of APB Opinion No. 29.” This statement requires that nonmonetary exchanges must be recorded at fair value and the appropriate gain or loss must be recognized so long as the fair value is determinable and the transaction has commercial substance. According to this statement, companies can no longer use the “similar productive assets” concept to account for nonmonetary exchanges at book value with no gain or loss being recognized. FAS 153 will be effective for fiscal periods beginning after June 15, 2005. The adoption of this statement may impact our operating results, financial position or cash flows in future periods if such a nonmonetary exchange occurs.
In December 2004,2007, the FASB issued SFAS No. 123R, “Share-Based Payment.160, “Noncontrolling Interest in Consolidated Financial Statements, an amendment of Accounting Research Bulletin (ARB) No. 51.” SFAS 123R revisesNo. 160 clarifies that a noncontrolling interest (previously commonly referred to as a minority interest) in a subsidiary is an ownership
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interest 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 123, “AccountingNo. 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 Stock-Based Compensation”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 focusesincreased 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 ofSettlement 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 share-based paymentsfiscal 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 services by employer to employee. The statement requiresall 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 expensechoose, at
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specified 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 of employee stock optionsoption and other equity-based compensation atto all entities with available-for-sale and trading securities. Additional disclosures are also required for instruments for which the grant date. The statement does not require a certain type of valuation model and either a binomial or Black-Scholes model may be used. The provisions offair value option is elected. SFAS 123R areNo. 159 is effective for financial statementsfiscal years beginning after November 15, 2007. No retrospective application is allowed, except for fiscal periods ending after June 15, 2005. We are currently evaluatingcompanies that choose to adopt early. At the methodeffective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of adoption and 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 operating results. Our future cash flows will not be impacted by the adoptionfinancial position or results of this standard. See Footnote 1 “Stock Based Compensation” for further information.operations.
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In February 2005,September 2006, the FASB releasedissued SFAS No. 157, “Fair Value Measurements,” which establishes a formal framework for public comment proposed Staff Position FAS 19-a “Accounting for Suspended Well Costs.” This proposed staff position would amend FASB Statement No. 19 “Financial Accountingmeasuring fair values of assets and Reportingliabilities in financial statements that are already required by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The proposed position states that exploratory well costs should continueUnited States generally accepted accounting principles (GAAP) to be capitalized if: 1) a sufficient quantity of reserved are discoveredmeasured at fair value. SFAS No. 157 clarifies guidance in the well to justify its completion as a producing well and 2) sufficient progress is madeFASB Concepts Statement (CON) No. 7 which discusses present value techniques in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvagemeasuring fair value. Additional disclosures are also required to provide information about management’s evaluation of capitalized exploratory well costs.for transactions measured at fair value. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. In addition,November 2007, the Staff Position requires the disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized forFASB granted a period greater than one year deferral (to fiscal years beginning after the completionNovember 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 drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Although this Staff Position is not final and has not been adopted by us, we have included the additional disclosures in Note 2. Comments on this proposed FSP are expected by March 7, 2005.
* * *
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.
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RESULTS OF OPERATIONS
20042007 and 20032006 Compared
We reported net income for the year ended December 31, 20042007 of $88.4$167.4 million, or $2.72$1.73 per share. During 2003,2006, we reported net income of $21.1$321.2 million, or $0.66$3.32 per share. OperatingThis decrease of $153.8 million in net income increased by $94.1was primarily due to a decrease in operating income of $254.2 million comparedresulting from the gain on sale of assets of $231.2 million included in 2006 related to the prior year,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 $66.6the 2006 south Louisiana and offshore properties sale. Additionally, there was a $29.8 million to $160.7 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 net income and operating income was principally due to decreased operating expenses from 2003 to 2004 related towas primarily the decreaseresult of increased DD&A and impairment expenses, offset in impairments of oilpart by reduced exploration and gas properties of $90.3 million related to the loss in 2003 of a reversionary interest in the Kurten field. In addition, the increases in operating incomegeneral and net income were due to an increase in our realized natural gas and crude oil prices.administrative expenses.
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Natural Gas Production Revenues
Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $5.20$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 $0.35 per Mcf in 2006. There was no revenue impact from the unrealized change in natural gas derivative fair value for the years ended December 31, 2007 or 2006.
| Year Ended December 31, | Variance | |||||||||||||
| 2007 | 2006 | Amount | Percent | |||||||||||
Natural Gas Production(Mmcf) | ||||||||||||||
East | 24,344 | 23,542 | 802 | 3 | % | |||||||||
Gulf Coast | 26,797 | 29,973 | (3,176 | ) | (11 | %) | ||||||||
West | 25,409 | 23,633 | 1,776 | 8 | % | |||||||||
Canada | 3,925 | 2,574 | 1,351 | 52 | % | |||||||||
Total Company | 80,475 | 79,722 | 753 | 1 | % | |||||||||
Natural Gas Production Sales Price ($/Mcf) | ||||||||||||||
East | $ | 7.78 | $ | 7.99 | $ | (0.21 | ) | (3 | %) | |||||
Gulf Coast | $ | 8.03 | $ | 7.37 | $ | 0.66 | 9 | % | ||||||
West | $ | 6.13 | $ | 6.05 | $ | 0.08 | 1 | % | ||||||
Canada | $ | 5.47 | $ | 6.18 | $ | (0.71 | ) | (11 | %) | |||||
Total Company | $ | 7.23 | $ | 7.13 | $ | 0.10 | 1 | % | ||||||
Natural Gas Production Revenue(In thousands) | ||||||||||||||
East | $ | 189,392 | $ | 188,111 | $ | 1,281 | 1 | % | ||||||
Gulf Coast | 215,106 | 221,020 | (5,914 | ) | (3 | %) | ||||||||
West | 155,676 | 143,058 | 12,618 | 9 | % | |||||||||
Canada | 21,466 | 15,908 | 5,558 | 35 | % | |||||||||
Total Company | $ | 581,640 | $ | 568,097 | $ | 13,543 | 2 | % | ||||||
Price Variance Impact on Natural Gas Production Revenue | ||||||||||||||
(In thousands) | ||||||||||||||
East | $ | (5,127 | ) | |||||||||||
Gulf Coast | 17,774 | |||||||||||||
West | 2,121 | |||||||||||||
Canada | (2,792 | ) | ||||||||||||
Total Company | $ | 11,976 | ||||||||||||
Volume Variance Impact on Natural Gas Production Revenue | ||||||||||||||
(In thousands) | ||||||||||||||
East | $ | 6,408 | ||||||||||||
Gulf Coast | (23,688 | ) | ||||||||||||
West | 10,497 | |||||||||||||
Canada | 8,350 | |||||||||||||
Total Company | $ | 1,567 | ||||||||||||
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 $84.0 million, or 17%, and natural gas production would have increased by 9,791 Mmcf, or 14%, from 2006 to 2007.
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Brokered Natural Gas Revenue and Cost
| Year Ended December 31, | Variance | |||||||||||||
| 2007 | 2006 | Amount | Percent | |||||||||||
Sales Price($/Mcf) | $ | 8.40 | $ | 8.14 | $ | 0.26 | 3 | % | ||||||
Volume Brokered (Mmcf) | 11,101 | 11,502 | (401 | ) | (3 | %) | ||||||||
Brokered Natural Gas Revenues(In thousands) | $ | 93,215 | $ | 93,651 | ||||||||||
Purchase Price($/Mcf) | $ | 7.37 | $ | 7.25 | $ | 0.12 | 2 | % | ||||||
Volume Brokered(Mmcf) | 11,101 | 11,502 | (401 | ) | (3 | %) | ||||||||
Brokered Natural Gas Cost(In thousands) | $ | 81,819 | $ | 83,375 | ||||||||||
Brokered Natural Gas Margin(In thousands) | $ | 11,396 | $ | 10,276 | $ | 1,120 | 11 | % | ||||||
(In thousands) | ||||||||||||||
Sales Price Variance Impact on Revenue | $ | 2,828 | ||||||||||||
Volume Variance Impact on Revenue | (3,264 | ) | ||||||||||||
| $ | (436 | ) | ||||||||||||
(In thousands) | ||||||||||||||
Purchase Price Variance Impact on Purchases | $ | (1,351 | ) | |||||||||||
Volume Variance Impact on Purchases | 2,907 | |||||||||||||
| $ | 1,556 | |||||||||||||
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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Crude 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 $65.03 per Bbl for 2006. There was no realized impact of crude oil derivative instruments in 2006. There was no unrealized impact of crude oil derivative instruments in 2007 or 2006.
| Year Ended December 31, | Variance | |||||||||||||
| 2007 | 2006 | Amount | Percent | |||||||||||
Crude Oil Production(Mbbl) | ||||||||||||||
East | 26 | 24 | 2 | 8 | % | |||||||||
Gulf Coast | 605 | 1,160 | (555 | ) | (48 | %) | ||||||||
West | 174 | 209 | (35 | ) | (17 | %) | ||||||||
Canada | 18 | 12 | 6 | 50 | % | |||||||||
Total Company | 823 | 1,405 | (582 | ) | (41 | %) | ||||||||
Crude Oil Sales Price($/Bbl) | ||||||||||||||
East | $ | 66.97 | $ | 62.03 | $ | 4.94 | 8 | % | ||||||
Gulf Coast | $ | 67.17 | $ | 65.44 | $ | 1.73 | 3 | % | ||||||
West | $ | 67.86 | $ | 63.36 | $ | 4.50 | 7 | % | ||||||
Canada | $ | 59.96 | $ | 60.55 | $ | (0.59 | ) | (1 | %) | |||||
Total Company | $ | 67.16 | $ | 65.03 | $ | 2.13 | 3 | % | ||||||
Crude Oil Revenue(In thousands) | ||||||||||||||
East | $ | 1,734 | $ | 1,474 | $ | 260 | 18 | % | ||||||
Gulf Coast | 40,673 | 75,894 | (35,221 | ) | (46 | %) | ||||||||
West | 11,784 | 13,253 | (1,469 | ) | (11 | %) | ||||||||
Canada | 1,052 | 759 | 293 | 39 | % | |||||||||
| �� | ||||||||||||||
Total Company | $ | 55,243 | $ | 91,380 | $ | (36,137 | ) | (40 | %) | |||||
Price Variance Impact on Crude Oil Revenue | ||||||||||||||
(In thousands) | ||||||||||||||
East | $ | 128 | ||||||||||||
Gulf Coast | 1,048 | |||||||||||||
West | 781 | |||||||||||||
Canada | (10 | ) | ||||||||||||
Total Company | $ | 1,947 | ||||||||||||
Volume Variance Impact on Crude Oil Revenue | ||||||||||||||
(In thousands) | ||||||||||||||
East | $ | 132 | ||||||||||||
Gulf Coast | (36,269 | ) | ||||||||||||
West | (2,250 | ) | ||||||||||||
Canada | 303 | |||||||||||||
Total Company | $ | (38,084 | ) | |||||||||||
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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Impact 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:
| Year Ended December 31, | |||||||||||||
| 2007 | 2006 | ||||||||||||
(In thousands) | Realized | Unrealized | Realized | Unrealized | |||||||||
Operating Revenues - Increase / (Decrease) to Revenue | |||||||||||||
Cash Flow Hedges | |||||||||||||
Natural Gas Production | $ | 79,838 | $ | — | $ | 28,266 | $ | — | |||||
Crude Oil | (796 | ) | — | — | — | ||||||||
Total Cash Flow Hedges | $ | 79,042 | $ | — | $ | 28,266 | $ | — | |||||
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:
Depreciation, Depletion and Amortization increased by $14.9 million in 2007 over 2006. This is primarily due to the impact on the DD&A rate of negative reserve revisions due to lower prices at the end of 2006, higher capital costs and commencement of production in an east Texas field.
Exploration expense decreased by $9.6 million from 2006 to 2007, primarily as a result of a decrease in total dry hole expense of $10.3 million, primarily in Canada and, to a lesser extent, in the West and Gulf Coast regions. In addition, there was a decrease in geophysical and geological expenses of $1.8 million, primarily due to a decrease in the Gulf Coast region, offset in part by an increase in Canada. Offsetting part of these decreases was an increase of $2.6 million in land and lease search expenses during 2007.
Impairment of Unproved Properties increased by $7.9 million in 2007 compared to 2006, primarily due to increased lease acquisition costs during 2005 and 2006 in several exploratory areas.
General and Administrative expense decreased by $7.4 million in 2007 primarily due to decreased stock compensation charges of $5.9 million as well as $4.2 million in decreased professional services fees for litigation. Partially offsetting these decreases were increases in employee compensation related expenses and bad debt expense.
Direct Operations expense increased by $2.4 million as a result of higher employee compensation charges and disposal, treating, compressor, workover and maintenance costs, partially offset by lower outside operated properties expense and insurance expense.
Brokered Natural Gas Cost decreased by $1.6 million from 2006 to 2007. See the preceding table labeled “Brokered Natural Gas Revenue and Cost” for further analysis.
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Taxes Other Than Income decreased by $1.5 million for 2007 compared to 2006, primarily due to decreased production taxes of $3.3 million as a result of decreased commodity volumes and prices as well as decreased franchise taxes, partially offset by an increase in ad valorem taxes.
Impairment of Oil and Gas Properties increased by $0.7 million for the year ended December 31, 2007 compared to the year ended December 31, 2006, due an impairment recorded in 2007 in the Gulf Coast region resulting from two non-commercial development completions in a small field in north Louisiana.
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.
- 53 -
Natural 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 $4.51$6.74 per Mcf for the comparable period of 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 $0.76$1.33 per Mcf in 2004 and $0.68 per Mcf in 2003.2005. The following table excludes the unrealized gain from the change in derivative fair value of $0.9 million and the unrealized loss of $1.5 million for the years ended December 31, 2004 and 2003, respectively. These unrealized changes in fair value have been included in the Natural Gas Production revenues line item on the Statement of Operations.
Year Ended December 31, | Variance | |||||||||||||
| 2004 | 2003 | Amount | Percent | |||||||||||
Natural Gas Production (Mmcf) | ||||||||||||||
Gulf Coast | 31,358 | 29,550 | 1,808 | 6 | % | |||||||||
West | 21,866 | 23,776 | (1,910 | ) | (8 | )% | ||||||||
East | 19,442 | 18,580 | 862 | 5 | % | |||||||||
Canada | 167 | — | 167 | — | ||||||||||
Total Company | 72,833 | 71,906 | 927 | 1 | % | |||||||||
Natural Gas Production Sales Price ($/Mcf) | ||||||||||||||
Gulf Coast | $ | 5.27 | $ | 4.78 | $ | 0.49 | 10 | % | ||||||
West | $ | 4.75 | $ | 3.67 | $ | 1.08 | 29 | % | ||||||
East | $ | 5.60 | $ | 5.15 | $ | 0.45 | 9 | % | ||||||
Canada | $ | 4.69 | $ | — | $ | 4.69 | — | |||||||
Total Company | $ | 5.20 | $ | 4.51 | $ | 0.69 | 15 | % | ||||||
Natural Gas Production Revenue (in thousands) | ||||||||||||||
Gulf Coast | $ | 165,177 | $ | 141,107 | $ | 24,070 | 17 | % | ||||||
West | 103,851 | $ | 87,245 | 16,606 | 19 | % | ||||||||
East | 108,935 | $ | 95,672 | 13,263 | 14 | % | ||||||||
Canada | 784 | — | 784 | — | ||||||||||
Total Company | $ | 378,747 | $ | 324,024 | $ | 54,723 | 17 | % | ||||||
Price Variance Impact on Natural Gas Production Revenue | ||||||||||||||
(in thousands) | ||||||||||||||
Gulf Coast | $ | 15,434 | ||||||||||||
West | 23,613 | |||||||||||||
East | 8,828 | |||||||||||||
Canada | 784 | |||||||||||||
Total Company | $ | 48,659 | ||||||||||||
Volume Variance Impact on Natural Gas Production Revenue | ||||||||||||||
(in thousands) | ||||||||||||||
Gulf Coast | $ | 8,635 | ||||||||||||
West | (7,009 | ) | ||||||||||||
East | 4,438 | |||||||||||||
Canada | — | |||||||||||||
Total Company | $ | 6,064 | ||||||||||||
The increase in natural gas production revenues was mainly a result of increased sales prices as well as the increase in overall production. Natural gas production was up slightly from the prior year and production revenues also increased from 2003. Natural gas production increased slightly in all regions except the West region, where the decline in production was due to lower capital spending in 2003 and continued natural decline. The increases in both sales price and production resulted in an increase in natural gas production revenues of $54.7 million.
- 37 -
Brokered Natural Gas Revenue and Cost
Year Ended December 31, | Variance | |||||||||||||
| 2004 | 2003 | Amount | Percent | |||||||||||
Sales Price ($/Mcf) | $ | 6.56 | $ | 5.16 | $ | 1.40 | 27 | % | ||||||
Volume Brokered (Mmcf) | 12,876 | 18,557 | (5,681 | ) | (31 | )% | ||||||||
Brokered Natural Gas Revenues (in thousands) | $ | 84,416 | $ | 95,754 | ||||||||||
Purchase Price ($/Mcf) | $ | 5.84 | $ | 4.64 | $ | 1.20 | 26 | % | ||||||
Volume Brokered (Mmcf) | 12,876 | 18,557 | (5,681 | ) | (31 | )% | ||||||||
Brokered Natural Gas Cost (in thousands) | $ | 75,217 | $ | 86,104 | ||||||||||
Brokered Natural Gas Margin (in thousands) | $ | 9,199 | $ | 9,650 | $ | (451 | ) | (5 | )% | |||||
(in thousands) | ||||||||||||||
Sales Price Variance Impact on Revenue | $ | 18,026 | ||||||||||||
Volume Variance Impact on Revenue | $ | (29,363 | ) | |||||||||||
| $ | (11,337 | ) | ||||||||||||
(in thousands) | ||||||||||||||
Purchase Price Variance Impact on Purchases | $ | (15,451 | ) | |||||||||||
Volume Variance Impact on Purchases | $ | 26,338 | ||||||||||||
| $ | 10,887 | |||||||||||||
The decrease in brokered natural gas revenues of $11.3 million combined with the decline in brokered natural gas cost of $10.9 million resulted in a decrease to the brokered natural gas margin of $0.5 million.
- 38 -
Crude Oil and Condensate Revenues
Our average total company realized crude oil sales price, including the realized impact of derivative instruments, was $31.55 per Bbl compared to $29.55 per Bbl for 2003. These prices include the realized impact of derivative instruments which reduced these prices by $8.98 per Bbl in 2004 and $1.41 per Bbl in 2003. The following table excludes the unrealized loss from the change in derivative fair value of $2.9 million and $1.9$1.1 million for the year ended December 31, 2004 and 2003, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate revenues line item on the Statement of Operations.
Year Ended December 31, | Variance | |||||||||||||
| 2004 | 2003 | Amount | Percent | |||||||||||
Crude Oil Production (Mbbl) | ||||||||||||||
Gulf Coast | 1,805 | 2,591 | (786 | ) | (30 | %) | ||||||||
West | 159 | 188 | (29 | ) | (15 | %) | ||||||||
East | 27 | 27 | — | — | ||||||||||
Canada | 4 | — | 4 | — | ||||||||||
Total Company | 1,995 | 2,806 | (811 | ) | (29 | %) | ||||||||
Crude Oil Sales Price ($/Bbl) | ||||||||||||||
Gulf Coast | $ | 30.67 | $ | 29.48 | $ | 1.19 | 4 | % | ||||||
West | $ | 40.29 | $ | 30.11 | $ | 10.18 | 34 | % | ||||||
East | $ | 38.28 | $ | 32.65 | $ | 5.63 | 17 | % | ||||||
Canada | $ | 37.93 | $ | — | $ | 37.93 | — | |||||||
Total Company | $ | 31.55 | $ | 29.55 | $ | 2.00 | 7 | % | ||||||
Crude Oil Revenue (in thousands) | ||||||||||||||
Gulf Coast | $ | 55,357 | $ | 76,375 | $ | (21,018 | ) | (28 | %) | |||||
West | 6,404 | 5,675 | 729 | 13 | % | |||||||||
East | 1,049 | 870 | 179 | 21 | % | |||||||||
Canada | 129 | — | 129 | — | ||||||||||
Total Company | $ | 62,939 | $ | 82,920 | $ | (19,981 | ) | (24 | %) | |||||
| �� | ||||||||||||||
Price Variance Impact on Crude Oil Revenue | ||||||||||||||
(in thousands) | ||||||||||||||
Gulf Coast | $ | 2,151 | ||||||||||||
West | 1,604 | |||||||||||||
East | 179 | |||||||||||||
Canada | 129 | |||||||||||||
Total Company | $ | 4,063 | ||||||||||||
Volume Variance Impact on Crude Oil Revenue | ||||||||||||||
(in thousands) | ||||||||||||||
Gulf Coast | $ | (23,169 | ) | |||||||||||
West | (875 | ) | ||||||||||||
East | — | |||||||||||||
Canada | — | |||||||||||||
Total Company | $ | (24,044 | ) | |||||||||||
The decline in crude oil production is due to emphasis on natural gas in the Gulf Coast drilling program, along with the natural decline of existing production in south Louisiana. The increase in the realized crude oil price combined with the decline in production resulted in a net revenue decrease of $20.0 million.
- 39 -
Other Operating Revenues
Other operating revenues decreased $3.7 million. This change2005. There was primarily a result of decreases in natural gas transportation revenue and natural gas liquid revenue for the year ended December 31, 2004.
Operating Expenses
Total costs and expenses from operations decreased $85.3 million for the year ended December 31, 2004 compared to the year ended December 31, 2003. The primary reasons for this fluctuation are as follows:
Interest Expense
Interest expense decreased $1.7 million. This variance is due to a lower average level of outstanding debt on the revolving credit facility offset somewhat by an increase in Prime rates. Average daily borrowings under the revolving credit facility during the year were $0.5 million in 2004 which is a decrease from $0.7 million in 2003. Our other remaining debt is at fixed interest rates.
Income Tax Expense
Income tax expense increased $35.2 million due to a comparable increase in our pre-tax net income.
- 40 -
2003 and 2002 Compared
We reported net income for the year ended December 31, 2003 of $21.1 million, or $0.66 per share. During the corresponding period of 2002, we reported net income of $16.1 million, or $0.51 per share. Operating income increased by $17.5 million compared to the comparable period of the prior year. The increase in net income and operating income was substantially due to an increase in our realized natural gas and crude oil prices.
Natural Gas Production Revenues
The average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $4.51 per Mcf. Due to derivative instruments this price was reduced by $0.68 per Mcf. The following table excludes theno unrealized impact offrom the change in derivative fair value for the year ended December 31, 2003 and 2002.2006. These amountsunrealized changes in fair value have been included in the Natural Gas Production Revenues line item onin the Consolidated Statement of Operations. See Item 7A for a discussion of the realized and unrealized impact of derivative instruments on operating revenues.
Year Ended December 31, | Variance | |||||||||||||
| 2003 | 2002 | Amount | Percent | |||||||||||
Natural Gas Production (Mmcf) | ||||||||||||||
Gulf Coast | 29,550 | 30,408 | (858 | ) | (3 | %) | ||||||||
West | 23,776 | 25,308 | (1,533 | ) | (6 | %) | ||||||||
East | 18,580 | 17,953 | 626 | 3 | % | |||||||||
Total Company | 71,906 | 73,670 | (1,764 | ) | (2 | %) | ||||||||
Natural Gas Production Sales Price ($/Mcf) | ||||||||||||||
Gulf Coast | $ | 4.78 | $ | 3.34 | $ | 1.44 | 43 | % | ||||||
West | $ | 3.67 | $ | 2.39 | $ | 1.28 | 54 | % | ||||||
East | $ | 5.15 | $ | 3.38 | $ | 1.77 | 52 | % | ||||||
Total Company | $ | 4.51 | $ | 3.02 | $ | 1.49 | 49 | % | ||||||
Natural Gas Production Revenue (in thousands) | ||||||||||||||
Gulf Coast | $ | 141,107 | $ | 101,525 | $ | 39,582 | 39 | % | ||||||
West | $ | 87,245 | $ | 60,563 | $ | 26,682 | 44 | % | ||||||
East | $ | 95,672 | $ | 60,696 | $ | 34,976 | 58 | % | ||||||
Total Company | $ | 324,024 | $ | 222,784 | $ | 101,240 | 45 | % | ||||||
Price Variance Impact on Natural Gas Production Revenue | ||||||||||||||
(in thousands) | ||||||||||||||
Gulf Coast | $ | 42,446 | ||||||||||||
West | $ | 30,349 | ||||||||||||
East | $ | 32,859 | ||||||||||||
Total Company | $ | 105,654 | ||||||||||||
Volume Variance Impact on Natural Gas Production Revenue | ||||||||||||||
(in thousands) | ||||||||||||||
Gulf Coast | $ | (2,864 | ) | |||||||||||
West | $ | (3,667 | ) | |||||||||||
East | $ | 2,117 | ||||||||||||
Total Company | $ | (4,414 | ) | |||||||||||
| Year Ended December 31, | Variance | |||||||||||||
| 2006 | 2005 | Amount | Percent | |||||||||||
Natural Gas Production(Mmcf) | ||||||||||||||
East | 23,542 | 21,435 | 2,107 | 10 | % | |||||||||
Gulf Coast | 29,973 | 28,071 | 1,902 | 7 | % | |||||||||
West | 23,633 | 23,224 | 409 | 2 | % | |||||||||
Canada | 2,574 | 1,149 | 1,425 | 124 | % | |||||||||
Total Company | 79,722 | 73,879 | 5,843 | 8 | % | |||||||||
Natural Gas Production Sales Price ($/Mcf) | ||||||||||||||
East | $ | 7.99 | $ | 8.02 | $ | (0.03 | ) | 0 | % | |||||
Gulf Coast | $ | 7.37 | $ | 6.38 | $ | 0.99 | 16 | % | ||||||
West | $ | 6.05 | $ | 6.00 | $ | 0.05 | 1 | % | ||||||
Canada | $ | 6.18 | $ | 6.79 | $ | (0.61 | ) | (9 | %) | |||||
Total Company | $ | 7.13 | $ | 6.74 | $ | 0.39 | 6 | % | ||||||
Natural Gas Production Revenue(In thousands) | ||||||||||||||
East | $ | 188,111 | $ | 171,902 | $ | 16,209 | 9 | % | ||||||
Gulf Coast | 221,020 | 179,061 | 41,959 | 23 | % | |||||||||
West | 143,058 | 139,298 | 3,760 | 3 | % | |||||||||
Canada | 15,908 | 7,802 | 8,106 | 104 | % | |||||||||
Total Company | $ | 568,097 | $ | 498,063 | $ | 70,034 | 14 | % | ||||||
Price Variance Impact on Natural Gas Production Revenue | ||||||||||||||
(In thousands) | ||||||||||||||
East | $ | (692 | ) | |||||||||||
Gulf Coast | 29,822 | |||||||||||||
West | 1,189 | |||||||||||||
Canada | (1,572 | ) | ||||||||||||
Total Company | $ | 28,747 | ||||||||||||
Volume Variance Impact on Natural Gas Production Revenue | ||||||||||||||
(In thousands) | ||||||||||||||
East | $ | 16,901 | ||||||||||||
Gulf Coast | 12,137 | |||||||||||||
West | 2,571 | |||||||||||||
Canada | 9,678 | |||||||||||||
Total Company | $ | 41,287 | ||||||||||||
The declineincrease in Natural Gas Production Revenue is due to the increase in natural gas sales production is due substantiallyand, to a lesser extent, the sizeincrease in realized natural gas prices. Production increased in all regions and timing ofprices were up in the Gulf Coast and West drilling programs, along with the natural decline of existing production.West. The increase in the total realized natural gas price combined with the decline inand production resulted in a net revenue increase of $101.2$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 $70.5 million.
- 4154 -
Brokered Natural Gas Revenue and Cost
Year Ended December 31, | Variance | |||||||||||||
| 2003 | 2002 | Amount | Percent | |||||||||||
Sales Price ($/Mcf) | $ | 5.16 | $ | 3.12 | $ | 2.04 | 65 | % | ||||||
Volume Brokered (Mmcf) | 18,557 | 18,807 | (250 | ) | (1 | %) | ||||||||
Brokered Natural Gas Revenues (in thousands) | $ | 95,754 | $ | 58,678 | ||||||||||
Purchase Price ($/Mcf) | $ | 4.64 | $ | 2.82 | $ | 1.82 | 65 | % | ||||||
Volume Brokered (Mmcf) | 18,557 | 18,807 | (250 | ) | (1 | %) | ||||||||
Brokered Natural Gas Cost (in thousands) | $ | 86,104 | $ | 53,036 | ||||||||||
Brokered Natural Gas Margin (in thousands) | $ | 9,650 | $ | 5,642 | $ | 4,008 | 71 | % | ||||||
(in thousands) | ||||||||||||||
Sales Price Variance Impact on Revenue | $ | 37,856 | ||||||||||||
Volume Variance Impact on Revenue | $ | (780 | ) | |||||||||||
| $ | 37,076 | |||||||||||||
(in thousands) | ||||||||||||||
Purchase Price Variance Impact on Purchases | $ | (33,774 | ) | |||||||||||
Volume Variance Impact on Purchases | $ | 705 | ||||||||||||
| $ | (33,069 | ) | ||||||||||||
| Year Ended December 31, | Variance | |||||||||||||
| 2006 | 2005 | Amount | Percent | |||||||||||
Sales Price($/Mcf) | $ | 8.14 | $ | 9.14 | $ | (1.00 | ) | (11 | %) | |||||
Volume Brokered (Mmcf) | 11,502 | 10,793 | 709 | 7 | % | |||||||||
Brokered Natural Gas Revenues(In thousands) | $ | 93,651 | $ | 98,605 | ||||||||||
Purchase Price($/Mcf) | $ | 7.25 | $ | 8.08 | $ | (0.83 | ) | (10 | %) | |||||
Volume Brokered(Mmcf) | 11,502 | 10,793 | 709 | 7 | % | |||||||||
Brokered Natural Gas Cost(In thousands) | $ | 83,375 | $ | 87,183 | ||||||||||
Brokered Natural Gas Margin(In thousands) | $ | 10,276 | $ | 11,422 | $ | (1,146 | ) | (10 | %) | |||||
(In thousands) | ||||||||||||||
Sales Price Variance Impact on Revenue | $ | (11,434 | ) | |||||||||||
Volume Variance Impact on Revenue | 6,480 | |||||||||||||
| $ | (4,954 | ) | ||||||||||||
(In thousands) | ||||||||||||||
Purchase Price Variance Impact on Purchases | $ | 9,537 | ||||||||||||
Volume Variance Impact on Purchases | (5,729 | ) | ||||||||||||
| $ | 3,808 | |||||||||||||
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.
- 4255 -
Crude Oil and Condensate Revenues
TheOur 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, was $29.55 per Bbl forwhich reduced the year ended December 31, 2003. Due to derivative instruments, this price was reduced by $1.41$9.93 per Bbl. The following table excludes the unrealized gain from the change in derivative fair value of $5.5 million for the year ended December 31, 2005. There was no unrealized impact offrom the change in derivative fair value for the year ended December 31, 2003 and 2002.2006. These amountsunrealized changes in fair value have been included in the Crude Oil and Condensate revenues line item onRevenues in the Consolidated Statement of Operations. See Item 7A for a discussion of the realized and unrealized impact of derivative instruments on operating revenues.
| Year Ended December 31, | Variance | Year Ended December 31, | Variance | |||||||||||||||||||||||||
| 2003 | 2002 | Amount | Percent | 2006 | 2005 | Amount | Percent | |||||||||||||||||||||
Crude Oil Production (Mbbl) | ||||||||||||||||||||||||||||
East | 24 | 27 | (3 | ) | (11 | %) | ||||||||||||||||||||||
Gulf Coast | 2,591 | 2,620 | (30 | ) | (1 | %) | 1,160 | 1,528 | (368 | ) | (24 | %) | ||||||||||||||||
West | 188 | 216 | (27 | ) | (13 | %) | 209 | 166 | 43 | 26 | % | |||||||||||||||||
East | 27 | 33 | (6 | ) | (18 | %) | ||||||||||||||||||||||
Canada | 12 | 18 | (6 | ) | (33 | %) | ||||||||||||||||||||||
Total Company | 2,806 | 2,869 | (63 | ) | (2 | %) | 1,405 | 1,739 | (334 | ) | (19 | %) | ||||||||||||||||
Crude Oil Sales Price ($/Bbl) | ||||||||||||||||||||||||||||
East | $ | 62.03 | $ | 53.84 | $ | 8.19 | 15 | % | ||||||||||||||||||||
Gulf Coast | $ | 29.48 | $ | 23.69 | $ | 5.79 | 24 | % | $ | 65.44 | $ | 42.81 | $ | 22.63 | 53 | % | ||||||||||||
West | $ | 30.11 | $ | 25.24 | $ | 4.87 | 19 | % | $ | 63.36 | $ | 55.37 | $ | 7.99 | 14 | % | ||||||||||||
East | $ | 32.65 | $ | 22.09 | $ | 10.56 | 48 | % | ||||||||||||||||||||
Canada | $ | 60.55 | $ | 43.39 | $ | 17.16 | 40 | % | ||||||||||||||||||||
Total Company | $ | 29.55 | $ | 23.79 | $ | 5.77 | 24 | % | $ | 65.03 | $ | 44.19 | $ | 20.84 | 47 | % | ||||||||||||
Crude Oil Revenue (in thousands) | ||||||||||||||||||||||||||||
Crude Oil Revenue(In thousands) | ||||||||||||||||||||||||||||
East | $ | 1,474 | $ | 1,463 | $ | 11 | 1 | % | ||||||||||||||||||||
Gulf Coast | $ | 76,375 | $ | 62,075 | $ | 14,299 | 23 | % | 75,894 | 65,427 | 10,467 | 16 | % | |||||||||||||||
West | $ | 5,675 | $ | 5,445 | $ | 230 | 4 | % | 13,253 | 9,155 | 4,098 | 45 | % | |||||||||||||||
East | $ | 870 | $ | 721 | $ | 149 | 21 | % | ||||||||||||||||||||
Canada | 759 | 791 | (32 | ) | (4 | %) | ||||||||||||||||||||||
Total Company | $ | 82,919 | $ | 68,241 | $ | 14,678 | 22 | % | $ | 91,380 | $ | 76,836 | $ | 14,544 | 19 | % | ||||||||||||
Price Variance Impact on Crude Oil Revenue | ||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
East | $ | 195 | ||||||||||||||||||||||||||
Gulf Coast | $ | 14,999 | 26,242 | |||||||||||||||||||||||||
West | $ | 917 | 1,672 | |||||||||||||||||||||||||
East | $ | 281 | ||||||||||||||||||||||||||
Canada | 198 | |||||||||||||||||||||||||||
Total Company | $ | 16,197 | $ | 28,307 | ||||||||||||||||||||||||
Volume Variance Impact on Crude Oil Revenue | ||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
East | $ | (184 | ) | |||||||||||||||||||||||||
Gulf Coast | $ | (700 | ) | (15,775 | ) | |||||||||||||||||||||||
West | $ | (687 | ) | 2,426 | ||||||||||||||||||||||||
East | $ | (133 | ) | |||||||||||||||||||||||||
Canada | (230 | ) | ||||||||||||||||||||||||||
Total Company | $ | (1,519 | ) | $ | (13,763 | ) | ||||||||||||||||||||||
The decline in crude oil production is due substantially to the size and timing of the Gulf Coast drilling program, along with the natural decline of existing production. The increase in the realized crude oil price combined withoffset by the decline in production resulted in a net revenue increase of $14.6 million.
- 43 -
Other Operating Revenues
Other operating revenues increased $3.6 million. This change was a$14.5 million, excluding the unrealized impact of derivative instruments. The decrease in oil production is primarily the result of an increasedecreased Gulf Coast production from the 2006 south Louisiana and offshore properties sale in plant revenue, transportation revenuethe third quarter of 2006 and the continued natural gas liquid revenue fordecline of the CL&F lease in south Louisiana, which was part of the sale. For the year ended December 31, 2003.2006, 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.
- 56 -
Impact 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:
| Year Ended December 31, | ||||||||||||||
| 2006 | 2005 | |||||||||||||
(In thousands) | Realized | Unrealized | Realized | Unrealized | ||||||||||
Operating Revenues - Increase / (Decrease) to Revenue | ||||||||||||||
Cash Flow Hedges | ||||||||||||||
Natural Gas Production | $ | 28,266 | $ | — | $ | (98,223 | ) | $ | 1,114 | |||||
Crude Oil | — | — | (2,430 | ) | (6 | ) | ||||||||
Total Cash Flow Hedges | 28,266 | — | (100,653 | ) | 1,108 | |||||||||
Other Derivative Financial Instruments | ||||||||||||||
Crude Oil | — | — | (14,842 | ) | 5,518 | |||||||||
Total Other Derivative Financial Instruments | — | — | (14,842 | ) | 5,518 | |||||||||
| $ | 28,266 | $ | — | $ | (115,495 | ) | $ | 6,626 | ||||||
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 $150.1by $41.0 million for the year ended December 31, 20032006 compared to the year ended December 31, 2002.2005. The primary reasons for this fluctuation arewere as follows:
Depreciation, Depletion and Amortization increased $33.2by $20.5 million in 2006. This was primarily due to increased production during 2006, an increase in finding costs and an increase in the DD&A rate associated with one field in east Texas as well as the commencement of offshore production in late 2005.
General and Administrative expense increased by $20.5 million in 2006. This increase was primarily due to increased stock compensation costs of $11.6 million. For additional informationDuring 2006, performance share and restricted stock amortization expense increased by $9.6 million and $0.7 million, respectively, primarily due to new grants issued in 2006 and changes in the accounting for the value of performance shares. During 2006, expense related to this increase seeSARs, which were granted for the analysis performedfirst time in 2006, and stock options, which were being expensed in 2006 due to the adoption of SFAS No. 123(R), increased by $1.3 million in total. In addition, there were increases in salaries and incentive compensation related to employee bonuses over the prior year as well as reserves for Brokered Natural Gas Revenue and Cost.litigation expenses.
Exploration expense decreased by $12.4 million in 2006, primarily as a result of decreased dry hole expense of $12.2 million, mainly as a result of a decrease in the Gulf Coast attributable to a more successful drilling program in 2006 compared to 2005 and, to a lesser extent, better success in Canada, partially offset by increased $18.0dry hole expense in the West region. In addition, geological and geophysical expenses were down by $1.9 million. Partially offsetting this overall decrease was an increase in employee expenses for salaries and benefits of approximately $1.2 million for employees in the exploration division as well as increased delay rental expenses of $0.6 million.
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Direct Operations expense in 2006 increased by $13.0 million over 2005. This was primarily the result of an increase over the prior year in incentive compensation and personnel related charges, insurance costs, and outside operated properties expense mainly from increases in the Gulf Coast region, largely from repairs related to a plant damaged by the hurricanes that occurred in 2005 and also, to a lesser extent, in the West region. Additional increases occurred in disposal costs, compressor expenses, and treating and pipeline costs. Partially offsetting these increases were decreased workover charges and outside operated plant operations expenses.
Impairment of Oil and Gas Properties increased by $3.9 million as a result of higher dry hole expensean impairment recorded in 2003. During 2003, we drilled 15 dry exploratory wells2006 for a marginally productive gas well in Colorado County, Texas in the Gulf Coast region compared to 3no impairments of oil and gas properties in 2005. Further analysis of this impairment is discussed in Note 2 of the corresponding period of 2002.Notes to the Consolidated Financial Statements.
Brokered Natural Gas Cost decreased by $3.8 million from 2005 to a pre-tax non-cash impairment charge of $87.9 million related to2006. See the loss of a reversionary interest in the Kurten field. Effective February 13, 2003, the Kurten partnership commenced liquidation at the limited partner’s election. In connection with the liquidation, an appraisal was obtained to allocate the interest in the partnership assets. Based on the receipt of the appraisal in February 2003, we would not receive the reversionary interest as part of the liquidation. Due to the impact of the loss of the reversionary interest on future estimated net cash flows of the Kurten field we performed an impairment review which resulted in an $87.9 million charge.preceding table labeled “Brokered Natural Gas Revenue and Cost” for further analysis.
Interest Expense, Net
Interest expense, net decreased $2.4 million. This variance isby $3.4 million due to the combination of a lower average level of outstandingborrowings on our 7.19% fixed rate debt and increased interest on the revolving credit facilityour short term investments as well as a declinethe 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 rates.
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 $7.4by $101.5 million due to a comparable increase in our pre-tax net income.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.
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| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
OilDerivative Instruments and gas prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business.Hedging Activity
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 natural gas prices may materially adversely affect 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.
Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include:
These factors make it impossible to predict with any certainty the future prices of oil and gas.
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 may expose us to risk of financial loss and limit the benefit to us of increases in prices.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 relatedas well as Note 11 of the Notes to commodity price swapsthe Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.
Derivative Instruments and Hedging Activity
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, 2004,2007, we had 1516 cash flow hedges open: 712 natural gas price collar arrangements, three natural gas swap arrangements and one crude oil price collar arrangement and 7 natural gas price swap arrangements. Additionally, we had two crude oil financial instruments open at December 31, 2004, that did not qualify for hedge accounting under SFAS 133.arrangement. At December 31, 2004,2007, a $28.8$7.3 million ($17.84.6 million, net of tax) unrealized lossgain was recorded toin Accumulated Other Comprehensive Income, along with a $38.4$12.7 million short-term derivative liabilityreceivable and a $2.9$5.4 million short-term derivative receivable.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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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,Revenue, as appropriate.
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The following table summarizes the realized During 2007 and unrealized impact of derivative activity reflected2006, there was no ineffectiveness recorded in the respective line itemConsolidated 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 Operating Revenues.
| Year Ended December 31, | ||||||||||||||||||||||||
| 2004 | 2003 | 2002 | ||||||||||||||||||||||
| (In thousands) | Realized | Unrealized | Realized | Unrealized | Realized | Unrealized | ||||||||||||||||||
Operating Revenues -Increase / (Decrease) to Revenue | ||||||||||||||||||||||||
Natural Gas Production | $ | (55,008 | ) | $ | 914 | $ | (48,829 | ) | $ | (1,468 | ) | $ | (574 | ) | $ | (1,683 | ) | |||||||
Crude Oil | (17,908 | ) | (2,917 | ) | (3,963 | ) | (1,879 | ) | (5,202 | ) | (693 | ) | ||||||||||||
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, 20042007 we would expect to reclassify to earnings,the Consolidated Statement of Operations, over the next 12 months, $17.8$4.6 million in after-tax expendituresincome associated with commodity derivatives.hedges. This reclassification represents the net liabilityshort-term receivable associated with open positions currently not reflected in earnings at December 31, 20042007 related to anticipated 20052008 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 derivativescash flow hedges are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas andor crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. Under our Revolving Credit Agreement, the aggregate level of commodity hedging mustDuring 2007, we did not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. During 2004,enter into any natural gas price swaps covered 29,617 Mmcf, or 41% ofcovering our gas production, fixing the sales price of this gas at an average of $5.04 per Mcf.
2007 production.
At December 31, 2004,2007, we had open natural gas price swap contracts covering 2005a portion of our 2008 production as follows:
| Natural Gas Price Swaps | |||||||||
Contract Period | Volume in Mmcf | Weighted Average Contract Price | Unrealized Gain /(Loss) (In thousands) | ||||||
As of December 31, 2004 | |||||||||
Natural Gas Price Swaps on Production in: | |||||||||
First Quarter 2005 | 5,069 | $ | 5.14 | ||||||
Second Quarter 2005 | 5,125 | 5.14 | |||||||
Third Quarter 2005 | 5,181 | 5.14 | |||||||
Fourth Quarter 2005 | 5,181 | 5.14 | |||||||
Full Year 2005 | 20,556 | $ | 5.14 | $ | (27,897 | ) | |||
From time to time we enter into natural gas and crude oil derivative arrangements that do not qualify for hedge accounting under SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At December 31, 2004, we had two open crude oil swap arrangements with an unrealized net loss of $5.5 million recognized in Operating Revenues.
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| Natural Gas Price Swaps | ||||||||
Contract Period | Volume in Mmcf | Weighted-Average Contract Price (per Mcf) | Net Unrealized Gain (In thousands) | |||||
As of December 31, 2007 | ||||||||
First Quarter 2008 | 1,233 | $ | 7.44 | |||||
Second Quarter 2008 | 1,233 | 7.44 | ||||||
Third Quarter 2008 | 1,246 | 7.44 | ||||||
Fourth Quarter 2008 | 1,246 | 7.44 | ||||||
Full Year 2008 | 4,958 | $ | 7.44 | $ | 472 | |||
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 2004,2007, natural gas price collars covered 22,95442,533 Mmcf of our gas production, or 32%53%, of our gas production, with a weighted averageweighted-average floor of $4.78$8.99 per Mcf and a weighted averageweighted-average ceiling of $6.06$12.19 per Mcf.
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At December 31, 2004,2007, we had open natural gas price collar contracts covering a portion of our 20052008 production as follows:
| Natural Gas Price Collars | |||||||||
Contract Period | Volume in Mmcf | Weighted Average Ceiling /Floor | Unrealized Gain / (Loss) (In thousands) | ||||||
As of December 31, 2004 | |||||||||
First Quarter 2005 | 4,982 | $ | 9.09 / $6.16 | ||||||
Second Quarter 2005 | 3,367 | 8.38 / 5.30 | |||||||
Third Quarter 2005 | 3,404 | 8.38 / 5.30 | |||||||
Fourth Quarter 2005 | 3,404 | 8.38 / 5.30 | |||||||
Full Year 2005 | 15,157 | $ | 8.61 / $5.59 | $(2,500 | ) | ||||
| Natural Gas Price Collars | ||||||||
Contract Period | Volume in Mmcf | Weighted-Average Ceiling / Floor (per Mcf) | Net Unrealized Gain (In thousands) | |||||
As of December 31, 2007 | ||||||||
First Quarter 2008 | 8,523 | $ | 10.14 / $8.17 | |||||
Second Quarter 2008 | 8,523 | 10.14 / 8.17 | ||||||
Third Quarter 2008 | 8,617 | 10.14 / 8.17 | ||||||
Fourth Quarter 2008 | 8,617 | 10.14 / 8.17 | ||||||
Full Year 2008 | 34,280 | $ | 10.14 / $8.17 | $ | 12,072 | |||
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During 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, 2004,2007, we had one open crude oil price collar contract covering a portion of our 20052008 production as follows:
| Crude Oil Price Collar | ||||||||
Contract Period | Volume in Mbbl | Weighted Average Ceiling /Floor | Unrealized Gain /(Loss) (In thousands) | |||||
As of December 31, 2004 | ||||||||
First Quarter 2005 | 90 | $ | 50.50 / $40.00 | |||||
Second Quarter 2005 | 91 | 50.50 / 40.00 | ||||||
Third Quarter 2005 | 92 | 50.50 / 40.00 | ||||||
Fourth Quarter 2005 | 92 | 50.50 / 40.00 | ||||||
Full Year 2005 | 365 | $ | 50.50 / $40.00 | $ | 454 | |||
| Crude Oil Price Collars | |||||||||
Contract Period | Volume in Mbbl | Ceiling / Floor (per Bbl) | Net Unrealized Loss (In thousands) | ||||||
As of December 31, 2007 | |||||||||
First Quarter 2008 | 91 | $ | 80.00 / $60.00 | ||||||
Second Quarter 2008 | 91 | 80.00 / 60.00 | |||||||
Third Quarter 2008 | 92 | 80.00 / 60.00 | |||||||
Fourth Quarter 2008 | 92 | 80.00 / 60.00 | |||||||
Full Year 2008 | 366 | $ | 80.00 / $60.00 | $ | (5,272 | ) | |||
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 on page 36.“Forward-Looking Information” for further details.
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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. The Company usesWe 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
| December 31, 2004 | December 31, 2003 | December 31, 2007 | December 31, 2006 | |||||||||||||||||||||||||
(In thousands) | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||||||||||||||
Debt | ||||||||||||||||||||||||||||
Long-Term Debt | ||||||||||||||||||||||||||||
7.19% Notes | $ | 80,000 | $ | 87,770 | $ | 100,000 | $ | 113,673 | $ | 40,000 | $ | 41,376 | $ | 60,000 | $ | 61,749 | ||||||||||||
7.26% Notes | 75,000 | 85,849 | 75,000 | 87,345 | 75,000 | 80,066 | 75,000 | 80,335 | ||||||||||||||||||||
7.36% Notes | 75,000 | 87,111 | 75,000 | 87,770 | 75,000 | 81,259 | 75,000 | 82,025 | ||||||||||||||||||||
7.46% Notes | 20,000 | 23,804 | 20,000 | 24,214 | 20,000 | 21,799 | 20,000 | 22,547 | ||||||||||||||||||||
Credit Facility | — | — | — | — | 140,000 | 140,000 | 10,000 | 10,000 | ||||||||||||||||||||
Current Maturities | ||||||||||||||||||||||||||||
7.19% Notes | (20,000 | ) | (20,466 | ) | (20,000 | ) | (20,299 | ) | ||||||||||||||||||||
Long-Term Debt, excluding Current Maturities | $ | 330,000 | $ | 344,034 | $ | 220,000 | $ | 236,357 | ||||||||||||||||||||
| $ | 250,000 | $ | 284,534 | $ | 270,000 | $ | 313,002 | |||||||||||||||||||||
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| Page | ||
Consolidated Balance Sheet at December 31, | ||
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Cabot Oil & Gas Corporation:
We have completed an integrated audit of Cabot Oil & Gas Corporation’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”) at December 31, 20042007 and 2003,2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20042007 in conformity with accounting principles generally accepted in the United States of America. TheseAlso in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, are the responsibilityfor maintaining effective internal control over financial reporting and for its assessment of the Company’s management.effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express an opinionopinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the auditaudits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An auditmisstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements includesincluded examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinion.
opinions.
As discussed in Note 126 to the consolidated financial statements, effective January 1, 2007, the Company adopted FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” As discussed in Note 5 to the consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting158 “Employers’ Accounting for Asset Retirement Obligations”Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).” As discussed in Notes 1 and 10 to the consolidated financial statements, effective January 1, 2003.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that2006, the Company maintained effective internal control over financial reporting asadopted Statement of December 31, 2004 based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”)Financial Accounting Standards No. 123(R), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established inInternal Control – Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States)“Share Based Payment (revised 2004). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.”
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A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 2, 2005
February 27, 2008
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CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share amounts)
| YEAR ENDED DECEMBER 31, | |||||||||||
| 2004 | 2003 | 2002 | |||||||||
OPERATING REVENUES | |||||||||||
Natural Gas Production | $ | 379,661 | $ | 322,556 | $ | 221,101 | |||||
Brokered Natural Gas | 84,416 | 95,816 | 58,729 | ||||||||
Crude Oil and Condensate | 60,022 | 81,040 | 67,548 | ||||||||
Other | 6,309 | 9,979 | 6,378 | ||||||||
| 530,408 | 509,391 | 353,756 | |||||||||
OPERATING EXPENSES | |||||||||||
Brokered Natural Gas Cost | 75,217 | 86,162 | 53,007 | ||||||||
Direct Operations - Field and Pipeline | 53,581 | 50,399 | 50,047 | ||||||||
Exploration | 48,130 | 58,119 | 40,167 | ||||||||
Depreciation, Depletion and Amortization | 103,343 | 94,903 | 96,512 | ||||||||
Impairment of Unproved Properties | 10,145 | 9,348 | 9,348 | ||||||||
Impairment of Oil & Gas Properties (Note 2) | 3,458 | 93,796 | 2,720 | ||||||||
General and Administrative | 34,735 | 25,112 | 28,377 | ||||||||
Taxes Other Than Income | 41,022 | 37,138 | 24,734 | ||||||||
| 369,631 | 454,977 | 304,912 | |||||||||
Gain (Loss) on Sale of Assets | (124 | ) | 12,173 | 244 | |||||||
INCOME FROM OPERATIONS | 160,653 | 66,587 | 49,088 | ||||||||
Interest Expense and Other | 22,029 | 23,545 | 25,311 | ||||||||
Income Before Income Taxes and Cumulative Effect of Accounting Change | 138,624 | 43,042 | 23,777 | ||||||||
Income Tax Expense | 50,246 | 15,063 | 7,674 | ||||||||
INCOME BEFORE CUMULATIVE | 88,378 | 27,979 | 16,103 | ||||||||
CUMULATIVE EFFECT OF | — | (6,847 | ) | — | |||||||
NET INCOME | $ | 88,378 | $ | 21,132 | $ | 16,103 | |||||
Basic Earnings Per Share - Before Accounting Change | $ | 2.72 | $ | 0.87 | $ | 0.51 | |||||
Diluted Earnings Per Share - Before Accounting Change | $ | 2.69 | $ | 0.87 | $ | 0.50 | |||||
Basic Loss Per Share - Accounting Change | $ | — | $ | (0.21 | ) | $ | — | ||||
Diluted Loss Per Share - Accounting Change | $ | — | $ | (0.21 | ) | $ | — | ||||
Basic Earnings Per Share | $ | 2.72 | $ | 0.66 | $ | 0.51 | |||||
Diluted Earnings Per Share | $ | 2.69 | $ | 0.65 | $ | 0.50 | |||||
Average Common Shares Outstanding | 32,488 | 32,050 | 31,737 | ||||||||
Diluted Common Shares (Note 14) | 32,893 | 32,290 | 32,076 | ||||||||
| Year Ended December 31, | |||||||||
(In thousands, except per share amounts) | 2007 | 2006 | 2005 | ||||||
OPERATING REVENUES | |||||||||
Natural Gas Production | $ | 581,640 | $ | 568,097 | $ | 499,177 | |||
Brokered Natural Gas | 93,215 | 93,651 | 98,605 | ||||||
Crude Oil and Condensate | 55,243 | 91,380 | 82,348 | ||||||
Other | 2,072 | 8,860 | 2,667 | ||||||
| 732,170 | 761,988 | 682,797 | |||||||
OPERATING EXPENSES | |||||||||
Brokered Natural Gas Cost | 81,819 | 83,375 | 87,183 | ||||||
Direct Operations - Field and Pipeline | 77,170 | 74,790 | 61,750 | ||||||
Exploration | 39,772 | 49,397 | 61,840 | ||||||
Depreciation, Depletion and Amortization | 143,951 | 128,975 | 108,458 | ||||||
Impairment of Unproved Properties | 19,042 | 11,117 | 12,966 | ||||||
Impairment of Oil & Gas Properties (Note 2) | 4,614 | 3,886 | — | ||||||
General and Administrative | 50,775 | 58,168 | 37,650 | ||||||
Taxes Other Than Income | 53,782 | 55,351 | 54,293 | ||||||
| 470,925 | 465,059 | 424,140 | |||||||
Gain on Sale of Assets | 13,448 | 232,017 | 74 | ||||||
INCOME FROM OPERATIONS | 274,693 | 528,946 | 258,731 | ||||||
Interest Expense and Other | 17,161 | 18,441 | 22,497 | ||||||
Income Before Income Taxes | 257,532 | 510,505 | 236,234 | ||||||
Income Tax Expense | 90,109 | 189,330 | 87,789 | ||||||
NET INCOME | $ | 167,423 | $ | 321,175 | $ | 148,445 | |||
Basic Earnings Per Share | $ | 1.73 | $ | 3.32 | $ | 1.52 | |||
Diluted Earnings Per Share | $ | 1.71 | $ | 3.26 | $ | 1.49 | |||
Weighted Average Common Shares Outstanding | 96,978 | 96,803 | 97,713 | ||||||
Diluted Common Shares (Note 13) | 98,130 | 98,601 | 99,451 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEET
(In thousands, except share amounts)
| December 31, | ||||||||
| 2004 | 2003 | |||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and Cash Equivalents | $ | 10,026 | $ | 724 | ||||
Accounts Receivable | 125,754 | 87,425 | ||||||
Inventories | 24,049 | 18,241 | ||||||
Deferred Income Taxes | 21,345 | 21,935 | ||||||
Other | 13,505 | 15,006 | ||||||
Total Current Assets | 194,679 | 143,331 | ||||||
Properties and Equipment, Net (Successful Efforts Method) | 994,081 | 895,955 | ||||||
Deferred Income Taxes | 14,855 | 8,920 | ||||||
Other Assets | 7,341 | 6,850 | ||||||
| $ | 1,210,956 | $ | 1,055,056 | |||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts Payable | $ | 104,969 | $ | 84,943 | ||||
Current Portion of Long-Term Debt | 20,000 | — | ||||||
Deferred Income Taxes | 944 | 1,826 | ||||||
Accrued Liabilities | 70,976 | 69,758 | ||||||
Total Current Liabilities | 196,889 | 156,527 | ||||||
Long-Term Debt | 250,000 | 270,000 | ||||||
Deferred Income Taxes | 247,376 | 208,955 | ||||||
Other Liabilities | 61,029 | 54,377 | ||||||
Commitments and Contingencies (Note 8) | ||||||||
Stockholders’ Equity | ||||||||
Common Stock: | ||||||||
Authorized — 80,000,000 Shares of $.10 Par Value Issued and Outstanding — 33,120,610 Shares and 32,538,255 Shares in 2004 and 2003, Respectively | 3,312 | 3,254 | ||||||
Additional Paid-in Capital | 381,781 | 361,699 | ||||||
Retained Earnings | 110,935 | 27,763 | ||||||
Accumulated Other Comprehensive Loss | (20,351 | ) | (23,135 | ) | ||||
Less Treasury Stock, at Cost: | ||||||||
707,700 and 302,600 Shares in 2004 and 2003, Respectively | (20,015 | ) | (4,384 | ) | ||||
Total Stockholders’ Equity | 455,662 | 365,197 | ||||||
| $ | 1,210,956 | $ | 1,055,056 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
- 53 -
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2004 | 2003 | 2002 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
Net Income | $ | 88,378 | $ | 21,132 | $ | 16,103 | ||||||
Adjustments to Reconcile Net Income to Cash | ||||||||||||
Provided by Operating Activities: | ||||||||||||
Cumulative Effect of Accounting Change | — | 6,847 | — | |||||||||
Depletion, Depreciation and Amortization | 103,343 | 94,903 | 96,512 | |||||||||
Impairment of Unproved Properties | 10,145 | 9,348 | 9,348 | |||||||||
Impairment of Long-Lived Assets | 3,458 | 93,796 | 2,720 | |||||||||
Deferred Income Tax Expense | 31,769 | (9,837 | ) | 7,882 | ||||||||
(Gain) / Loss on Sale of Assets | 124 | (12,173 | ) | (244 | ) | |||||||
Exploration Expense | 48,130 | 58,119 | 40,167 | |||||||||
Change in Derivative Fair Value | 2,003 | 3,347 | 2,376 | |||||||||
Performance Share Compensation | 3,429 | — | — | |||||||||
Other | 3,475 | 885 | 3,888 | |||||||||
Changes in Assets and Liabilities: | ||||||||||||
Accounts Receivable | (39,404 | ) | (17,397 | ) | (19,317 | ) | ||||||
Inventories | (5,808 | ) | (2,989 | ) | 2,308 | |||||||
Other Current Assets | 3,255 | (9,208 | ) | 3,976 | ||||||||
Other Assets | (491 | ) | 163 | (4,307 | ) | |||||||
Accounts Payable and Accrued Liabilities | 17,231 | 7,041 | 7,342 | |||||||||
Other Liabilities | 3,985 | (2,339 | ) | (4,572 | ) | |||||||
Net Cash Provided by Operating Activities | 273,022 | 241,638 | 164,182 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
Capital Expenditures | (207,346 | ) | (122,018 | ) | (103,189 | ) | ||||||
Proceeds from Sale of Assets | 119 | 28,281 | 4,688 | |||||||||
Exploration Expense | (48,130 | ) | (58,119 | ) | (40,167 | ) | ||||||
Net Cash Used by Investing Activities | (255,357 | ) | (151,856 | ) | (138,668 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
Increase in Debt | 187,000 | 248,655 | 180,000 | |||||||||
Decrease in Debt | (187,000 | ) | (341,000 | ) | (205,746 | ) | ||||||
Sale of Common Stock Proceeds | 12,474 | 6,728 | 3,461 | |||||||||
Purchase of Treasury Stock | (15,631 | ) | — | — | ||||||||
Dividends Paid | (5,206 | ) | (5,043 | ) | (5,079 | ) | ||||||
Net Cash Used by Financing Activities | (8,363 | ) | (90,660 | ) | (27,364 | ) | ||||||
Net Increase (Decrease) in Cash and Cash Equivalents | 9,302 | (878 | ) | (1,850 | ) | |||||||
Cash and Cash Equivalents, Beginning of Period | 724 | 1,602 | 3,452 | |||||||||
Cash and Cash Equivalents, End of Period | $ | 10,026 | $ | 724 | $ | 1,602 | ||||||
| December 31, | ||||||||
(In thousands, except share amounts) | 2007 | 2006 | ||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and Cash Equivalents | $ | 18,498 | $ | 41,854 | ||||
Accounts Receivable, Net | 109,306 | 116,546 | ||||||
Income Taxes Receivable | 3,832 | 24,512 | ||||||
Inventories | 27,353 | 32,997 | ||||||
Deferred Income Taxes | 26,456 | 9,386 | ||||||
Derivative Contracts (Note 11) | 12,655 | 81,982 | ||||||
Other Current Assets | 23,313 | 8,405 | ||||||
Total Current Assets | 221,413 | 315,682 | ||||||
Properties and Equipment, Net (Successful Efforts Method) (Note 2) | 1,908,117 | 1,480,201 | ||||||
Deferred Income Taxes | 47,847 | 30,912 | ||||||
Other Assets | 31,217 | 7,696 | ||||||
| $ | 2,208,594 | $ | 1,834,491 | |||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts Payable | $ | 173,497 | $ | 147,680 | ||||
Current Portion of Long-Term Debt | 20,000 | 20,000 | ||||||
Deferred Income Taxes | 3,930 | 31,962 | ||||||
Income Taxes Payable | 1,391 | 9,282 | ||||||
Derivative Contracts (Note 11) | 5,383 | 16 | ||||||
Accrued Liabilities | 48,065 | 42,087 | ||||||
Total Current Liabilities | 252,266 | 251,027 | ||||||
Long-Term Liability for Pension Benefits (Note 5) | 6,743 | 7,219 | ||||||
Long-Term Liability for Postretirement Benefits (Note 5) | 20,204 | 18,204 | ||||||
Long-Term Debt (Note 4) | 330,000 | 220,000 | ||||||
Deferred Income Taxes | 481,770 | 347,430 | ||||||
Other Liabilities | 47,354 | 45,413 | ||||||
Commitments and Contingencies (Note 7) | ||||||||
Stockholders’ Equity | ||||||||
Common Stock: | ||||||||
Authorized — 120,000,000 Shares of $0.10 Par Value | ||||||||
Issued and Outstanding — 102,681,468 Shares and | ||||||||
101,418,220 Shares in 2007 and 2006, respectively | 10,268 | 10,142 | ||||||
Additional Paid-in Capital | 424,229 | 417,995 | ||||||
Retained Earnings | 722,344 | 565,591 | ||||||
Accumulated Other Comprehensive Income / (Loss) (Note 14) | (894 | ) | 37,160 | |||||
Less Treasury Stock, at Cost: | ||||||||
5,204,700 Shares in both 2007 and 2006 | (85,690 | ) | (85,690 | ) | ||||
Total Stockholders’ Equity | 1,070,257 | 945,198 | ||||||
| $ | 2,208,594 | $ | 1,834,491 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
- 5465 -
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITYCASH FLOWS
(In thousands) | Common Shares | Stock Par | Treasury Shares | Treasury Stock | Paid-In Capital | Accumulated (Loss) | Retained Earnings | Total | ||||||||||||||||||
Balance at December 31, 2001 | 31,905 | $ | 3,191 | 303 | $ | (4,384 | ) | $ | 346,260 | $ | 835 | $ | 650 | $ | 346,552 | |||||||||||
Net Income | 16,103 | 16,103 | ||||||||||||||||||||||||
Exercise of Stock Options | 209 | 20 | 3,845 | 3,865 | ||||||||||||||||||||||
Cash Dividends at $0.16 per Share | (5,079 | ) | (5,079 | ) | ||||||||||||||||||||||
Other Comprehensive Loss | (13,774 | ) | (13,774 | ) | ||||||||||||||||||||||
Stock Grant Vesting | 19 | 2 | 2,988 | 2,990 | ||||||||||||||||||||||
Balance at December 31, 2002 | 32,133 | $ | 3,213 | 303 | $ | (4,384 | ) | $ | 353,093 | $ | (12,939 | ) | $ | 11,674 | $ | 350,657 | ||||||||||
Net Income | 21,132 | 21,132 | ||||||||||||||||||||||||
Exercise of Stock Options | 345 | 35 | 7,733 | 7,768 | ||||||||||||||||||||||
Cash Dividends at $0.16 per Share | (5,043 | ) | (5,043 | ) | ||||||||||||||||||||||
Other Comprehensive Loss | (10,196 | ) | (10,196 | ) | ||||||||||||||||||||||
Stock Grant Vesting | 60 | 6 | 873 | 879 | ||||||||||||||||||||||
Balance at December 31, 2003 | 32,538 | $ | 3,254 | 303 | $ | (4,384 | ) | $ | 361,699 | $ | (23,135 | ) | $ | 27,763 | $ | 365,197 | ||||||||||
Net Income | 88,378 | 88,378 | ||||||||||||||||||||||||
Exercise of Stock Options | 529 | 53 | 15,060 | 15,113 | ||||||||||||||||||||||
Purchase of Treasury Stock | 405 | (15,631 | ) | (15,631 | ) | |||||||||||||||||||||
Performance Share Awards | 2,394 | 2,394 | ||||||||||||||||||||||||
Stock Grant Vesting | 54 | 5 | 2,628 | 2,633 | ||||||||||||||||||||||
Cash Dividends at $0.16 per Share | (5,206 | ) | (5,206 | ) | ||||||||||||||||||||||
Other Comprehensive Income | 2,784 | 2,784 | ||||||||||||||||||||||||
Balance at December 31, 2004 | 33,121 | $ | 3,312 | 708 | $ | (20,015 | ) | $ | 381,781 | $ | (20,351 | ) | $ | 110,935 | $ | 455,662 | ||||||||||
| Year Ended December 31, | ||||||||||||
(In thousands) | 2007 | 2006 | 2005 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
Net Income | $ | 167,423 | $ | 321,175 | $ | 148,445 | ||||||
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: | ||||||||||||
Depreciation, Depletion and Amortization | 143,951 | 128,975 | 108,458 | |||||||||
Impairment of Unproved Properties | 19,042 | 11,117 | 12,966 | |||||||||
Impairment of Oil & Gas Properties | 4,614 | 3,886 | — | |||||||||
Deferred Income Tax Expense | 95,152 | 52,011 | 39,628 | |||||||||
Gain on Sale of Assets | (13,448 | ) | (232,017 | ) | (74 | ) | ||||||
Exploration Expense | 39,772 | 49,397 | 61,840 | |||||||||
Unrealized Gain on Derivatives | — | — | (6,626 | ) | ||||||||
Stock-Based Compensation Expense and Other | 16,241 | 21,271 | 9,803 | |||||||||
Changes in Assets and Liabilities: | ||||||||||||
Accounts Receivable, Net | 6,854 | 39,463 | (43,938 | ) | ||||||||
Income Taxes Receivable | 14,456 | (11,198 | ) | 1,444 | ||||||||
Inventories | 5,644 | (8,381 | ) | (567 | ) | |||||||
Other Current Assets | (14,908 | ) | 1,007 | 1,188 | ||||||||
Other Assets | (29,795 | ) | (733 | ) | (192 | ) | ||||||
Accounts Payable and Accrued Liabilities | 1,052 | (29,694 | ) | 26,147 | ||||||||
Income Taxes Payable | (1,281 | ) | 18,398 | 3,656 | ||||||||
Other Liabilities | 7,368 | 1,912 | 2,382 | |||||||||
Stock-Based Compensation Tax Benefit | — | (9,485 | ) | — | ||||||||
Net Cash Provided by Operating Activities | 462,137 | 357,104 | 364,560 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
Capital Expenditures | (557,211 | ) | (467,430 | ) | (351,306 | ) | ||||||
Proceeds from Sale of Assets | 7,061 | 329,474 | 996 | |||||||||
Exploration Expense | (39,772 | ) | (49,397 | ) | (61,840 | ) | ||||||
Net Cash Used in Investing Activities | (589,922 | ) | (187,353 | ) | (412,150 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
Increase in Debt | 175,000 | 205,000 | 265,000 | |||||||||
Decrease in Debt | (65,000 | ) | (305,000 | ) | (195,000 | ) | ||||||
Sale of Common Stock Proceeds | 5,099 | 6,235 | 4,586 | |||||||||
Stock-Based Compensation Tax Benefit | — | 9,485 | — | |||||||||
Purchase of Treasury Stock | — | (46,492 | ) | (19,183 | ) | |||||||
Dividends Paid | (10,670 | ) | (7,751 | ) | (7,213 | ) | ||||||
Net Cash Provided by / (Used in) Financing Activities | 104,429 | (138,523 | ) | 48,190 | ||||||||
Net (Decrease) / Increase in Cash and Cash Equivalents | (23,356 | ) | 31,228 | 600 | ||||||||
Cash and Cash Equivalents, Beginning of Period | 41,854 | 10,626 | 10,026 | |||||||||
Cash and Cash Equivalents, End of Period | $ | 18,498 | $ | 41,854 | $ | 10,626 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
- 5566 -
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOMESTOCKHOLDERS’ EQUITY
| Year Ended December 31, | ||||||||||||
(In thousands) | 2004 | 2003 | 2002 | |||||||||
Net Income | $ | 88,378 | $ | 21,132 | $ | 16,103 | ||||||
Other Comprehensive Income (Loss) | ||||||||||||
Reclassification Adjustment for Settled Contracts | 53,516 | 47,926 | 6,230 | |||||||||
Changes in Fair Value of Hedge Positions | (48,494 | ) | (63,014 | ) | (26,361 | ) | ||||||
Adjustment to Recognize Minimum Pension Liability | (1,404 | ) | (1,333 | ) | (2,177 | ) | ||||||
Foreign Currency Translation Adjustment | 662 | (5 | ) | — | ||||||||
Deferred Income Tax | (1,496 | ) | 6,230 | 8,534 | ||||||||
Total Other Comprehensive Income (Loss) | 2,784 | (10,196 | ) | (13,774 | ) | |||||||
Comprehensive Income | $ | 91,162 | $ | 10,936 | $ | 2,329 | ||||||
(In thousands, except per share amounts) | Common Shares | Stock Par | Treaury Shares | Treasury Stock | Paid-In Capital | Accumulated Other Comprehensive Income / (Loss) (1) | Retained Earnings | Total | |||||||||||||||||||
Balance at December 31, 2004 | 99,362 | $ | 9,936 | 2,124 | $ | (20,015 | ) | $ | 375,157 | $ | (20,351 | ) | $ | 110,935 | $ | 455,662 | |||||||||||
Net Income | 148,445 | 148,445 | |||||||||||||||||||||||||
Exercise of Stock Options | 600 | 60 | 4,525 | 4,585 | |||||||||||||||||||||||
Purchase of Treasury Stock | 904 | (19,183 | ) | (19,183 | ) | ||||||||||||||||||||||
Tax Benefit of Stock-Based Compensation | 3,662 | 3,662 | |||||||||||||||||||||||||
Stock Amortization and Vesting | 202 | 20 | 8,997 | 9,017 | |||||||||||||||||||||||
Cash Dividends at $0.074 per Share | (7,213 | ) | (7,213 | ) | |||||||||||||||||||||||
Other Comprehensive Income | 5,236 | 5,236 | |||||||||||||||||||||||||
Balance at December 31, 2005 | 100,164 | $ | 10,016 | 3,028 | $ | (39,198 | ) | $ | 392,341 | $ | (15,115 | ) | $ | 252,167 | $ | 600,211 | |||||||||||
Net Income | 321,175 | 321,175 | |||||||||||||||||||||||||
Exercise of Stock Options | 876 | 88 | 6,127 | 6,215 | |||||||||||||||||||||||
Purchase of Treasury Stock | 2,177 | (46,492 | ) | (46,492 | ) | ||||||||||||||||||||||
Tax Benefit of Stock-Based Compensation | 9,485 | 9,485 | |||||||||||||||||||||||||
Stock Amortization and Vesting | 378 | 38 | 10,042 | 10,080 | |||||||||||||||||||||||
Cash Dividends at $0.08 per Share | (7,751 | ) | (7,751 | ) | |||||||||||||||||||||||
Effect of Adoption of SFAS No. 158 | (14,079 | ) | (14,079 | ) | |||||||||||||||||||||||
Other Comprehensive Income | 66,354 | 66,354 | |||||||||||||||||||||||||
Balance at December 31, 2006 | 101,418 | $ | 10,142 | 5,205 | $ | (85,690 | ) | $ | 417,995 | $ | 37,160 | $ | 565,591 | $ | 945,198 | ||||||||||||
Net Income | 167,423 | 167,423 | |||||||||||||||||||||||||
Exercise of Stock Options | 619 | 62 | 5,005 | 5,067 | |||||||||||||||||||||||
Stock Amortization and Vesting | 644 | 64 | 7,503 | 7,567 | |||||||||||||||||||||||
Stock Held in Rabbi Trust | (6,274 | ) | (6,274 | ) | |||||||||||||||||||||||
Cash Dividends at $0.11 per Share | (10,670 | ) | (10,670 | ) | |||||||||||||||||||||||
Other Comprehensive Income | (38,054 | ) | (38,054 | ) | |||||||||||||||||||||||
Balance at December 31, 2007 | 102,681 | $ | 10,268 | 5,205 | $ | (85,690 | ) | $ | 424,229 | $ | (894 | ) | $ | 722,344 | $ | 1,070,257 | |||||||||||
(1) | For further details on the components of Accumulated Other Comprehensive Income and Loss, refer to Note 14 of the Notes to the Consolidated Financial Statements. |
The accompanying notes are an integral part of these consolidated financial statements.
- 5667 -
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
| Year Ended December 31, | ||||||||||||||||
(In thousands) | 2007 | 2006 | 2005 | |||||||||||||
Net Income | $ | 167,423 | $ | 321,175 | $ | 148,445 | ||||||||||
Other Comprehensive Income / (Loss), net of taxes | ||||||||||||||||
Reclassification Adjustment for Settled Contracts, net of taxes of $29,801, $10,686 and $(38,404), respectively | (49,241 | ) | (17,580 | ) | 62,249 | |||||||||||
Changes in Fair Value of Hedge Positions, net of taxes of $(1,777), $(49,311) and $35,293, respectively | 2,555 | 81,679 | (57,266 | ) | ||||||||||||
Defined Benefit Pension and Postretirement Plans: | ||||||||||||||||
Net Loss Arising During the Year, net of taxes of $1,034 | $ | (1,733 | ) | |||||||||||||
Amortization of Net Obligation at Transition, net of taxes of $(238) | 394 | |||||||||||||||
Amortization of Prior Service Cost, net of taxes of $(413) | 681 | |||||||||||||||
Amortization of Net Loss, net of taxes of $(483) | 799 | |||||||||||||||
Total Defined Benefit Pension and Postretirement Plans, net of taxes of $(100), $(1,848) and $77, respectively | 141 | 3,081 | (128 | ) | ||||||||||||
Foreign Currency Translation Adjustment, net of taxes of $(5,072), $507 and $(427), respectively | 8,491 | (826 | ) | 381 | ||||||||||||
Total Other Comprehensive Income / (Loss) | (38,054 | ) | 66,354 | 5,236 | ||||||||||||
Comprehensive Income | $ | 129,369 | $ | 387,529 | $ | 153,681 | ||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
- 68 -
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
| 1. | Summary of Significant Accounting Policies |
Basis of Presentation and Nature of Operations
Cabot Oil & Gas Corporation and its subsidiaries are engaged in the development, exploitation, exploration, development, production and marketing of natural gas and, to a lesser extent, crude oil and natural gas liquids. The Company also transports, stores, gathers and purchases natural gas for resale. The Company operates in one segment, natural gas and oil explorationdevelopment, exploitation and exploitation almostexploration, exclusively within the continental United States and Canada.
The Company’s exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. The Company’s program is designed to be disciplined and balanced with a focus on achieving strong financial returns.
The consolidated financial statements contain the accounts of the Company and its majority-owned subsidiaries after eliminating all significant intercompany balances and transactions. Certain prior year amounts have been reclassified to conform to the current year presentation.
On February 23, 2007, the Board of Directors declared a 2-for-1 split of the Company’s 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 have been retroactively adjusted to give effect to the 2-for-1 split of the Company’s common stock. The effect on the December 31, 2006 Consolidated Balance Sheet was a reduction to Additional Paid-in Capital and an increase to Common Stock of $5.1 million.
On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s common stock in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the common stock on the record date. All common stock accounts and per share data were retroactively adjusted to give effect to the 3-for-2 split of the Company’s common stock.
Recently Issued Accounting Pronouncements
In May 2004,December 2007, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” This FSP provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) for employers that sponsor postretirement health care plans that provide prescription drug benefits. This FSP also requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Act (the subsidy). This FSP supersedes FSP 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” and is effective for the first interim period beginning after June 15, 2004. The Company’s current accumulated projected benefit obligation and net periodic postretirement benefit cost does not reflect any amount associated with the subsidy. Furthermore, in 2004, the Company amended its postretirement benefit plan to exclude prescription drug benefits for participants age 65 and older effective January 1, 2006. The adoption of this FSP is not expected to impact the Company’s operating results, financial position or cash flows.
In November 2004, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 151, “Inventory Costs -160, “Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARBAccounting Research Bulletin (ARB) No. 43, Chapter 4”51.” SFAS No. 160 clarifies that a noncontrolling interest (previously commonly referred to as a minority interest) in a subsidiary is an effortownership interest 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 uniteboth the United States accounting standards for inventories with International Accounting Standards leading to consistent application of certain accounting requirements. FAS 151 addresses accounting for abnormal amounts of freight, handling costs, idle facility expenseparent and spoilage (wasted material) and requires that these costs be recognized as current period expenses. Previously, these costs hadthe noncontrolling interest is now required to be categorizedreported separately. Previously, net income attributable to the noncontrolling interest was typically reported as “so abnormal as to require treatment as current period charges.”an expense or other deduction in arriving at consolidated net income and was often combined with other financial statement amounts. In addition, allocation of fixed production overheads to the costs of conversionownership interests in subsidiaries held by parties other than the parent must be based onclearly identified, labeled, and presented in the normal capacityequity 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 production facilities. FAS 151 will beparent 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 JuneDecember 15, 2005. The2008 and earlier adoption is prohibited. Prospective application is required. At this time, the Company does not have any material noncontrolling interests in consolidated subsidiaries. Therefore, it does not believe that the adoption of this statement is not expected toSFAS No. 160 will have a material impact the Company’s operatingon its financial position, results financial positionof operations or cash flows.
In December 2004, the FASB issued SFAS 153 “Exchanges of Nonmonetary Assets – an amendment of APB Opinion No. 29.” This statement requires that nonmonetary exchanges must be recorded at fair value and the appropriate gain or loss must be recognized so long as the fair value is determinable and the transaction has commercial substance. According to this statement, companies can no longer use the “similar productive assets” concept to account for nonmonetary exchanges at book value with no gain or loss being recognized. FAS 153 will be effective for fiscal periods beginning after June 15, 2005. The adoption of this statement may impact the Company’s operating results, financial position or cash flows in future periods if such a nonmonetary exchange occurs.
- 5769 -
In December 2004,2007, the FASB issued SFAS No. 123R, “Share-Based Payment.141(R), “Business Combinations.” SFAS 123R revisesNo. 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 123, “AccountingNo. 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 Stock-Based Compensation”,fiscal years, and focusesinterim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. The Company cannot predict the impact that the adoption of SFAS No. 141(R) will have on its financial position, results of operations or cash flows with respect to any acquisitions completed after December 31, 2007.
In May 2007, the FASB issued FASB Staff Position (FSP) No. FASB Interpretation Number (FIN) 48-1, “Definition ofSettlement 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. The Company has 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 share-based paymentsfiscal 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 services by employer to employee.all periods presented. The statement requiresCompany does not believe that the adoption of FSP No. FIN 39-1 will have a material impact on its 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 expensechoose, at specified 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 employee stock options and other equity-based compensation at the grant date. The statementfirst remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. Since the Company has not elected to adopt the fair value option for eligible items, it does not requirebelieve that SFAS No. 159 will have an impact on its financial position or results of operations.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which establishes a certain typeformal framework for measuring fair values of valuation modelassets and either a binomial or Black-Scholes model may be used. The provisions of SFAS 123R are effective forliabilities in financial statements for fiscal periods ending after June 15, 2005. The Company is currently evaluating the method of adoption and the impact on the Company’s operating results. Future cash flows of the Company will not be impactedthat are already required by the adoption of this standard. See “Stock Based Compensation” below for further information.
In February 2005, the FASB released for public comment proposed Staff Position FAS 19-a “Accounting for Suspended Well Costs.” This proposed staff position would amend FASB Statement No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The proposed position states that exploratory well costs should continueUnited States generally accepted accounting principles (GAAP) to be capitalized if: 1) a sufficient quantity of reserves are discoveredmeasured at fair value. SFAS No. 157 clarifies guidance in the well to justify its completion as a producing well and 2) sufficient progress is madeFASB Concepts Statement (CON) No. 7 which discusses present value techniques in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvagemeasuring fair value. Additional disclosures are also required for transactions measured at fair value. SFAS No.
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157 is effective for fiscal years beginning after November 15, 2007. In addition,November 2007, the Staff Position requires the disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized forFASB granted a period greater than one year deferral (to fiscal years beginning after the completionNovember 15, 2008) for non-financial assets and liabilities to comply with SFAS No. 157. The Company does not believe that SFAS No. 157 will have a material impact on its financial position or results of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. Although this Staff Position is not final and has not been adopted by the company, the company has included the additional disclosures in Note 2. Comments on this proposed FSP are expected by March 7, 2005.
operations.
Pipeline ImbalancesInventories
Inventories are comprised of natural gas and, to a lesser extent, oil in storage, tubular goods and well equipment and pipeline imbalances. All inventory balances are carried at the lower of cost or market. Natural gas and oil in storage are valued at average cost. Tubular goods and well equipment are valued at historical cost.
Natural gas gathering and pipeline operations normally include imbalance arrangements with the pipeline. The volumes of natural gas due to or from the Company under imbalance arrangements are recorded at actual selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net value of the natural gas imbalance is included in inventory in the consolidated balance sheet.
Properties and Equipment
The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells, and successful exploratory drilling costs to locate proved reserves are capitalized.
Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. A determination of whether a well has found proved reserves is made shortly after drilling is completed. The determination is based on a process which relies on interpretations of available geologic, geophysic,geophysical, and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether proved reserves have been found only as long as: i) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and ii) drilling of the additional exploratory wells is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired, and its costs are charged to expense. For a discussion of the Company’s suspended wells, see Note 2 of the Notes to the Consolidated Financial Statements.
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InThe Company determines if an impairment has occurred through either adverse changes or as a result of the absenceannual review of a determination as to whether the reserves that have been found can be classified as proved, the costs of drilling such an exploratory well is not carried as an asset for more than one year following completion of drilling. If, after that year has passed, a determination that proved reserves exist cannot be made, the well is assumed to be impaired, and its costs are charged to expense.
all fields. The impairment of unamortized capital costs is measured at a lease level and is reduced to fair value if it is determined that the sum of expected future net cash flows is less than the net book value. The Company determines if an impairment has occurred through either adverse changes or as a result of the annual review of all fields. In 2003, the Company recorded impairments related to the loss of a reversionary interest in its Kurten fieldDuring 2007 and a field in the East region. These impairments totaled $93.8 million. During 2004,2006, the Company recorded total impairments of $3.5 million.$4.6 million and $3.9 million, respectively. During 2002,2005, the Company recorded total impairments of $2.7 million.
did not record any impairments.
Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs net of estimated salvage values and acquisition costs, are depreciated and depleted on a field basis by the units-of-production method using proved developed and proved reserves, respectively. The costs of unproved oil and gas properties are generally combined and amortizedimpaired over a period that is based on the average holding period for such properties and the Company’s experience of successful drilling. Properties related to gathering and pipeline systems and
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equipment are depreciated using the straight-line method based on estimated useful lives ranging from 10 to 25 years. Generally pipeline and transmission systems are depreciated over 12 to 25 years, gathering and compression equipment is depreciated over 10 years and storage equipment and facilities are depreciated over 10 to 16 years. Certain other assets are depreciated on a straight-line basis.
basis over 3 to 10 years. Buildings are depreciated on a straight-line basis over 25 years.
Costs of retired, sold or abandoned properties that make up a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the units-of-production rate is not significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold.
See Note 2 of the Notes to the Consolidated Financial Statements for a discussion of the disposition of the Company’s 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).
Revenue Recognition and Gas Imbalances
The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. A natural gas imbalance liability is recorded at the actual price realized upon the gas sale in accounts payable in the consolidated balance sheet if the Company’s excess takes of natural gas exceed its estimated remaining proved developed reserves for these properties. See Note 3 of the Notes to the Consolidated Financial Statements for the Company’s wellhead gas imbalances.
Brokered Natural Gas Margin
The revenues and expenses related to brokering natural gas are reported gross as part of Operating Revenues and Operating Expenses. The Company realizes brokered margin as a result of buying and selling natural gas in back-to-back transactions.transactions with separate counterparties. The Company realized $9.2$11.4 million, $9.7$10.3 million and $5.7$11.4 million of brokered natural gas margin in 2004, 2003,2007, 2006 and 2002,2005, respectively.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.
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Natural Gas Measurement
The Company records estimated amounts for natural gas revenues and natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operation, measurement, and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material.
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Accounts Payable
This account may include credit balances from outstanding checks in zero balance cash accounts. TheThese credit balance included in accounts payable was $2.7 million at December 31, 2003, which is reflectedbalances are referred to as an increase in short-term borrowings in financing activities inbook overdrafts, as a component of Accounts Payable on the Consolidated Statement of Cash Flows.Balance Sheet. There waswere no credit balancebalances from outstanding checks in zero balance cash accounts included in accounts payable at December 31, 20042007 and 2006 as sufficient cash was available for offset.
Allowance for Doubtful Accounts
The Company records an allowance for doubtful accounts for receivables that the Company feels may be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against the accounts receivable line on the balance sheetConsolidated Balance Sheet, was $5.3$4.0 million and $5.4$4.6 million respectively, as ofat December 31, 20042007 and 2003.
2006, respectively.
Risk Management Activities
From time to time, the Company enters into derivative contracts, such as natural gas and crude oil price swaps or costlesszero-cost price collars, as a hedging strategy to manage commodity price risk associated with its inventories, production or other contractual commitments. All hedge transactions are subject to the Company’s risk management policy which does not permit speculative trading activities. Gains or losses on these hedging activities are generally recognized over the period that its inventories, production or other underlying commitment is hedged as an offset to the specific hedged item. Cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contract not considered a hedge would beare recognized currently in the results of operations.
When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if the hedge is no longer effective, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge. See Note 11 of the Notes to the Consolidated Financial Instruments,Statements for further discussion.
Stock Based Compensation
Effective January 1, 2006, the Company adopted the provisions of SFAS No. 123(R), “Share Based Payment (revised 2004),” which replaces the provisions of Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees” and SFAS No. 123, “Accounting for Stock-Based Compensation,” (as amended). The Company accountselected the modified prospective transition method for adoption, and accordingly, no adjustments to prior period financial statements were made. Upon adoption, the Company recorded a cumulative effect charge totaling $0.6 million ($0.4 million, net of tax), which is included within General and Administrative Expenses in the Consolidated Statement of Operations due to its immateriality. Adoption of SFAS No. 123(R) increased income from operations and income before income taxes by approximately $1.3 million and increased net income by approximately $0.8 million for the year ended December 31, 2006. In addition, the tax benefit for stock-based compensation of $9.5 million for 2006 is now included as both a cash inflow from financing activities and a cash outflow from operating activities in the Consolidated Statement of Cash Flows. For the year ended December 31, 2007, the Company did not recognize a tax benefit for stock-based compensation as a result of the tax net operating loss position for the year under the Alternative Minimum Tax system. See Note 10 of the Notes to the Consolidated Financial Statements for additional details.
Prior to January 1, 2006, the Company accounted for stock-based compensation in accordance with the intrinsic value
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based method prescribed by Accounting Principles Board OpinionAPB No. 25, “Accounting for Stock Issued to Employees.”25. Under the intrinsic value based method, no compensation cost is the excess, if any, of the quoted market price of the stock at grant date over the amount an employee must pay to acquire the stock.
SFAS 123, “Accounting for Stock-Based Compensation”, as amended by SFAS 148, “Accounting for Stock-Based Compensation – Transition and Disclosure”, outlines a fair value based method of accountingexpense was recorded for stock options granted when the exercise price for options granted was equal to or similar equity instruments.greater than the fair value of the Company’s common stock on the date of the grant. See Note 10 of the Notes to the Consolidated Financial Statements for additional disclosure.
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The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123
| Year Ended December 31, | |||||||||
(In thousands, except per share amounts) | 2004 | 2003 | 2002 | ||||||
Net Income, as reported | $ | 88,378 | $ | 21,132 | $ | 16,103 | |||
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax | 1,571 | 1,950 | 1,605 | ||||||
Pro forma net income | $ | 86,807 | $ | 19,182 | $ | 14,498 | |||
Earnings per share: | |||||||||
Basic - as reported | $ | 2.72 | $ | 0.66 | $ | 0.51 | |||
Basic - pro forma | $ | 2.67 | $ | 0.60 | $ | 0.46 | |||
Diluted - as reported | $ | 2.69 | $ | 0.65 | $ | 0.50 | |||
Diluted - pro forma | $ | 2.64 | $ | 0.59 | $ | 0.45 | |||
Share Count | 32,488 | 32,050 | 31,737 | ||||||
Diluted Share Count | 32,893 | 32,290 | 32,076 | ||||||
The fair value of stock options included in the pro forma results for each of the three years is not necessarily indicative of future effects on net income and earnings per share.
The assumptions used in the fair value method calculation as well as additional stock based compensation information are disclosed in the following table.
| Year Ended December 31, | ||||||||||||
(In thousands, except per share amounts) | 2004 | 2003 | 2002 | |||||||||
Compensation Expense in Net Income, as reported(1) | $ | 4,043 | $ | 1,001 | $ | 2,326 | ||||||
Weighted Average Value per Option Granted During the Period(2) | $ | 11.31 | $ | 6.77 | $ | 6.23 | ||||||
Assumptions: | ||||||||||||
Stock Price Volatility | 38.4 | % | 35.3 | % | 35.8 | % | ||||||
Risk Free Rate of Return | 3.3 | % | 2.5 | % | 3.9 | % | ||||||
Dividend Rate (per year) | $ | 0.16 | $ | 0.16 | $ | 0.16 | ||||||
Expected Term (in years) | 4 | 4 | 4 | |||||||||
Cash and Cash Equivalents
The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. At December 31, 2004,2007 and 2003,2006, the cash and cash equivalents are primarily concentrated in onetwo financial institution.institutions. The Company periodically assesses the financial condition of these institutions and believes that any possible credit risk is minimal. Excluded from cash and cash equivalents at December 31, 2007 is $11.6 million of restricted cash. See Note 7 of the Notes to the Consolidated Financial Statements for further details.
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Environmental Matters
Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.
Use of Estimates
In preparing financial statements, the Company follows generally accepted accounting principles. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas, natural gas liquids and crude oil reserves and related cash flow estimates used in impairment tests of oil and gas properties, natural gas, natural gas liquids and crude oil revenues and expenses, current values of derivative instruments, as well as estimates of expenses related to legal, environmental and other contingencies, depreciation, depletion and amortization, pension and postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates.
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2. Properties and Equipment
| 2. | Properties and Equipment, Net |
Properties and equipment, net are comprised of the following:
| December 31, | December 31, | |||||||||||||||
| 2004 | 2003 | |||||||||||||||
| (In thousands) | ||||||||||||||||
(In thousands) | 2007 | 2006 | ||||||||||||||
Unproved Oil and Gas Properties | $ | 94,795 | $ | 86,918 | $ | 108,868 | $ | 114,108 | ||||||||
Proved Oil and Gas Properties | 1,646,841 | 1,469,751 | 2,627,346 | 2,109,045 | ||||||||||||
Gathering and Pipeline Systems | 160,951 | 146,909 | 235,127 | 205,473 | ||||||||||||
Land, Building and Improvements | 4,860 | 4,758 | 5,094 | 4,976 | ||||||||||||
Other | 31,261 | 28,658 | 36,508 | 34,067 | ||||||||||||
| 1,938,708 | 1,736,994 | 3,012,943 | 2,467,669 | |||||||||||||
Accumulated Depreciation, Depletion and Amortization | (944,627 | ) | (841,039 | ) | (1,104,826 | ) | (987,468 | ) | ||||||||
| $ | 994,081 | $ | 895,955 | $ | 1,908,117 | $ | 1,480,201 | |||||||||
As of December 31, 2004,On January 1, 2005, the Company has included disclosures that would be required by the pending FASB Staff Position (“FSP”)adopted FSP FAS 19-a,19-1, “Accounting for Suspended Well Costs.” TheUpon adoption of the FSP, the Company evaluated all existing capitalized exploratory well costs under the provisions of the pending FSP. The provisions require that, in order for costs to be capitalized, a sufficient quantity of reserves must be discovered in the well to justify its completion as a producing well and that sufficient progress has been made in assessing the well’s economic and operating feasibility. If both of these requirements are not met, the costs should be expensed. The following table reflects the net changes in capitalized exploratory well costs during 2004, 20032007, 2006 and 2002.2005.
(In thousands)- 75 -
| December 31, | ||||||||||||
| 2004 | 2003 | 2002 | ||||||||||
Beginning balance at January 1 | $ | 13,277 | $ | 3,958 | $ | 15,548 | ||||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 49,685 | 48,865 | 26,580 | |||||||||
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves | (36,247 | ) | (12,003 | ) | (21,235 | ) | ||||||
Capitalized exploratory well costs charged to expense | (18,605 | ) | (27,543 | ) | (16,935 | ) | ||||||
Ending balance at December 31 | $ | 8,110 | $ | 13,277 | $ | 3,958 | ||||||
| December 31, | ||||||||||||
(In thousands) | 2007 | 2006 | 2005 | |||||||||
Beginning balance at January 1 | $ | 8,428 | $ | 6,132 | $ | 8,591 | ||||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 2,161 | 8,317 | 6,132 | |||||||||
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves | (8,011 | ) | (5,926 | ) | (1,069 | ) | ||||||
Capitalized exploratory well costs charged to expense | (417 | ) | (95 | ) | (7,522 | ) | ||||||
Ending balance at December 31 | $ | 2,161 | $ | 8,428 | $ | 6,132 | ||||||
At December 31, 2007 and 2005, the Company did not have any projects that had exploratory well costs that were capitalized for a period of greater than one year. At December 31, 2006, the Company had four projects that had exploratory well costs that were capitalized for a period greater than one year.
The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
(In thousands)
| December 31, | |||
| 2004 | |||
Capitalized exploratory well costs that have been capitalized for a period of one year or less | $ | 6,471 | |
Capitalized exploratory well costs that have been capitalized for a period greater than one year | — | ||
Balance at December 31 | $ | 6,471 | |
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | 0 | ||
There were no capitalized exploratory well costs at December 31, 2003 and 2002 for wells that have completed drilling without the ability to determine the existence of proved reserves.
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| December 31, | |||||||||
(In thousands) | 2007 | 2006 | 2005 | ||||||
Capitalized exploratory well costs that have been capitalized for a period of one year or less | $ | 2,161 | $ | 8,317 | $ | 6,132 | |||
Capitalized exploratory well costs that have been capitalized for a period greater than one year | — | 111 | — | ||||||
Balance at December 31 | $ | 2,161 | $ | 8,428 | $ | 6,132 | |||
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | — | 4 | — | ||||||
At December 31, 2004,2006, the Company had 3two wells that had completedwhere the drilling andwas complete, but a determination of whether proved reserves existed could not be made. Costs associated with these wells have been capitalized for less than one year. One well, located in Canada, completed drilling in September 2006. Subsequent well completion attempts were halted until mid-November 2006, waiting for acceptable weather conditions. The well was completed in the first quarter of 2007. The second well is in the Rocky MountainMountains area and reached total depth in November 2004. It cannot be completed2006. Completion attempts were postponed due to the Bureau of Land Management stipulation which prohibits activity until the summer of 2007. Subsequent completion attempts proved unsuccessful and the costs were expensed in the second quarter of 2007.
Included in the December 31, 2006 amount of exploratory well costs that have been capitalized for a period greater than one year are $0.1 million of costs that have been capitalized since 2005. Two wells areThis amount relates to three projects comprised of preliminary costs incurred in Canadathe preparation of well sites where drilling has not commenced as of December 31, 2006. In 2007, it was determined not to drill these projects and reachedassociated costs were expensed. Also included in the December 31, 2006 amount was another well that had completed drilling in OctoberJanuary 2007 and December 2004. These wells arewas awaiting completion or sidetracking which is anticipated to commence by May 2005.results before confirmation of proved reserves could be made. That well was completed in 2007 and proved reserves were recorded in the first quarter of 2007.
At December 31, 2007 and 2005, the Company had no wells that had completed drilling for more than one year where a determination of whether proved reserves existed could not be made.
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During 2004,2007, the Company recorded an impairment of $3.5approximately $4.6 million in the Castor field in Bienville Parish, Louisiana in the Gulf Coast region resulting from two non-commercial development completions. During 2006, the Company recorded an impairment of $3.9 million. The impairment was recorded on a two-well fieldmarginally productive gas well in south LouisianaColorado County, Texas in the Gulf Coast region. Both the 2007 and was due to production performance issues related to water encroachment. This2006 impairment charge wascharges were recorded due to the capitalized costcosts of the fieldfields exceeding the future undiscounted cash flows. This charge isThese charges were reflected in the quarterlyoperating results of the Company and waswere measured based on discounted cash flows utilizing a discount rate appropriate for risks associated with the related field. During 2005, the Company did not record any impairments.
Disposition of Assets
As partOn September 29, 2006, the Company substantially completed the 2006 south Louisiana and offshore properties sale to Phoenix Exploration Company LP for a gross sales price of $340.0 million. The Company received approximately $333.3 million in net proceeds from the 2001 Cody acquisition, we acquired an interest in certain oil and gas propertiessale. In addition to the net gain of $231.2 million ($144.5 million, net of tax) recorded for the year ended December 31, 2006, the Company recorded a net gain of $12.3 million ($7.7 million, net of tax) in the Kurten field, as general partnerConsolidated Statement of a partnership and as an operator. We had approximately a 25% interest inOperations for the field, including a one percent interest in the partnership. Under the partnership agreement, we had the right to a reversionary working interest that would bring our ultimate interest to 50% upon the limited partner reaching payout. Based on the additionyear ended December 31, 2007, which included cash proceeds of this reversionary interest, and because the field has over a 40-year reserve life, approximately $91$5.8 million was allocated to this field under purchase accounting at the time of the acquisition. Additionally, the limited partner had the sole option to trigger a liquidation of the partnership.
Effective February 13, 2003, liquidation of the partnership commenced at the election of the limited partner. The limited partner was a financial entity and not an industry operator. Their decision to liquidate was based upon their perception that the value of their investment in the partnership had increased due to an increase in underlying commodity prices, primarily oil, since their investment in 1999. We proceeded with the liquidation to avoid having a minority interest in a non-operated water flood field for which the new operator was not designated at the time of liquidation. In connection with the liquidation, an appraisal was required to be obtained to allocate the interest in the partnership assets. Additionally, the Company was required to test the field for recoverability in accordance with SFAS 144. Pursuant to the terms of the partnership agreement and based on the appraised value of the partnership assets it was not possible for us to obtain the reversionary interest as part of the liquidation. Due to the impact of the loss of the reversionary interest on future estimated net cash flows of the Kurten field, the limited partner’s decision and our decision to proceed with the liquidation, an impairment review was performed which required an after-tax impairment chargereceived in the first quarter of 2003 of $54.4 million. This impairment charge is reflected2007, $2.1 million in the 2003 Statement of Operations as an operating expense but did not impact our cash flows.
During 2003 the Company divested ofpurchase price adjustments and $4.4 million that had been deferred until legal title to certain non-strategic assets. These assets include properties in Pennsylvania that were sold for $16.1 million, and resulted in a gain of $6.9 million. Additionally, the Company divested of a water treatment facility in the amount of $3.4 million, which resulted in a gain of $2.5 million.
In 2002, the Company recorded impairments of $2.7 million. Included in this impairment amount were impairments on four small fields, three of which were in the Gulf Coast and one in the Rocky Mountains. For each of these fields, the capitalized cost exceeded the future undiscounted cash flows. In addition, a pipeline in the Eastern region was written down to fair market value.could be assigned.
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3. ADDITIONAL BALANCE SHEET INFORMATION
| 3. | Additional Balance Sheet Information |
Certain balance sheet amounts are comprised of the following:
December 31, 2004 | December 31, 2003 | December 31, | ||||||||||||||
| (In thousands) | ||||||||||||||||
Accounts Receivable | ||||||||||||||||
(In thousands) | 2007 | 2006 | ||||||||||||||
ACCOUNTS RECEIVABLE, NET | ||||||||||||||||
Trade Accounts | $ | 105,378 | $ | 79,439 | $ | 94,550 | $ | 102,023 | ||||||||
Joint Interest Accounts | 13,554 | 13,312 | 16,443 | 18,574 | ||||||||||||
Current Income Tax Receivable | 10,796 | — | ||||||||||||||
Other Accounts | 1,312 | 81 | 2,291 | 501 | ||||||||||||
| 131,040 | 92,832 | 113,284 | 121,098 | |||||||||||||
Allowance for Doubtful Accounts | (5,286 | ) | (5,407 | ) | (3,978 | ) | (4,552 | ) | ||||||||
| $ | 125,754 | $ | 87,425 | $ | 109,306 | $ | 116,546 | |||||||||
Other Current Assets | ||||||||||||||||
Derivative Contracts | $ | 2,906 | $ | 1,152 | ||||||||||||
INVENTORIES | ||||||||||||||||
Natural Gas and Oil in Storage | $ | 20,472 | $ | 22,717 | ||||||||||||
Tubular Goods and Well Equipment | 5,953 | 7,680 | ||||||||||||||
Pipeline Imbalances | 928 | 2,600 | ||||||||||||||
| $ | 27,353 | $ | 32,997 | |||||||||||||
OTHER CURRENT ASSETS | ||||||||||||||||
Drilling Advances | 6,180 | 6,443 | $ | 2,475 | $ | 651 | ||||||||||
Prepaid Balances | 4,173 | 4,325 | 8,900 | 7,416 | ||||||||||||
Restricted Cash | 11,600 | — | ||||||||||||||
Other Accounts | 246 | 3,086 | 338 | 338 | ||||||||||||
| $ | 13,505 | $ | 15,006 | $ | 23,313 | $ | 8,405 | |||||||||
Accounts Payable | ||||||||||||||||
OTHER ASSETS | ||||||||||||||||
Note Receivable | $ | 13,375 | $ | — | ||||||||||||
Rabbi Trust Deferred Compensation Plan | 9,744 | 6,077 | ||||||||||||||
Other Accounts | 8,098 | 1,619 | ||||||||||||||
| $ | 31,217 | $ | 7,696 | |||||||||||||
ACCOUNTS PAYABLE | ||||||||||||||||
Trade Accounts | $ | 12,808 | $ | 11,872 | $ | 27,678 | $ | 28,569 | ||||||||
Natural Gas Purchases | 8,669 | 5,751 | 6,465 | 8,356 | ||||||||||||
Royalty and Other Owners | 35,369 | 28,001 | 37,023 | 37,230 | ||||||||||||
Capital Costs | 26,203 | 21,964 | 83,754 | 59,524 | ||||||||||||
Taxes Other Than Income | 5,634 | 3,280 | 6,416 | 4,805 | ||||||||||||
Drilling Advances | 7,102 | 5,721 | 1,528 | 1,506 | ||||||||||||
Wellhead Gas Imbalances | 1,991 | 2,085 | 3,227 | 2,288 | ||||||||||||
Other Accounts | 7,193 | 6,269 | 7,406 | 5,402 | ||||||||||||
| $ | 104,969 | $ | 84,943 | $ | 173,497 | $ | 147,680 | |||||||||
Accrued Liabilities | ||||||||||||||||
ACCRUED LIABILITIES | ||||||||||||||||
Employee Benefits | $ | 10,123 | $ | 9,105 | $ | 13,699 | $ | 13,575 | ||||||||
Current Liability for Pension Benefits | 116 | 67 | ||||||||||||||
Current Liability for Postretirement Benefits | 642 | 577 | ||||||||||||||
Taxes Other Than Income | 14,191 | 13,359 | 13,216 | 15,696 | ||||||||||||
Interest Payable | 6,569 | 6,368 | 6,518 | 5,995 | ||||||||||||
Derivative Contracts | 38,368 | 36,582 | ||||||||||||||
Litigation | 11,600 | — | ||||||||||||||
Other Accounts | 1,725 | 4,344 | 2,274 | 6,193 | ||||||||||||
| $ | 70,976 | $ | 69,758 | $ | 48,065 | $ | 42,103 | |||||||||
Other Liabilities | ||||||||||||||||
Postretirement Benefits Other Than Pension | $ | 4,717 | $ | 2,132 | ||||||||||||
Accrued Pension Cost | 5,089 | 2,664 | ||||||||||||||
OTHER LIABILITIES | ||||||||||||||||
Rabbi Trust Deferred Compensation Plan | 4,199 | 3,568 | $ | 16,018 | $ | 6,077 | ||||||||||
Derivative Contracts | — | 3,051 | ||||||||||||||
Accrued Plugging and Abandonment Liability | 40,375 | 36,848 | 24,724 | 22,655 | ||||||||||||
Other | 6,649 | 6,114 | ||||||||||||||
Other Accounts | 6,612 | 16,681 | ||||||||||||||
| $ | 61,029 | $ | 54,377 | $ | 47,354 | $ | 45,413 | |||||||||
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4. Inventories
Inventories are comprised of the following:
| December 31, | |||||||
(In thousands) | 2004 | 2003 | |||||
Natural Gas and Oil in Storage | $ | 17,631 | $ | 15,191 | |||
Tubular Goods and Well Equipment | 6,387 | 3,367 | |||||
Pipeline Imbalances | 31 | (317 | ) | ||||
| $ | 24,049 | $ | 18,241 | ||||
Natural gas and oil in storage is valued at average cost. Tubular goods and well equipment is valued at historical cost. All inventory balances are carried at the lower of cost or market.
5. Debt and Credit Agreements
| 4. | Debt and Credit Agreements |
7.19% Notes
In November 1997, the Company issued an aggregate principal amount of $100 million of its 12-year 7.19% Notes (7.19% Notes) to a group of six institutional investors in a private placement offering. The 7.19% Notes require five annual $20 million principal payments startingwhich started in November 2005. The Company made the required $20 million payments in 2007, 2006 and 2005. The Company may prepay all or any portion of the indebtedness on any date with a prepayment penalty. The 7.19% Notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. These covenants include a required asset coverage ratio (present value of proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0, and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.
7.33% Weighted AverageWeighted-average Fixed Rate Notes
To partially fund the cash portion of the acquisition of Cody Company in AugustIn July 2001, the Company issued $170 million of Notes to a group of seven institutional investors in a private placement transaction in July 2001.transaction. Prior to the determination of the Note’s interest rates, the Company entered into a treasury lock in order to reduce the risk of rising interest rates. Interest rates rose during the pricing period, resulting in a $0.7 million gain that will beis being amortized over the life of the Notes, and thereby reducing the effective interest rate by 5.5 basis points. All of the Notes have bullet maturities and were issued in three separate tranches as follows:
| Principal | Term | Coupon | ||||||
Tranche 1 | $ | 75,000,000 | 10-year | 7.26 | % | |||
Tranche 2 | $ | 75,000,000 | 12-year | 7.36 | % | |||
Tranche 3 | $ | 20,000,000 | 15-year | 7.46 | % | |||
| Principal | Term | Maturity Date | Coupon | |||||||
Tranche 1 | $ | 75,000,000 | 10-year | July 2011 | 7.26 | % | ||||
Tranche 2 | $ | 75,000,000 | 12-year | July 2013 | 7.36 | % | ||||
Tranche 3 | $ | 20,000,000 | 15-year | July 2016 | 7.46 | % | ||||
The Notes were issued under the same Note Purchase Agreement as the 7.19% Notes.
Revolving Credit Agreement
On December 10, 2004, the Company amended its Revolving Credit Agreement (Credit Facility)(credit facility) with a group of nine banks. The Credit Facilitycredit facility allows for borrowings of $250 million, of which $140 million and $10 million were outstanding at year end was $250 million. ItDecember 31, 2007 and 2006, respectively. The credit facility can be expanded up to $350 million, either with the existing banks or new banks. This Credit FacilityThe credit facility is unsecured. The term of the Credit Facilitycredit facility expires in December 2009. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the banks’ petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. While the Company does not expect a reduction in the available credit line, in the event that it is adjusted below the outstanding level of borrowings, the Company has a period of six months either to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or to pay down one-sixth of the excess during each of the six months.
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Interest rates under the Credit Facilitycredit facility are based on Euro-Dollars (LIBOR) or Base Rate (Prime) indications, plus a margin. These associated margins increase if the total indebtedness is 50% or greater, greater than 75% or greater than 90% of the Company’s debt limit of $530 million, which can be expanded up to $630$610 million, as shown below.below:
| Debt Percentage | ||||||||||||
| Lower than 50% | 50% or higher but not exceeding 75% | Higher than 75% but not exceeding 90% | Higher than 90% | |||||||||
Euro-Dollar margin | 1.000 | % | 1.250 | % | 1.500 | % | 1.750 | % | ||||
Base Rate margin | 0.000 | % | 0.000 | % | 0.250 | % | 0.500 | % | ||||
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The Company’s weighted-average effective interest rates for the Credit Facility incredit facility during the years ended December 31, 2004, 2003,2007, 2006 and 20022005 were 4.2%7.2%, 1.9%,7.9% and 3.4%6.9%, respectively. As of December 31, 2007, the weighted-average interest rate on the Company’s credit facility was 6.9%. The Credit Facilitycredit facility provides for a commitment fee on the unused available balance at an annual rate of one-quarter of 1%. The Credit Facilitycredit facility also contains various customary restrictions, which include the following:
| (a) | Maintenance of a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. |
| (b) | Prohibition on the merger or sale of all, or substantially all, of the Company’s or any subsidiary’s assets to a third party, except under certain limited conditions. |
The Company believes it was in compliance in all material respects with allits covenants contained in its various debt agreements at December 31, 20042007 and 20032006 and during the years then ended.
6. Employee Benefit Plans
| 5. | Employee Benefit Plans |
Pension Plan
The Company has aan underfunded non-contributory, defined benefit pension plan for all full-time employees. Plan benefits are based primarily on years of service and salary level near retirement. Plan assets are mainly equity securities and fixed income investments and equity securities.investments. The Company complies with the Employee Retirement Income Security Act (ERISA) of 1974 and Internal Revenue Code limitations when funding the plan. The measurement date used to measure pension benefit amounts is December 31, 2004.
The Company has aan unfunded non-qualified equalization plan to ensure payments to certain executive officers of amounts to which they are already entitled under the provisions of the pension plan, but which are subject to limitations imposed by federal tax laws. This plan is unfunded.
Net periodic pension cost of the Company during the last three years is comprised of the following:
(In thousands) | 2004 | 2003 | 2002 | |||||||||
Qualified | ||||||||||||
Current Year Service Cost | $ | 1,619 | $ | 1,481 | $ | 1,056 | ||||||
Interest Accrued on Pension Obligation | 1,697 | 1,515 | 1,362 | |||||||||
Expected Return on Plan Assets | (1,474 | ) | (999 | ) | (991 | ) | ||||||
Net Amortization and Deferral | 88 | 88 | 88 | |||||||||
Recognized Loss | 383 | 415 | 21 | |||||||||
Net Periodic Pension Cost | $ | 2,313 | $ | 2,500 | $ | 1,536 | ||||||
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(In thousands) | 2004 | 2003 | 2002 | ||||||
Non-Qualified | |||||||||
Current Year Service Cost | $ | 395 | $ | 280 | $ | 78 | |||
Interest Accrued on Pension Obligation | 381 | 163 | 29 | ||||||
Net Amortization | 77 | 77 | 77 | ||||||
Loss Recognized from Settlement | — | — | 963 | ||||||
Recognized Loss | 428 | 187 | 7 | ||||||
Net Periodic Pension Cost | $ | 1,281 | $ | 707 | $ | 1,154 | |||
Obligations and Funded Status
The following table illustratesfunded status represents the funded statusdifference between the projected benefit obligation of the Company’s qualified and non-qualified pension plans and the fair value of the qualified pension plan’s assets at December 31:
| 2004 | 2003 | |||||||||||||||
(In thousands) | Qualified | Non-Qualified | Qualified | Non-Qualified | ||||||||||||
Actuarial Present Value of: Accumulated Benefit Obligation | $ | 23,181 | $ | 3,579 | $ | 21,347 | $ | 3,171 | ||||||||
Projected Benefit Obligation | $ | 29,809 | $ | 6,257 | $ | 27,411 | $ | 6,136 | ||||||||
Plan Assets at Fair Value | 18,092 | — | 18,683 | — | ||||||||||||
Projected Benefit Obligation in Excess of Plan Assets | 11,717 | 6,257 | 8,728 | 6,136 | ||||||||||||
Unrecognized Net Loss | (9,846 | ) | (4,374 | ) | (7,083 | ) | (5,457 | ) | ||||||||
Unrecognized Prior Service Cost | (248 | ) | (322 | ) | (336 | ) | (399 | ) | ||||||||
Adjustment to Recognize Minimum Liability | 3,466 | 2,018 | 1,355 | 2,891 | ||||||||||||
Accrued Pension Cost | $ | 5,089 | $ | 3,579 | $ | 2,664 | $ | 3,171 | ||||||||
31.
The change in the combined projected benefit obligation of the Company’s qualified and non-qualified pension plans and the change in the Company’s qualified plan assets at fair value during the last three years is explained as follows:
(In thousands) | 2004 | 2003 | 2002 | |||||||||
Beginning of Year | $ | 33,547 | $ | 26,042 | $ | 19,894 | ||||||
Service Cost | 2,014 | 1,761 | 1,134 | |||||||||
Interest Cost | 2,078 | 1,678 | 1,391 | |||||||||
Actuarial Loss | 1,798 | 4,679 | 5,860 | |||||||||
Benefits Paid | (3,371 | ) | (613 | ) | (2,237 | ) | ||||||
End of Year | $ | 36,066 | $ | 33,547 | $ | 26,042 | ||||||
The change in the combined plan assets at fair value of the Company’s qualified and non-qualified pension plans during the last three years is explained as follows:
(In thousands) | 2004 | 2003 | 2002 | |||||||||
Beginning of Year | $ | 18,683 | $ | 10,279 | $ | 9,909 | ||||||
Actual Return on Plan Assets | 957 | 2,446 | (1,280 | ) | ||||||||
Employer Contribution | 2,000 | 6,735 | 4,080 | |||||||||
Benefits Paid | (3,371 | ) | (613 | ) | (2,237 | ) | ||||||
Expenses Paid | (177 | ) | (164 | ) | (193 | ) | ||||||
End of Year | $ | 18,092 | $ | 18,683 | $ | 10,279 | ||||||
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The reconciliation of the combined funded status of the Company’s qualified and non-qualified pension plans at the end of the last three years is explained as follows:
(In thousands) | 2004 | 2003 | 2002 | |||||||||
Funded Status | $ | 17,974 | $ | 14,864 | $ | 15,762 | ||||||
Unrecognized Loss | (14,220 | ) | (12,540 | ) | (9,745 | ) | ||||||
Unrecognized Prior Service Cost | (570 | ) | (735 | ) | (899 | ) | ||||||
Net Amount Recognized | $ | 3,184 | $ | 1,589 | $ | 5,118 | ||||||
Accrued Benefit Liability – Qualified Plan | $ | 5,089 | $ | 2,664 | $ | 7,857 | ||||||
Accrued Benefit Liability – Non-Qualified Plan | 3,579 | 3,171 | 338 | |||||||||
Intangible Asset | (5,484 | ) | (4,246 | ) | (3,077 | ) | ||||||
Net Amount Recognized | $ | 3,184 | $ | 1,589 | $ | 5,118 | ||||||
Assumptions used to determine projected postretirement benefit obligations and pension costs are as follows:
| 2004 | 2003 | 2002 | |||||||
Discount Rate(1) | 5.75 | % | 6.25 | % | 6.50 | % | |||
Rate of Increase in Compensation Levels | 4.00 | % | 4.00 | % | 4.00 | % | |||
Long-Term Rate of Return on Plan Assets | 8.00 | % | 8.00 | % | 9.00 | % | |||
Health Care Cost Trend for Medical Benefits | 10.00 | % | 8.00 | % | 8.00 | % |
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(In thousands) | 2007 | 2006 | 2005 | |||||||||
Change in Benefit Obligation | ||||||||||||
Benefit Obligation at Beginning of Year | $ | 45,475 | $ | 41,211 | $ | 36,066 | ||||||
Service Cost | 2,931 | 2,720 | 1,803 | |||||||||
Interest Cost | 2,769 | 2,333 | 1,981 | |||||||||
Actuarial Loss | 1,314 | 5 | 1,852 | |||||||||
Plan Amendments | — | (3 | ) | 120 | ||||||||
Benefits Paid | (886 | ) | (791 | ) | (611 | ) | ||||||
Benefit Obligation at End of Year | 51,603 | 45,475 | 41,211 | |||||||||
Change in Plan Assets | ||||||||||||
Fair Value of Plan Assets at Beginning of Year | 38,189 | 23,765 | 18,092 | |||||||||
Actual Return on Plan Assets | 3,179 | 3,587 | 1,544 | |||||||||
Employer Contributions | 5,000 | 12,008 | 5,000 | |||||||||
Benefits Paid | (886 | ) | (791 | ) | (611 | ) | ||||||
Expenses Paid | (738 | ) | (380 | ) | (260 | ) | ||||||
Fair Value of Plan Assets at End of Year | 44,744 | 38,189 | 23,765 | |||||||||
Funded Status at End of Year | $ | (6,859 | ) | $ | (7,286 | ) | $ | (17,446 | ) | |||
Amounts Recognized in the Balance Sheet
Amounts recognized in the balance sheet at December 31 consist of the following:
(In thousands) | 2007 | 2006 | 2005 | |||||||||
Long-Term Assets | $ | — | $ | — | $ | 454 | ||||||
Current Liabilities | (116 | ) | (67 | ) | (1,204 | ) | ||||||
Long-Term Liabilities | (6,743 | ) | (7,219 | ) | (5,904 | ) | ||||||
| $ | (6,859 | ) | $ | (7,286 | ) | $ | (6,654 | ) | ||||
Amounts Recognized in Accumulated Other Comprehensive Income
Amounts recognized in accumulated other comprehensive income at December 31 consist of the following:
(In thousands) | 2007 | 2006 | 2005 | |||||||
Prior Service Cost | $ | 194 | $ | 336 | $ | — | ||||
Net Actuarial Loss | 13,744 | 12,946 | — | |||||||
Minimum Pension Liability | — | — | (5,119 | ) | ||||||
| $ | 13,938 | $ | 13,282 | $ | (5,119 | ) | ||||
The estimated prior service cost and net loss for the qualified defined benefit pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are approximately $0.1 million and $0.8 million, respectively.
The estimated prior service cost and net loss for the defined benefit non-qualified pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are less than $0.1 million and $0.1 million, respectively.
The combined accumulated benefit obligation for both pension plans was $39.5 million, $34.8 million and $30.9 million at December 31, 2007, 2006 and 2005, respectively.
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Components of Net Periodic Benefit Cost and Other Amounts Recognized in Other Comprehensive Income
Qualified Pension Plan
(In thousands) | 2007 | 2006 | 2005 | |||||||||
Qualified Components of Net Periodic Benefit Cost | ||||||||||||
Current Year Service Cost | $ | 2,705 | $ | 2,518 | $ | 2,485 | ||||||
Interest Cost | 2,611 | 2,211 | 1,896 | |||||||||
Expected Return on Plan Assets | (3,015 | ) | (1,962 | ) | (1,507 | ) | ||||||
Amortization of Prior Service Cost | 84 | 98 | 99 | |||||||||
Amortization of Net Loss | 987 | 1,125 | 921 | |||||||||
Net Periodic Pension Cost | $ | 3,372 | $ | 3,990 | $ | 3,894 | ||||||
Other Changes in Qualified Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income | ||||||||||||
Net Loss | 1,694 | N/A | N/A | |||||||||
Amortization of Net Loss | (987 | ) | N/A | N/A | ||||||||
Amortization of Prior Service Cost | (84 | ) | N/A | N/A | ||||||||
Total Recognized in Other Comprehensive Income | 623 | N/A | N/A | |||||||||
Total Recognized in Qualified Net Periodic Benefit Cost and Other Comprehensive Income | $ | 3,995 | N/A | N/A | ||||||||
| Non-Qualified Pension Plan | ||||||||||||
(In thousands) | 2007 | 2006 | 2005 | |||||||||
Non-Qualified Components of Net Periodic Benefit Cost | ||||||||||||
Current Year Service Cost | $ | 226 | $ | 203 | $ | (682 | ) | |||||
Interest Cost | 158 | 122 | 85 | |||||||||
Amortization of Prior Service Cost | 58 | 77 | 77 | |||||||||
Amortization of Net Loss / (Gain) | 102 | 85 | (22 | ) | ||||||||
Net Periodic Pension Cost / (Income) | $ | 544 | $ | 487 | $ | (542 | ) | |||||
Other Changes in Non-Qualified Benefit Obligations Recognized in Other Comprehensive Income | ||||||||||||
Net Loss | 193 | N/A | N/A | |||||||||
Amortization of Net Loss | (102 | ) | N/A | N/A | ||||||||
Amortization of Prior Service Cost | (58 | ) | N/A | N/A | ||||||||
Total Recognized in Other Comprehensive Income | 33 | N/A | N/A | |||||||||
Total Recognized in Non-Qualified Net Periodic Benefit Cost and Other Comprehensive Income | $ | 577 | N/A | N/A | ||||||||
Assumptions
Weighted-average assumptions used to determine projected pension benefit obligations at December 31 were as follows:
| 2007 | 2006 | 2005 | |||||||
Discount Rate | 6.00 | % | 5.75 | % | 5.50 | % | |||
Rate of Compensation Increase | 4.00 | % | 4.00 | % | 4.00 | % |
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Weighted-average assumptions used to determine net periodic pension costs at December 31 are as follows:
| 2007 | 2006 | 2005 | |||||||
Discount Rate | 5.75 | % | 5.50 | % | 5.75 | % | |||
Expected Long-Term Return on Plan Assets | 8.00 | % | 8.00 | % | 8.00 | % | |||
Rate of Compensation Increase | 4.00 | % | 4.00 | % | 4.00 | % |
The long-term expected rate of return on plan assets used in 20042007, as shown above, is eight percent. The Company establishes the long-term expected rate of return by developing a forward looking long-term expected rate of return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation.
Estimated future benefit payments under One of the plan objectives is that performance of the equity portion of the pension plan exceed the Standard and Poors’ 500 Index over the long term. The Company also seeks 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 the Company’s qualifiedpension calculations, the Company has used eight percent as the expected long-term return on plan assets for 2007, 2006 and non-qualified pension plans are expected2005. In order to derive this return, a Monte Carlo simulation was run using 5,000 simulations based upon the Company’s actual asset allocation and liability duration, which has been determined to be paid as follows: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 the Company expects to achieve over 50 percent of the time, is approximately nine percent. The Company expects 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. The Company believes that the eight percent chosen is a reasonable estimate based on its actual results.
(In thousands) | Qualified | Non-Qualified | Total | ||||||
2005 | $ | 553 | $ | 216 | $ | 769 | |||
2006 | 640 | 368 | 1,008 | ||||||
2007 | 731 | 262 | 993 | ||||||
2008 | 808 | 316 | 1,124 | ||||||
2009 | 963 | 504 | 1,467 | ||||||
Years 2010 - 2014 | 8,332 | 3,697 | 12,029 | ||||||
Plan Assets
At December 31, 20042007 and 2003,2006, the non-qualified pension plan did not have plan assets. The plan assets of the Company’s qualified pension plan at December 31, 20042007 and 2003,2006, by asset category are as follows:
| 2004 | 2003 | |||||||||||
(In thousands) | Amount | Percent | Amount | Percent | ||||||||
Equity securities | $ | 13,934 | 77 | % | $ | 11,722 | 63 | % | ||||
Debt securities | 3,226 | 18 | % | 3,349 | 18 | % | ||||||
Other(1) | 932 | 5 | % | 3,612 | 19 | % | ||||||
Total | $ | 18,092 | 100 | % | $ | 18,683 | 100 | % | ||||
| 2007 | 2006 | |||||||||||
(In thousands) | Amount | Percent | Amount | Percent | ||||||||
Equity securities | $ | 31,220 | 70 | % | $ | 27,124 | 71 | % | ||||
Debt securities | 12,684 | 28 | % | 10,605 | 28 | % | ||||||
Other(1) | 840 | 2 | % | 460 | 1 | % | ||||||
Total | $ | 44,744 | 100 | % | $ | 38,189 | 100 | % | ||||
(1) | Primarily consists of cash and cash equivalents. |
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The Company’s investment strategy for benefit plan assets is to invest in funds to maximize the return over the long-term, subject to an appropriate level of risk. Additionally, the objective is for each class of investments to outperform its representative benchmark over the long term. The Company generally targets a portfolio of assets utilizing equity securities, debt 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 the portfolio. The account will typically be fully invested; however, as a temporary investment or an asset protection measure, part of the account may be invested 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.
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Cash Flows
Contributions
The funding levels of the pension plans are in compliance with standards set by applicable law or regulation. In 20042007, the Company did not have any required minimum funding obligations; however, it chose to fund $2$5 million into the qualified plan. In 20052008, the Company does not have any required minimum funding obligations.obligations for the qualified pension plan. The Company will contribute $0.1 million, as shown below, for the non-qualified pension plan. Currently, management has not determined if aany discretionary funding will be made in 2005.2008.
Estimated Future Benefit Payments
The following estimated benefit payments under the Company’s qualified and non-qualified pension plans, which reflect expected future service, as appropriate, are expected to be paid as follows:
Savings Investment Plan
The Company has a Savings Investment Plan (SIP) which is a defined contribution plan. The Company matches a portion of employees’ contributions in cash. Participation in the SIP is voluntary and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $1.4 million, $1.4 million, and $1.3 million in 2004, 2003, and 2002, respectively. The Company matches employee contributions dollar-for-dollar on the first 6% of an employee’s pretax earnings. The Company’s Common Stock is an investment option within the SIP.
Deferred Compensation Plan
In 1998, the Company established a Deferred Compensation Plan. This plan is available to officers of the Company and acts as a supplement to the Savings Investment Plan. The Company matches a portion of the employee’s contribution and those assets are invested in instruments selected by the employee. Unlike the SIP, the Deferred Compensation Plan does not have dollar limits on tax deferred contributions. However, the assets of this plan are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company. At December 31, 2004, the balance in the Deferred Compensation Plan’s rabbi trust was $4.2 million.
The employee participants guide the diversification of trust assets. The trust assets are invested in mutual funds that cover the investment spectrum from equity to money market. These mutual funds are publicly quoted and reported at market value. No shares of the Company’s stock are held by the trust. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets is recorded on the Company’s balance sheet as a component of Other Assets and the corresponding liability is recorded as a component of Other Liabilities.
There is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets for two reasons. First, the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants. Second, no shares of the Company’s stock are held in the trust.
The Company charged to expense plan contributions of less than $20,000 in each year presented.
(In thousands) | Qualified | Non-Qualified | Total | ||||||
2008 | $ | 1,075 | $ | 127 | $ | 1,202 | |||
2009 | 1,337 | 171 | 1,508 | ||||||
2010 | 1,395 | 298 | 1,693 | ||||||
2011 | 1,613 | 217 | 1,830 | ||||||
2012 | 2,052 | 342 | 2,394 | ||||||
Years 2013 - 2017 | 16,118 | 2,158 | 18,276 | ||||||
Postretirement Benefits Other than Pensions
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. The health care plans are contributory, with participants’ contributions adjusted annually. The life insurance plans were non-contributory. As of January 1, 2006, the Company no longer provides postretirement life insurance coverage. Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 251235 retirees and their dependants at the end of 20042007 and 244 retirees and their dependants at the end of 2003. The measurement date used to measure postretirement benefits other than pensions is December 31, 2004.2006.
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When the Company adopted SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pension”, in 1992, it began amortizing the $16.9 million accumulated postretirement benefit, known as the Transition Obligation,transition obligation, over a period of 20 years, or $0.8 million per year which is included in the annual expense of the plan. Included in the amortization benefit of the unrecognized transition obligation amount below are the effects of plan amendments during 1996, 2000 and 2004. TheAs a result of the adoption of SFAS No. 158, the remaining unamortized balance at December 31, 2006 of $3.2 million is $4.6 million whichnow recognized in accumulated other comprehensive income. Additionally, a portion of this amount will be amortized overand reclassified from the next seven years.balance sheet to the income statement as expense each year.
Obligations and Funded Status
The funded status represents the difference between the projected benefit obligation of the Company’s postretirement plan and the fair value of plan assets at December 31. The postretirement plan does not have any plan assets; therefore, the funded status is equal to the amount of the December 31 projected benefit obligation.
Postretirement- 84 -
The change in the Company’s postretirement benefit costs recognizedobligation during the last three years, as well as the funded status at the end of the last three years, is as follows:
(In thousands) | 2007 | 2006 | 2005 | |||||||||
Change in Benefit Obligation | ||||||||||||
Benefit Obligation at Beginning of Year | $ | 18,781 | $ | 11,793 | $ | 14,101 | ||||||
Service Cost | 871 | 789 | 675 | |||||||||
Interest Cost | 1,076 | 877 | 605 | |||||||||
Actuarial Loss / (Gain) | 880 | 6,337 | (876 | ) | ||||||||
Plan Amendments | — | (153 | ) | (1,434 | ) | |||||||
Benefits Paid | (762 | ) | (862 | ) | (1,278 | ) | ||||||
Benefit Obligation at End of Year | 20,846 | 18,781 | 11,793 | |||||||||
Change in Plan Assets | ||||||||||||
Fair Value of Plan Assets at End of Year | N/A | N/A | N/A | |||||||||
Funded Status at End of Year | $ | (20,846 | ) | $ | (18,781 | ) | $ | (11,793 | ) | |||
Amounts Recognized in the Balance Sheet
Amounts recognized in the balance sheet at December 31 consist of the following:
(In thousands) | 2007 | 2006 | 2005 | |||||||||
Current Liabilities | $ | (642 | ) | $ | (577 | ) | $ | (500 | ) | |||
Long-Term Liabilities | (20,204 | ) | (18,204 | ) | (6,514 | ) | ||||||
| $ | (20,846 | ) | $ | (18,781 | ) | $ | (7,014 | ) | ||||
Amounts Recognized in Accumulated Other Comprehensive Income
Amounts recognized in accumulated other comprehensive income at December 31 consist of the following:
(In thousands) | 2007 | 2006 | 2005 | |||||
Transition Obligation | $ | 2,527 | $ | 3,159 | N/A | |||
Prior Service Cost | 1,618 | 2,570 | N/A | |||||
Net Actuarial Loss | 4,392 | 3,705 | N/A | |||||
| $ | 8,537 | $ | 9,434 | N/A | ||||
The estimated net obligation at transition, prior service cost and net loss for the defined benefit postretirement plan that will be amortized from accumulated other comprehensive income into net periodic postretirement cost over the next fiscal year are $0.6 million, $1.0 million and $0.2 million, respectively.
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Components of Net Periodic Benefit Cost
(In thousands) | 2007 | 2006 | 2005 | |||||||||
Components of Net Periodic Postretirement Benefit Cost | ||||||||||||
Current Year Service Cost | $ | 871 | $ | 789 | $ | 675 | ||||||
Interest Cost | 1,076 | 877 | 605 | |||||||||
Amortization of Prior Service Cost | 952 | 952 | 910 | |||||||||
Amortization of Net Obligation at Transition | 632 | 632 | 648 | |||||||||
Amortization of Net Loss / (Gain) | 193 | 32 | (79 | ) | ||||||||
SFAS 106 Net Periodic Postretirement Cost | 3,724 | 3,282 | 2,759 | |||||||||
Recognized Curtailment Gain | — | (86 | ) | — | ||||||||
Recognized Loss Due to Special Term Benefits | — | — | 319 | |||||||||
SFAS 88 (Cost) / Income | — | (86 | ) | 319 | ||||||||
Total SFAS 106 and SFAS 88 Cost | $ | 3,724 | $ | 3,196 | $ | 3,078 | ||||||
Other Changes in Benefit Obligations Recognized in Other Comprehensive Income | ||||||||||||
Net Loss | 880 | N/A | N/A | |||||||||
Amortization of Prior Service Cost | (952 | ) | N/A | N/A | ||||||||
Amortization of Net Obligation at Transition | (632 | ) | N/A | N/A | ||||||||
Amortization of Net Loss / (Gain) | (193 | ) | N/A | N/A | ||||||||
Total Recognized in Other Comprehensive Income | (897 | ) | N/A | N/A | ||||||||
Total Recognized in Qualified Net Periodic Benefit Cost and Other Comprehensive Income | $ | 2,827 | N/A | N/A | ||||||||
Assumptions
Assumptions used to determine projected postretirement benefit obligations and postretirement costs are as follows:
(In thousands) | 2004 | 2003 | 2002 | |||||||||
Service Cost of Benefits Earned During the Year | $ | 671 | $ | 265 | $ | 215 | ||||||
Interest Cost on the Accumulated Postretirement Benefit Obligation | 784 | 385 | 381 | |||||||||
Amortization Benefit of the Unrecognized Gain | (59 | ) | (155 | ) | (267 | ) | ||||||
Amortization of Prior Service Cost | 1,211 | — | — | |||||||||
Amortization Benefit of the Unrecognized Transition Obligation | 662 | 662 | 662 | |||||||||
Total Postretirement Benefit Cost | $ | 3,269 | $ | 1,157 | $ | 991 | ||||||
| 2007 | 2006 | 2005 | |||||||
Discount Rate(1) | 6.00 | % | 5.75 | % | 5.50 | % | |||
Health Care Cost Trend Rate for Medical Benefits Assumed for Next Year | 9.00 | % | 8.00 | % | 9.00 | % | |||
Rate to which the cost trend rate is assumed to decline (the Ultimate Trend Rate) | 5.00 | % | 5.00 | % | 5.00 | % | |||
Year that the rate reaches the Ultimate Trend Rate | 2012 | 2010 | 2010 |
(1) | Represents the year end rates used to determine the projected benefit obligation. To compute postretirement cost in 2007, 2006 and 2005, respectively, the beginning of year discount rates of 5.75%, 5.5% and 5.75% were used. |
The health care cost trend rate used to measure the expected cost from 2000 to 2003 for medical benefits to retirees was 8%.eight percent. Provisions of the plan should preventexisting at that time would have prevented significant future increases in employer cost after 2000. During the yearyears ended December 31, 2005 and 2004, the plan was amended and the limit, or cap, on the employer subsidy for medical and prescription drugin several areas effective January 1, 2006. As of January 1, 2006, coverage provided to participants age 65 and older was removed. In addition, certain other modificationsis under a fully-insured arrangement which replaces the former self-funded plan. Benefits under this new arrangement are comparable to benefits under the plan were madeself-funded plan. The Company subsidy is limited to limit prescription drug coverage (for60% of the expected annual fully-insured premium for participants not age 65 and older) and increaseolder. For all participants under age 65, the plan deductibles and reimbursements by retirees. The companyCompany subsidy for all retiree medical and prescription drug benefits, for all other participants, beginning January 1, 2006, iswas limited to an aggregate annual amount not to exceed $648,000. This limit will increase by 3.5% annually thereafter. Additionally, in February 2005, the Company prepaid the life insurance premiums for all retirees retiring before January 1, 2006, eliminating all future premiums for retiree life insurance. Effective January 1, 2006, the Company eliminated
The health care cost trend rate used at December 31, 2004 was 10%. The rate- 86 -
company paid retiree life insurance coverage. Changes were made to the cost trend ratelife insurance product that is assumedoffered to decline (the ultimate trend rate) is 5% as of December 31, 2004. The year that this ultimate trend rate will be reached is 2009.
employees allowing employees to continue coverage into retirement by paying the premiums directly to the life insurance provider.
Assumed health care cost trend rates may have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
(In thousands) | 1-Percentage- Point Increase | 1-Percentage- Point Decrease | 1-Percentage- Point Increase | 1-Percentage- Point Decrease | ||||||||||
Effect on total of service and interest cost | $ | 146 | $ | (163 | ) | $ | 382 | $ | (306 | ) | ||||
Effect on postretirement benefit obligation | 1,661 | (2,025 | ) | 3,403 | (2,770 | ) | ||||||||
Cash Flows
Contributions
The funded status ofCompany expects to contribute approximately $0.7 million to the postretirement benefit plan in 2008.
Estimated Future Benefit Payments
The following estimated benefit payments under the Company’s postretirement benefit obligation at December 31, 2004, and 2003 is comprised of the following:
(In thousands) | 2004 | 2003 | ||||||
Plan Assets at Fair Value | $ | — | $ | — | ||||
Accumulated Postretirement Benefits Other Than Pensions | 14,101 | 6,181 | ||||||
Unrecognized Cumulative Net Gain | 814 | 1,736 | ||||||
Unrecognized Prior Service Cost | (5,691 | ) | — | |||||
Unrecognized Transition Obligation | (4,631 | ) | (5,293 | ) | ||||
Accrued Postretirement Benefit Liability | $ | 4,593 | $ | 2,624 | ||||
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The change in the accumulated postretirement benefit obligation during the last three years is presentedplans, which reflect expected future service, as follows:
(In thousands) | 2004 | 2003 | 2002 | |||||||||
Beginning of Year | $ | 6,181 | $ | 6,185 | $ | 5,507 | ||||||
Service Cost | 671 | 265 | 215 | |||||||||
Interest Cost | 784 | 386 | 381 | |||||||||
Amendments | 6,901 | — | — | |||||||||
Actuarial Loss | 864 | 221 | 912 | |||||||||
Benefits Paid | (1,300 | ) | (876 | ) | (830 | ) | ||||||
End of Year | $ | 14,101 | $ | 6,181 | $ | 6,185 | ||||||
Estimated future benefit paymentsappropriate, are expected to be paid as follows:
(In thousands) | |||
2005 | $ | 1,034 | |
2006 | 653 | ||
2007 | 688 | ||
2008 | 706 | ||
2009 | 735 | ||
Years 2010 - 2014 | 4,479 | ||
(In thousands) | |||
2008 | $ | 661 | |
2009 | 706 | ||
2010 | 761 | ||
2011 | 831 | ||
2012 | 917 | ||
Years 2013 - 2017 | 6,446 | ||
On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introducesintroduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to certain Medicare benefits. In accordance with FSP No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, any measures of the accumulated plan benefit obligation or net periodic postretirement benefit cost in the financial statements or accompanying notes do not reflect the effects of the Act on the Company’s plan. As amended by the Company has amendedon January 1, 2006, the postretirement benefit plan to excludeexcludes prescription drug benefits to participants age 65 and older effective January 1, 2006, management believesolder. Due to this amendment, FSP willNo. 106-2 did not have an impact on operating results, financial position or cash flows of the Company.
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Incremental Effect of Applying SFAS No. 158 to Pension and Postretirement Plans on Individual Line Items in the Balance Sheet
The table below illustrates the incremental effects of applying SFAS No. 158 to various individual balance sheet line items as of December 31, 2006. The column entitled “Before Application of SFAS No. 158” includes the effect of the additional minimum liability adjustment required for 2006.
(In thousands) | Before Application of SFAS No. 158 | Adjustments | After Application of SFAS No. 158 | ||||||||
Other Assets | $ | 7,864 | $ | (168 | ) | $ | 7,696 | ||||
Deferred Income Tax Asset (Non-Current) | 22,465 | 8,447 | 30,912 | ||||||||
Total Assets | 1,826,212 | 8,279 | 1,834,491 | ||||||||
Accrued Liabilities | 41,459 | 644 | 42,103 | ||||||||
Total Current Liabilities | 250,383 | 644 | 251,027 | ||||||||
Long-Term Liability for Pension Benefits | (5,639 | ) | 12,858 | 7,219 | |||||||
Long-Term Liability for Postretirement Benefits | 9,348 | 8,856 | 18,204 | ||||||||
Accumulated Other Comprehensive Income | 51,239 | (14,079 | ) | 37,160 | |||||||
Total Stockholders’ Equity | 959,277 | (14,079 | ) | 945,198 | |||||||
Total Liabilities and Stockholders’ Equity | 1,826,212 | 8,279 | 1,834,491 | ||||||||
Savings Investment Plan
The Company has a Savings Investment Plan (SIP), which is a defined contribution plan. The Company matches a portion of employees’ contributions in cash. Participation in the SIP is voluntary, and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $2.0 million, $1.8 million and $1.6 million in 2007, 2006, and 2005, respectively. The Company matches employee contributions dollar-for-dollar on the first six percent of an employee’s pretax earnings. The Company’s common stock is an investment option within the SIP.
Deferred Compensation Plan
In 1998, the Company established a Deferred Compensation Plan. This plan is available to officers of the Company and acts as a supplement to the Savings Investment Plan. If the employee’s base salary and bonus deferrals cause the employee to not receive the full six percent company match to the Savings Investment Plan, the Company will make a contribution annually into the Deferred Compensation Plan to ensure that the employee receives a full matching contribution from the Company. Unlike the SIP, the Deferred Compensation Plan does not have dollar limits on tax deferred contributions. However, the assets of this plan are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company.
The officer participants guide the diversification of trust assets. The trust assets are invested in either mutual funds that cover the investment spectrum from equity to money market, or may include holdings of the Company’s common stock, which is funded by the issuance of shares to the trust. The mutual funds are publicly quoted and reported at market value. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets, excluding the Company’s common stock, was $9.7 million and $6.1 million at December 31, 2007 and 2006, respectively, and is included within Other Assets in the Consolidated Balance Sheet. Related liabilities totaled $16.0 million and $6.1 million at December 31, 2007 and 2006, respectively, and are included within Other Liabilities in the Consolidated Balance Sheet. The Company’s common stock held in the rabbi trust is recorded at the market value on the date of deferral, which totaled $6.3 million at December 31, 2007 and is included within Additional Paid-in Capital in Stockholder’s Equity in the Consolidated Balance Sheet. There was no common stock held in the trust in 2006. The Company common stock issued to the trust is not considered outstanding for purposes of calculating basic earnings per share, but is considered a common stock equivalent in the calculation of diluted earnings per share.
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7. Income TaxesThere is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets, excluding the Company’s common stock, because the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants. Stock compensation expense may be recognized if the fair market value of the Company common stock changes. This impact was immaterial in 2007.
The Company charged to expense plan contributions of less than $20,000 in each of 2007, 2006 and 2005.
| 6. | Income Taxes |
Income tax expense (benefit) is summarized as follows:
| Year Ended December 31, | ||||||||||||
(In thousands) | 2004 | 2003 | 2002 | |||||||||
Current | ||||||||||||
Federal | $ | 14,767 | $ | 22,826 | $ | (1,158 | ) | |||||
State | 3,710 | 2,075 | 869 | |||||||||
Total | 18,477 | 24,901 | (289 | ) | ||||||||
Deferred | ||||||||||||
Federal | 31,779 | (8,549 | ) | 7,931 | ||||||||
State | (10 | ) | (1,289 | ) | 32 | |||||||
Total | 31,769 | (9,838 | ) | 7,963 | ||||||||
Total Income Tax Expense | $ | 50,246 | $ | 15,063 | $ | 7,674 | ||||||
| Year Ended December 31, | |||||||||
(In thousands) | 2007 | 2006 | 2005 | ||||||
Current | |||||||||
Federal | $ | (1,424) | $ | 123,155 | $ | 42,976 | |||
State | (3,619) | 14,164 | 5,185 | ||||||
Total | (5,043) | 137,319 | 48,161 | ||||||
Deferred | |||||||||
Federal | 91,257 | 49,911 | 37,565 | ||||||
State | 3,895 | 2,100 | 2,063 | ||||||
Total | 95,152 | 52,011 | 39,628 | ||||||
Total Income Tax Expense | $ | 90,109 | $ | 189,330 | $ | 87,789 | |||
Total income taxes were different than the amounts computed by applying the statutory federal income tax rate as follows:
| Year Ended December 31, | ||||||||||||
(In thousands) | 2004 | 2003 | 2002 | |||||||||
Statutory Federal Income Tax Rate | 35 | % | 35 | % | 35 | % | ||||||
Computed “Expected” Federal Income Tax | $ | 48,518 | $ | 15,065 | $ | 8,322 | ||||||
State Income Tax, Net of Federal Income Tax Benefit | 4,353 | 1,334 | 737 | |||||||||
Other, Net | (2,625 | )(1) | (1,336 | )(2) | (1,385 | )(3) | ||||||
Total Income Tax Expense | $ | 50,246 | $ | 15,063 | $ | 7,674 | ||||||
| Year Ended December 31, | ||||||||||||
(In thousands) | 2007 | 2006 | 2005 | |||||||||
Statutory Federal Income Tax Rate | 35 | % | 35 | % | 35 | % | ||||||
Computed “Expected” Federal Income Tax | $ | 90,137 | $ | 178,818 | $ | 82,682 | ||||||
State Income Tax, Net of Federal Income Tax Benefit | 5,452 | 14,494 | 7,030 | |||||||||
Qualified Production Activities Deduction | — | (2,327 | ) | (1,324 | ) | |||||||
Benefit Related to Favorable State Tax Determination(1) | (2,831 | ) | — | — | ||||||||
Deferred Tax Benefit Related to Reduction in Overall State Tax Rate(2) | (1,378 | ) | (2,605 | ) | (550 | ) | ||||||
Other, Net | (1,271 | ) | 950 | (49 | ) | |||||||
Total Income Tax Expense | $ | 90,109 | $ | 189,330 | $ | 87,789 | ||||||
(1) |
|
(2) |
|
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The tax effects of temporary differences that resulted in significant portions of the deferred tax liabilities and deferred tax assets as of December 31 were as follows:
(In thousands) | 2004 | 2003 | ||||
Deferred Tax Liabilities | ||||||
Property, Plant and Equipment | $ | 246,962 | $ | 208,955 | ||
Items Accrued for Financial Reporting Purposes | 1,358 | 1,826 | ||||
| 248,320 | 210,781 | |||||
Deferred Tax Assets | ||||||
Net Operating Loss Carryforwards | 2,045 | 725 | ||||
Items Accrued for Financial Reporting Purposes | 21,290 | 15,893 | ||||
Other Comprehensive Income | 12,865 | 14,237 | ||||
| 36,200 | 30,855 | |||||
Net Deferred Tax Liabilities | $ | 212,120 | $ | 179,926 | ||
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| Year Ended December 31, | ||||||
(In thousands) | 2007 | 2006 | ||||
Deferred Tax Liabilities | ||||||
Property, Plant and Equipment | $ | 472,444 | $ | 346,198 | ||
Items Accrued for Financial Reporting Purposes | 5,395 | 2,408 | ||||
Other Comprehensive Income | 7,861 | 30,786 | ||||
Total | 485,700 | 379,392 | ||||
Deferred Tax Assets | ||||||
Alternative Minimum Tax Credit Carryforwards | 8,587 | — | ||||
Net Operating Loss Carryforwards | 22,170 | 1,281 | ||||
Items Accrued for Financial Reporting Purposes | 35,193 | 30,564 | ||||
Other Comprehensive Income | 8,353 | 8,453 | ||||
Total | 74,303 | 40,298 | ||||
Net Deferred Tax Liabilities | $ | 411,397 | $ | 339,094 | ||
As of December 31, 2004,2007, the Company had aincurred net operating losses for regular income tax reporting purposes of $49.8 million that it expects to utilize against 2005 taxable income. In addition, the Company had alternative minimum tax credit carryforwards of $8.6 million which do not expire and can be used to offset regular income taxes in future years to the extent that regular income taxes exceed the alternative minimum tax in any such year. The Company also had net operating loss carryforwardcarryforwards of $39.5$82.3 million for state income tax reporting purposes, the majority of which will expire between 20112016 and 2024 and none available for regular federal income tax purposes.2027. It is expected that these deferred tax benefits will be utilized prior to their expiration.
Uncertain Tax Positions
8. CommitmentsIn June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109.” This Interpretation provides guidance for recognizing and Contingenciesmeasuring uncertain tax positions as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a two-step process for accounting for income tax uncertainties. First, a threshold condition of “more likely than not” should be met to determine whether any of the benefit of the uncertain tax position should be recognized in the financial statements. If the recognition threshold is met, FIN 48 provides additional guidance on measuring the amount of the uncertain tax position. Under FIN 48, the Company 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. FIN 48 is effective for fiscal years beginning after December 15, 2006.
The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the Company recognized no change to the liability for unrecognized tax benefits.
The Company recognizes accrued interest related to uncertain tax positions in Interest Expense and Other and accrued penalties related to such positions in General and Administrative expense in the Consolidated Statement of Operations, which is consistent with the recognition of these items in prior reporting periods. As of January 1, 2007, the Company had recorded a liability of approximately $0.9 million for interest. During 2007, the Company reversed this liability and recorded interest receivable of $0.4 million. This resulted in an adjustment to net interest expense of $1.3 million. As of December 31, 2007, the Company determined that no accrual for penalties was required.
As of January 1, 2007, after the implementation of FIN 48, the Company’s unrecognized tax benefits were $1.0
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million. This amount, if recognized, would not affect the effective tax rate. As of December 31, 2007, it is reasonably possible that the 2001-2004 years currently pending before the IRS Appeals Division will be settled within the next twelve months. Discussions are ongoing with the taxing authorities regarding these years. The amounts recorded reflect the Company’s estimate as to the ultimate resolution of these matters. For the year ended December 31, 2007, the unrecognized tax benefit increased by $1.4 million. The amount of unrecognized tax benefits, if recognized, would not have a significant impact on the effective tax rate.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
(In thousands) | ||||
Unrecognized tax benefit balance at January 1, 2007 | $ | 1,029 | ||
Additions based on tax positions related to the current year | — | |||
Additions for tax positions of prior years | 1,415 | |||
Reductions for tax positions of prior years | (19 | ) | ||
Settlements | — | |||
Unrecognized tax benefit balance at December 31, 2007 | $ | 2,425 | ||
It is possible that the amount of unrecognized tax benefits will change in the next twelve months. The Company does not expect that a change would have a significant impact on its results of operations, financial position or cash flows.
The U.S. federal statute of limitations remains open for years 2001 and onward. State income tax returns are generally subject to examination for a period of three to four years after filing of the respective return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by state authorities in major jurisdictions include Texas and West Virginia (2001 onward). The Company is not currently under examination, nor has it been notified of an upcoming examination, by West Virginia. The Company has been audited by Texas for report years through 2006. The audits were resolved successfully and no material adjustments were made.
| 7. | Commitments and Contingencies |
Firm Gas Transportation Agreements
The Company has incurred, and will incur over the next several years, demand charges on firm gas transportation agreements. These agreements provide firm transportation capacity rights on pipeline systems in Canada, the West and East regions. The remaining terms on these agreements range from less than one year to approximately 20 years and require the Company to pay transportation demand charges regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability.
Future obligations under firm gas transportation agreements in effect at December 31, 2007 are as follows:
(In thousands) | |||
2008 | $ | 9,937 | |
2009 | 10,156 | ||
2010 | 6,703 | ||
2011 | 4,526 | ||
2012 | 3,350 | ||
Thereafter | 47,493 | ||
| $ | 82,165 | ||
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Drilling Rig Commitments
The Company has five drilling rigs in the Gulf Coast that are under contract. As of December 31, 2007, the Company is obligated under these contracts to pay $71.3 million over the next three years as follows:
(In thousands) | |||
2008 | $ | 41,180 | |
2009 | 27,902 | ||
2010 | 2,250 | ||
| $ | 71,332 | ||
Lease Commitments
The Company leases certain transportation vehicles, warehouse facilities, office space, and machinery and equipment under cancelable and non-cancelable leases. The lease for the Company’s office in Houston runs for approximately fivetwo more years. MostAll of the Company’sthese operating leases expire within the next five years, and some of these leases may be renewed. Rent expense under such arrangements totaled $8.7$12.3 million, $8.5$10.7 million and $8.8$9.1 million for the years ended December 31, 2004, 2003,2007, 2006 and 2002,2005, respectively.
Future minimum rental commitments under non-cancelable leases in effect at December 31, 20042007 are as follows:
(In thousands) | ||||||
2005 | $ | 4,889 | ||||
2006 | 4,542 | |||||
2007 | 4,340 | |||||
2008 | 2,063 | $ | 5,414 | |||
2009 | 784 | 4,120 | ||||
2010 | 1,267 | |||||
2011 | 528 | |||||
2012 | 183 | |||||
Thereafter | 382 | — | ||||
| $17,000 | $ | 11,512 | ||||
Guarantees
During 2006, the Company assisted certain non-executive employees in obtaining loans to purchase interests offered under its 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 the Company’s 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.
Contingencies
The Company is a defendant in various legal proceedings arising in the normal course of ourits business. All known liabilities are fully accrued based on management’s best estimate of the potential loss. While the outcome and impact of such legal proceedings on the Company 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 the Company’s consolidated financial position.position or cash flow. Operating results, and cash flow, however, could be significantly impacted in the reporting periods in which such matters are resolved.
Wyoming Royalty Litigation
In June 2000, the Company was sued by two overriding royalty owners in Wyoming state court for unspecified damages. The plaintiffs requested class certification and alleged that the Company had improperly deducted costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claimed that the Company had failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. At a mediation held in April 2003, the plaintiffs in this case claimed total damages of $9.5 million plus attorney fees. The Company settled the case for a total of $2.25 million and the State District Court Judge entered his order approving the settlement in the fourth quarter of 2003. The class included all private fee royalty and overriding royalty owners of the Company in the State of Wyoming except those in the suit discussed below and one owner who opted out of the settlement. It also includes provisions for the method of valuation of gas for royalty payment purposes going forward and for reporting of royalty payments, which should prevent further litigation of these issues by the class members.
In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district court. The plaintiffs in the federal case have made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court case but have not asked for class certification.
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The federal district court judge certified two questions of state law for decision by the Wyoming State Supreme Court, which recently answered both questions. The Wyoming Supreme Court ruled that certain deductions taken by the Company from the plaintiffs were not proper and that the statutes of limitations advanced by the Company are discovery statutes and accordingly do not begin to run until the plaintiffs knew, or had reason to know, of the violation. The Company believes it has properly reported to the plaintiffs, and that if it did not, the plaintiffs knew or should have known the reporting was improper and the nature of the deductions, thus triggering the statute of limitations. The Company still intends to raise defenses to the alleged failure to report claims. There is also a dispute as to how the interest should be calculated.
The federal judge refused to certify a question relating to the issue of the proper calculation of damages for failure to provide certain information required by statute on overriding royalty owner check stubs that had been decided adversely to our position in a state district court letter decision in a separate case. After the federal judge’s refusal to certify this issue, the plaintiffs reduced the damages they were claiming. Based upon recent communication from the plaintiffs they are now claiming $26.2 million in total damages which consists of $20.3 million for alleged violations of the check stub reporting statute and $5.9 million for all other damages.
In the opinion of our outside counsel, Brown, Drew & Massey, LLP, the likelihood of the plaintiffs recovering $20.3 million for the check stub reporting statute is remote. However, a reserve that management believes is adequate to provide for the check stub reporting statute and all other damages has been established based on management’s estimate at this time of the probable outcome of this case.
West Virginia Royalty Litigation
In December 2001, the Company was sued by two royalty owners in West Virginia state court for an unspecified amount of damages. The plaintiffs have requested class certification under the West Virginia Rules of Civil Procedure and allegealleged that the Company failed to pay royalty based upon the wholesale market value of the gas, produced, that itthe Company had taken improper deductions from the royalty and that it failed to
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properly inform royalty owners of the plaintiffs and other similarly situated persons of deductions taken from the royalty.deductions. The plaintiffs have also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that the Company reached with Columbia Gas Transmission Corporation in the 1995 Columbia Gas Transmission Corporation bankruptcy proceeding.
Discovery and pleadings necessary to placeproceedings. The Court entered an order on June 1, 2005 granting the class certification issue before the state court have been ongoing. A hearing on the plaintiffs’ motion for class certificationcertification.
The parties reached a tentative settlement in 2007, pursuant to which the Company 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 the Company. 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 would 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 the Company to $12.0 million.
In the tentative settlement, the Company and the class members also agreed 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 October 20, 2003, and proposed findingsFebruary 12, 2008. The Court approved the final settlement at the hearing. Upon filing of fact and conclusionsthe written Order of law were submitted toApproval by the court on December 5, 2003. A status conference was held withCourt, the court andprocess will begin for distribution of the court advised it intends to issue a ruling onsettlement proceeds from the class certification motion. The court was expected to rule by December 2004, and we are still awaiting a decision. Discovery is proceeding on the claims pending the ruling on the class certification motion. Discovery is to be completed by April 1, 2005, and the trial is currently scheduled for August 15, 2005. If a class is certified it is expected this trial date will be continued to a later date.
The investigation into this claim continues and it is in the discovery phase.trust. The Company is vigorously defending the case. It hashad provided a reserve that management believes is adequate based on its estimate ofsufficient to cover the probable outcome ofamount agreed upon to settle this case.
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Texas Title Litigation
On January 6, 2003, the Company was served with Plaintiffs’ Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs filed their First Supplemental Original Petition on March 17, 2004 and their Second Supplemental Petition on November 12, 2004. The significant change in the second Supplemental Petition is that plaintiffs appear to limit their claim to the mineral estate, rather than making claims to both the surface and mineral estate. The plaintiffs allege that they are the rightful owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. As Cody Energy, LLC, the Company acquired certain leases and wells from Wynn-Crosby 1996, Ltd. in 1997 and 1998 and the Company subsequently acquired a 320 acre lease from Hector and Gloria Lopez in 2001. The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in minerals and all improvements on the lands on which the Company acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass, conversion, all for unspecified actual and exemplary damages. The original trial date of May 19, 2003 was cancelled and a new trial date has not been set. The Company has not had the opportunity to conduct discovery in this matter. The Company estimates that production revenue from this field since its predecessor, Cody Energy, LLC, acquired title and since the Company acquired its lease is approximately $14.9 million. The carrying value of this property is approximately $34 million. Co-defendants Shell Oil Company and Shell Western E&P filed a motion for summary judgment seeking dismissal of plaintiffs’ causes of action on multiple grounds. The original plaintiffs’ attorneys asked permission from the Court to withdraw from the representation. The Court granted that request, and new attorneys for some, but not all of the plaintiffs have recently entered the case. The motion for summary judgment was reset and a hearing was held in December of 2003. The Company joined in the motion. After a second hearing, the Court denied the motion for summary judgment. The defendants have moved to add parties whose title interests are being challenged by the plaintiffs, and who are therefore necessary to the case, or in the alternative, abate the proceeding until the plaintiffs join all parties whose interests may be affected by plaintiffs’ claims.
Although the investigation into this claim is in its early stages, the Company intends to vigorously defend the case. Should the Company receive an adverse ruling in this case, an impairment review would be assessed to ensure the carrying value of the property is recoverable. Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.
Raymondville Area
In April 2004, the Company’s wholly owned subsidiary, Cody Energy, LLC, filed suit in Willacy County, Texas against certain of its co-working interest owners in the Raymondville Area, located in Kenedy and Willacy Counties. In early 2003, Cody had proposed a new prospect to certain of these co-working interest owners located within jointly owned oil and gas leases. Some of the co-working interest owners elected to participate and some did not. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.
In December 2003, certain of the co-working interest owners who elected not to participate in the initial well notified Cody that they believed that they had the right to participate in subsequent wells. Cody contends that, under the terms of the agreements between the parties, the co-working interest owners that elected not to participate in the initial well in the prospect were required to assign their interest in the proposed prospect to those who elected to participate. Alternatively, Cody contends that such owners lost their right to participate in subsequent wells within a 1,200 foot radius of the initial well.
The defendants have filed a counter claim against the Company and one of the defendants has filed a lien against Cody’s interest in the leases in the Raymondville Area. Cody contends that this lien is improper and has sought damages for its filing. Cody is vigorously prosecuting this case which is in its early stage of discovery. No trial date has been set by the court.
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Certain of the defendants filed a Motion for Partial Summary Judgment contending that they did not have adequate notice of the prospect proposal. Cody is contesting this Motion. In addition, in late December 2004, Cody filed a Motion for Final Summary Judgment asking the court to find that, under the terms of the agreements, Cody and the participating working interest owners are entitled to an assignment of the interests of the co-working interest owners who elected not to participate in the prospect. No hearing date has been set by the court.
Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.
litigation.
Commitment and Contingency Reserves
The Company has 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 the Company could incur approximately $11.1$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 the Company 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 the consolidated financial position or cash flow of the Company. Operating results, and cash flow, however, could be significantly impacted in the reporting periods in which such matters are resolved.
9. Cash Flow Information
| 8. | Cash Flow Information |
Cash paid / (received) for interest and income taxes is as follows:
| Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||
(In thousands) | 2004 | 2003 | 2002 | 2007 | 2006 | 2005 | |||||||||||||
Interest | $ | 16,415 | $ | 18,298 | $ | 25,112 | $ | 20,257 | $ | 24,088 | $ | 17,366 | |||||||
Income Taxes | 29,861 | 19,267 | 266 | (20,099 | ) | 128,752 | 47,142 | ||||||||||||
The decrease in cash paid for income taxes from 2006 to 2007 is primarily due to the Company’s 2007 net operating loss position and the receipt of $29.6 million in federal tax refunds relating to the Company’s 2006 tax return. 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 sale of the Company’s offshore and certain south Louisiana assets.
The Company recorded benefits of $2.6 million, $1.0$9.5 million and $0.4$3.7 million for the years ended December 31, 2004, 20032006 and 2002,2005, respectively, for tax deductions taken due to employee stock option exercises and restricted stock grant vesting. For the year ended December 31, 2007, the Company did not recognize a tax benefit for stock-based compensation as a result of the tax net operating loss position for the year under the Alternative Minimum Tax system. See Note 10 of the Notes to the Consolidated Financial Statements for additional details.
10. Capital Stock- 93 -
| 9. | Capital Stock |
Incentive Plans
On April 29, 2004, the 2004 Incentive Plan was approved by the shareholders. Under the Company’s 2004 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2004 Incentive Plan consisting of stock options or stock awards, in addition toawards. In the first quarter of 2007, the Board of Directors eliminated the automatic award of an option to purchase 10,00015,000 shares (pre 2-for-1 split) of Common Stockcommon stock on the date the non-employee directors first join the boardBoard of directors.Directors. In its place, the Board of Directors will consider an annual fixed dollar stock award which is competitive with the Company’s peer group. A total of 1,700,0005,100,000 shares of Common Stockcommon stock may be issued under the 2004 Incentive Plan. In addition, shares remaining available for award under the 1994 Long-Term Incentive Plan and the Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (herein “Prior Plans”) were subsumed into the 2004 Incentive Plan (228,398 shares on April 29, 2004). Under the 2004 Incentive Plan, no more than 600,0001,800,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 1,000,0003,000,000 shares may be issued pursuant to incentive stock options. Awards outstanding under the Prior PlansCompany’s prior stock plans will remain outstanding in accordance with their original terms and conditions.
Stock Split
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During 2004,On February 23, 2007, the Board of Directors granteddeclared a series of 168,500 performance share awards to certain executives and key employees of the Company. These awards are earned based on the comparative performance2-for-1 split of the Company’s Common Stock measured against sixteen other companiescommon stock in the Company’s peer group overform of a three year vesting period endingstock distribution. The stock dividend was distributed on December 31, 2006. DependingMarch 30, 2007 to stockholders of record on the Company’s performance, employees may earn upMarch 16, 2007. All common stock accounts and per share data have been retroactively adjusted to 100% of the award in Common Stock, and an additional 100% of the award in cash. The performance shares qualify for variable accounting, and accordingly, are recorded at their fair value with compensation expense recognized over the performance period.
During 2004, the Company granted 7,000 restricted stock units to various Company Directors. These units immediately vest and will be paid out whenever the Director ceases to be a Director of the Company. For all restricted stock units, the Company recognized compensation expense equalgive effect to the market value2-for-1 split of the Company’s Common Stock oncommon stock.
Increase in Authorized Shares
On May 4, 2006, the grant datestockholders of the respective awards.Company approved an increase in the authorized number of shares of common stock from 80 million to 120 million shares. The Company 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 the Preferred Stock Purchase Rights Plan described below.
Treasury Stock
Information regardingThe Board of Directors has authorized a share repurchase program under which the Company may purchase shares of common stock options underin the Company’s 2004 Incentive Planopen market or in negotiated transactions. The timing and amount of these stock purchases are determined at the Prior Plansdiscretion of management. The Company may use the repurchased shares to fund stock compensation programs presently in existence, or for other corporate purposes. All purchases executed to date have been through open market transactions. There is summarized below:
| December 31, | ||||||
| 2004 | 2003 | 2002 | ||||
Shares Under Option at Beginning of Period | 1,349,501 | 1,287,829 | 1,081,621 | |||
Granted | 24,500 | 467,000 | 429,300 | |||
Exercised | 529,183 | 345,386 | 181,027 | |||
Surrendered or Expired | 33,129 | 59,942 | 42,065 | |||
Shares Under Option at End of Period | 811,689 | 1,349,501 | 1,287,829 | |||
Options Exercisable at End of Period | 377,329 | 511,719 | 570,406 | |||
For eachno expiration date associated with the authorization to repurchase securities of the three most recent years,Company.
During the price rangeyear ended December 31, 2007, the Company did not repurchase any shares of common stock. Since the authorization date, the Company has repurchased 5,204,700 shares, or 52% of the 10 million total shares authorized for outstanding options was $17.44repurchase at December 31, 2007, for a total cost of approximately $85.7 million. The repurchased shares are held as treasury stock. No treasury shares have been delivered or sold by the Company subsequent to $34.98 per share. The following tables provide more information about the options by exercise price and year.repurchase.
Options with exercise prices between $17.44 and $20.00 per share:
| December 31, | |||||||||
| 2004 | 2003 | 2002 | |||||||
Options Outstanding | |||||||||
Number of Options | 229,963 | 444,668 | 737,385 | ||||||
Weighted Average Exercise Price | $ | 19.28 | $ | 19.22 | $ | 18.97 | |||
Weighted Average Contractual Term (in years) | 2.0 | 2.6 | 3.0 | ||||||
Options Exercisable | |||||||||
Number of Options | 122,491 | 204,229 | 301,277 | ||||||
Weighted Average Exercise Price | $ | 19.29 | $ | 19.04 | $ | 18.39 | |||
Options with exercise prices between $20.01 and $34.98 per share:
| December 31, | |||||||||
| 2004 | 2003 | 2002 | |||||||
Options Outstanding | |||||||||
Number of Options | 581,726 | 904,833 | 550,444 | ||||||
Weighted Average Exercise Price | $ | 24.24 | $ | 24.69 | $ | 25.81 | |||
Weighted Average Contractual Term (in years) | 2.7 | 3.4 | 3.0 | ||||||
Options Exercisable | |||||||||
Number of Options | 254,838 | 307,490 | 269,129 | ||||||
Weighted Average Exercise Price | $ | 24.44 | $ | 26.42 | $ | 25.39 | |||
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Dividend Restrictions
The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the Common Stockcommon stock depending on, among other things, the Company’s financial condition, funds from operations, the level of its capital and exploration expenditures, and its future business prospects. None of the note or credit agreements in place have a restricted payment provision.provision or other provision limiting dividends.
Treasury Stock- 94 -
In August 1998, the Board of Directors authorized the Company
Purchase Rights
On January 21, 1991, the Board of Directors adopted the Preferred Stock Purchase Rights Plan and declared a dividend distribution of one right for each outstanding share of Common Stock.common stock. On December 8, 2000, the rights agreement for the plan was amended and restated to extend the term of the plan to 2010 and to make other changes. Each right becomes exercisable at a price of $55, when any person or group has acquired or made a tender or exchange offer for beneficial ownership of 15% or more of the Company’s outstanding Common Stock.common stock. Each right entitles the holder, other than the acquiring person or group, to purchase one one-hundredtha fraction of a share of Series A Junior Participating Preferred Stock (Junior Preferred Stock). After a person or group acquires beneficial ownership of 15% of the Common Stock,common stock, each right entitles the holder to purchase Common Stockcommon stock or other property having a market value (as defined in the plan) of twice the exercise price of the right. An exception to this triggering event applies in the case of a tender or exchange offer for all outstanding shares of Common Stockcommon stock determined to be fair and in the best interests of the Company and its stockholders by a majority of the independent directors. Under certain circumstances, the Board of Directors may opt to exchange one share of Common Stockcommon stock for each exercisable right. If there is a 15% holder and the Company is acquired in a merger or other business combination in which it is not the survivor, or 50% or more of the Company’s assets or earning power are sold or transferred, each right entitles the holder to purchase common stock of the acquiring company with a market value (as defined in the plan) equal to twice the exercise price of each right. At December 31, 20042007 there were no shares of Junior Preferred Stock issued or outstanding.
The rights expire on January 21, 2010, and may be redeemed by the Company for $0.01 per right at any time before a person or group acquires beneficial ownership of 15% of the Common Stock.common stock.
As a result of stock splits in 2005 and 2007, each share of common stock continues to include one right under the Company’s Preferred Stock Purchase Rights Plan, and each right now provides for the purchase, upon the occurrence of the conditions set forth in the plan, of one-third of one one-hundredth of a share of preferred stock at a purchase price of approximately $18.33 per one-third of one one-hundredth of a share (or $55 for each one one-hundredth of a share). The redemption price of each right is now one-third of a cent.
| 10. | Stock-Based Compensation |
Adoption of SFAS No. 123(R)
Prior to January 1, 2006, the Company accounted for stock-based compensation in accordance with the intrinsic value based method prescribed by APB No. 25. Under the intrinsic value based method, no compensation expense was recorded for stock options granted when the exercise price for options granted was equal to or greater than the fair value of the Company’s common stock on the date of the grant.
Beginning January 1, 2006, the Company began accounting for stock-based compensation under SFAS No. 123(R), which applies to new awards and to awards modified, repurchased or cancelled after December 31, 2005. The Company recorded compensation expense based on the fair value of awards as described below. Additionally, compensation expense for the portion of the awards for which the requisite service period was not rendered that were outstanding at December 31, 2005 was or will be recognized as the requisite service is rendered on or after January 1, 2006.
Compensation expense charged against income for stock-based awards for the years ended December 31, 2007, 2006 and 2005 was $15.3 million, $21.2 million and $9.6 million, pre-tax, respectively, and is included in General and Administrative Expense in the Consolidated Statement of Operations. The primary reasons for the decrease from 2007 to 2006 were due to a reduction in performance share expense from a change in the liability component of the awards resulting from the variance in the Company’s relative ranking from 2006 to 2007 as well as a reduction in restricted stock awards as a result of awards that vested in 2007. Compensation expense in 2005 only included amortization of restricted stock grants and compensation expense related to performance shares and restricted stock units. The $0.6 million ($0.4 million, net of tax) cumulative effect charge at adoption that was recorded in the first quarter of 2006 was due primarily to the recording of the liability component of the Company’s performance share awards at fair value, rather than intrinsic
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11.Index to Financial
StatementsInstruments
value. The Company recorded tax benefits related to stock-based compensation of $9.5 million and $3.7 million for the years ended December 31, 2006 and 2005, respectively, for tax deductions taken due to employee stock option exercises and restricted stock grant vesting. For the year ended December 31, 2007, the Company realized an $11.2 million tax benefit for the tax deduction in excess of book compensation cost associated with taxable employee stock-based compensation. In accordance with SFAS No. 123(R), the Company may recognize this tax benefit only to the extent it reduced the Company’s income taxes payable for the year. For regular tax purposes, the Company was in a net operating loss position; thus the entire tax benefit of stock-based compensation for 2007 will be recorded only when the tax net operating loss is utilized to reduce income taxes payable or claim a refund of taxes paid in prior years.
Prior to the adoption of SFAS No. 123(R), the Company presented tax benefits resulting from tax deductions related to stock-based compensation as an operating cash flow. Under SFAS No. 123(R), the tax benefits resulting from tax deductions in excess of expense are reported as an operating cash outflow and a financing cash inflow. For the year ended December 31, 2006, $9.5 million was reported in these two separate line items in the Consolidated Statement of Cash Flows.
On October 26, 2005, the Compensation Committee of the Board of Directors of the Company approved the acceleration to December 15, 2005 of the vesting of 198,799 unvested stock options awarded in February 2003 under the Company’s Second Amended and Restated 1994 Long-Term Incentive Plan and 24,500 unvested stock options awarded in April 2004 under the Company’s 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 April 2006 and April 2007, respectively. The decision to accelerate the vesting of these unvested options, which the Company believed to be in the best interest of its shareholders and employees, was made solely to reduce compensation expense and administrative burden associated with the Company’s adoption of SFAS No. 123(R). The accelerated vesting of the options did not have an impact on the Company’s results of operations or cash flows in 2005. The acceleration of vesting reduced the Company’s compensation expense related to these options by approximately $0.2 million for 2006.
During the third quarter of 2006, the Company adopted the provisions outlined under 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. The Company was not required to adopt this provision until January 1, 2007, one year from the adoption of 123(R); however, it chose early adoption. The Company made a one time election as prescribed under the FSP to use the shortcut approach to derive the initial windfall tax benefit pool. The Company chose to use a one-pool approach which combines all awards granted to employees, including non-employee directors.
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The following table illustrates the effect on Net Income and Earnings per Share if the Company had applied the fair value recognition provisions of SFAS No. 123(R) to stock-based employee compensation during the year ended December 31, 2005:
(In thousands, except per share amounts) | ||||
Net Income, as reported | $ | 148,445 | ||
Add: Employee stock-based compensation expense, net of related tax effects, included in net income, as reported | 5,965 | |||
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax, previously not included in Net Income | (6,932 | ) | ||
Pro forma net income | $ | 147,478 | ||
Earnings per Share: | ||||
Basic - as reported | $ | 1.52 | ||
Basic - pro forma | $ | 1.51 | ||
Diluted - as reported | $ | 1.49 | ||
Diluted - pro forma | $ | 1.48 | ||
Share Count | 97,713 | |||
Diluted Share Count | 99,451 | |||
In September 2006, the SEC Staff issued a letter summarizing its views regarding the backdating of stock options. The letter discusses the date that is to be used as the measurement date for options in order to value the exercise price of stock options. It also discusses the documentation that should be available to support award grant dates. The Company reviewed its stock option granting practices and found no instances of backdating. Further, as required under the Company’s incentive plans, the stock option grant date is the date on which the Compensation Committee and/or Board of Directors approves the award. Company management is given no discretion to choose the grant date. The Company maintains Compensation Committee and/or Board of Directors minutes and other records to support the grant dates of its options.
Restricted Stock Awards
Restricted stock awards vest either at the end of a three year service period, or on a graded-vesting basis of one-third at each anniversary date over a three year service period. Under the graded-vesting approach, the Company recognizes compensation cost over the three year requisite service period for each separately vesting tranche as though the awards are, in substance, multiple awards. For awards that vest at the end of the three year service period, expense is recognized ratably using a straight-line expensing approach over three years. For all restricted stock awards, vesting is dependant upon the employees’ continued service with the Company, with the exception of employment termination due to death, disability or retirement.
The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The maximum contractual term is three years. In accordance with SFAS No. 123(R), the Company accelerated the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company’s stock-based compensation programs for awards issued after the adoption of SFAS No. 123(R). The Company used an annual forfeiture rate ranging from 0% to 3.3% based on approximately ten years of the Company’s history for this type of award to various employee groups.
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The following table is a summary of restricted stock award activity for the year ended December 31, 2007:
Restricted Stock Awards | Shares | Weighted- Average Grant Date Fair Value per share | Weighted- Average Remaining Contractual Term (in years) | Aggregate Intrinsic Value (in thousands) (1) | |||||||
Non-vested shares outstanding at December 31, 2006 | 797,644 | $ | 15.97 | ||||||||
Granted | 51,900 | 32.92 | |||||||||
Vested | (350,576 | ) | 14.97 | ||||||||
Forfeited | (15,474 | ) | 17.98 | ||||||||
Non-vested shares outstanding at December 31, 2007 | 483,494 | $ | 18.44 | 1.9 | $ | 19,519 | |||||
(1) | The aggregate intrinsic value of restricted stock awards is calculated by multiplying the closing market price of theCompany’s stock on December 31, 2007 by the number of non-vested restricted stock awards outstanding. |
As shown in the table above, there were 51,900 shares of restricted stock granted to employees during 2007. Awards totaling 51,500 shares vest at the end of a three year service period commencing in July 2007. Awards totaling 400 shares vest over a two year service period commencing in October 2007 and are amortized using a graded-vesting schedule. During the year ended December 31, 2006, 93,700 restricted stock awards were granted with a weighted-average grant date fair value per share of $23.80. During the year ended December 31, 2005, 655,246 restricted stock awards were granted with a weighted-average grant date fair value per share of $15.94. The total fair value of shares vested during 2007, 2006 and 2005 was $5.2 million, $5.0 million and $2.2 million, respectively.
Compensation expense recorded for all unvested restricted stock awards for the years ended December 31, 2007, 2006 and 2005 was $3.4 million, $6.1 million and $5.6 million, respectively. Included in 2007 and 2006 restricted stock expense was $0.1 million and $0.6 million, respectively related to the immediate expensing of shares granted to retirement-eligible employees. Unamortized expense as of December 31, 2007 for all outstanding restricted stock awards was $2.3 million.
Restricted Stock Units
Restricted stock units are granted from time to time to non-employee directors of the Company. The fair value of these units is measured at the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and are paid out when the director ceases to be a director of the Company. Due to the immediate vesting of the units and the unknown term of each director, the weighted-average remaining contractual term in years has been omitted from the table below.
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The following table is a summary of restricted stock unit activity for the year ended December 31, 2007:
Restricted Stock Units | Shares | Weighted- Average Grant Date Fair Value per share | Aggregate Intrinsic Value (in thousands) (1) | ||||||
Outstanding at December 31, 2006 | 77,440 | $ | 19.99 | ||||||
Granted and fully vested | 24,654 | 35.49 | |||||||
Issued | (17,042 | ) | 22.57 | ||||||
Forfeited | — | — | |||||||
Outstanding at December 31, 2007 | 85,052 | $ | 23.97 | $ | 3,434 | ||||
(1) | The intrinsic value of restricted stock units is calculated by multiplying the closing market price of theCompany’s stock on December 31, 2007 by the number of outstanding restricted stock units. |
As shown in the table above, 24,654 restricted stock units were granted during 2007. During 2006, 34,440 restricted stock units were granted with a weighted-average grant date fair value per share of $25.41. During 2005, 39,200 restricted stock units were granted with a weighted-average grant date fair value per share of $17.79.
The compensation cost, which reflects the total fair value of these units, recorded entirely in the first quarter of 2007 was $0.9 million. Compensation expense recorded during the years ended December 31, 2006 and 2005 for restricted stock units was $0.9 million and $0.7 million, respectively.
Stock Options
Stock option awards are granted with an exercise price equal to the fair market price (defined as the average of the high and low trading prices of the Company’s stock at the date of grant) of the Company’s stock on the date of grant.
During the year ended December 31, 2007, there were no stock options granted. During the year ended December 31, 2006, 60,000 stock options, with an exercise price of $23.80 per share, were granted to two incoming non-employee directors of the Company. All of these stock options were granted in the first quarter of 2006. No stock options were granted in the year ended December 31, 2005.
Compensation cost is recorded based on a graded-vesting schedule as the options vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. Stock options have a maximum contractual term of five years. No forfeiture rate is assumed for stock options granted to directors due to the forfeiture rate history for these types of awards for this group of individuals. Compensation expense recorded during 2007 and 2006 for these stock options was $0.1 million and $0.3 million, respectively. Since the Company had not yet adopted SFAS No. 123(R) as of December 31, 2005, stock options were not expensed through the Consolidated Statement of Operations during 2005 and no compensation expense was recorded. Unamortized expense as of December 31, 2007 for all outstanding stock options was $0.1 million. The weighted-average period over which this compensation will be recognized is approximately 1.2 years.
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The grant date fair value of a stock option is calculated by using a Black-Scholes model. The assumptions used in the Black-Scholes fair value calculation for stock options are as follows:
| Year Ended December 31, | ||||||||||
| 2007 | 2006 | 2005 | ||||||||
Weighted-Average Value per Option Granted During the Period (1) | $ | — | $ | 7.32 | $ | — | ||||
Assumptions | ||||||||||
Stock Price Volatility | — | 31.5 | % | — | ||||||
Risk Free Rate of Return | — | 4.6 | % | — | ||||||
Expected Dividend | — | 0.3 | % | — | ||||||
Expected Term (in years) | — | 4.0 | — | |||||||
(1) | Calculated using the Black-Scholes fair value based method. |
The expected term was derived by reviewing minimum and maximum expected term outputs from the Black-Scholes model based on award type and employee type. This term represents the period of time that awards granted are expected to be outstanding. The stock price volatility was calculated using historical closing stock price data for the Company for the period associated with the expected term through the grant date of each award. The risk free rate of return percentages are based on the continuously compounded equivalent of the US Treasury (Nominal 10) within the expected term as measured on the grant date. The expected dividend percentage assumes that the Company will continue to pay a consistent level of dividend each quarter.
The following table is a summary of stock option activity for the years ended December 31, 2007, 2006 and 2005:
| 2007 | 2006 | 2005 | ||||||||||||||||
Stock Options | Shares | Weighted- Average Exercise Price | Shares | Weighted- Average Exercise Price | Shares | Weighted- Average Exercise Price | ||||||||||||
Outstanding at Beginning of Year | 1,007,950 | $ | 9.03 | 1,826,696 | $ | 7.66 | 2,435,068 | $ | 7.61 | |||||||||
Granted | — | — | 60,000 | 23.80 | — | — | ||||||||||||
Exercised | (619,000 | ) | 8.18 | (876,946 | ) | 7.20 | (600,986 | ) | 7.46 | |||||||||
Forfeited or Expired | — | — | (1,800 | ) | 9.10 | (7,386 | ) | 7.43 | ||||||||||
Outstanding at December 31 (1) | 388,950 | $ | 10.38 | 1,007,950 | $ | 9.03 | 1,826,696 | $ | 7.66 | |||||||||
Options Exercisable at December 31(2) | 348,950 | $ | 8.84 | 947,950 | $ | 8.09 | 1,791,696 | $ | 7.65 | |||||||||
(1) | The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds theexercise price of the option. The aggregate intrinsic value of options outstanding at December 31, 2007 was $11.7 million. Theweighted-average remaining contractual term is 0.7 years. |
(2) | The aggregate intrinsic value of options exercisable at December 31, 2007 was $11.0 million. The weighted-average remaining contractual term is 0.4 years. |
The total intrinsic value of options exercised during the years ended December 31, 2007, 2006 and 2005 was $19.9 million, $17.7 million and $6.9 million, respectively.
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At December 31, 2007, the exercise price range for outstanding options was $6.42 to $23.80 per share. The following tables provide more information about the options by exercise price.
Options with exercise prices between $6.42 and $15.00 per share:
Options Outstanding | |||
Number of Options | 338,950 | ||
Weighted Average Exercise Price | $ | 8.40 | |
Weighted Average Contractual Term (in years) | 0.3 | ||
Options Exercisable | |||
Number of Options | 338,950 | ||
Weighted Average Exercise Price | $ | 8.40 | |
Weighted Average Contractual Term (in years) | 0.3 | ||
Options with exercise prices between $15.01 and $23.80 per share:
Options Outstanding | |||
Number of Options | 50,000 | ||
Weighted Average Exercise Price | $ | 23.80 | |
Weighted Average Contractual Term (in years) | 3.2 | ||
Options Exercisable | |||
Number of Options | 10,000 | ||
Weighted Average Exercise Price | $ | 23.80 | |
Weighted Average Contractual Term (in years) | 3.2 | ||
Stock Appreciation Rights
Beginning in 2006, the Compensation Committee has granted SARs to employees. These awards allow the employee to receive any intrinsic value over the grant date fair market value that may result from the price appreciation on a set number of common shares during the contractual term of seven years. All of these awards have graded-vesting features and will vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. As these SARs are paid out in stock, rather than in cash, the Company calculates the fair value in the same manner as stock options, by using a Black-Scholes model.
The assumptions used in the Black-Scholes fair value calculation for SARs are as follows:
| Year Ended December 31, | ||||||||
| 2007 | 2006 | |||||||
Weighted-Average Value per Stock Appreciation Right Granted During the Period (1) | $ | 11.26 | $ | 7.09 | ||||
Assumptions | ||||||||
Stock Price Volatility | 32.6 | % | 31.6 | % | ||||
Risk Free Rate of Return | 4.6 | % | 4.6 | % | ||||
Expected Dividend | 0.2 | % | 0.3 | % | ||||
Expected Term (in years) | 4.00 | 3.75 | ||||||
(1) | Calculated using the Black-Scholes fair value based method. |
These assumptions were derived using the same process as described in the “Stock Options” section above.
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The following table is a summary of SAR activity for the years ended December 31, 2007 and 2006:
| 2007 | 2006 | |||||||||
Stock Appreciation Rights | Shares | Weighted- Average Exercise Price | Shares | Weighted- Average Exercise Price | ||||||
Outstanding at Beginning of Year | 265,600 | $ | 23.80 | — | $ | — | ||||
Granted | 107,200 | 35.22 | 265,600 | 23.80 | ||||||
Exercised | — | — | — | — | ||||||
Forfeited or Expired | — | — | — | — | ||||||
Outstanding at December 31 (1) | 372,800 | $ | 27.08 | 265,600 | $ | 23.80 | ||||
SARs Exercisable at December 31(2) | 88,526 | $ | 23.80 | — | $ | — | ||||
(1) | The intrinsic value of a SAR is the amount by which the current market value of the underlying stock exceeds the exercise price of the SAR. The aggregate intrinsic value of SARs outstanding at December 31, 2007 was $5.0 million. The weighted-average remaining contractual term is 5.4 years. |
(2) | The aggregate intrinsic value of SARs exercisable at December 31, 2007 was $1.5 million. The weighted-average remaining contractual term is 5.1 years. |
As shown in the table above, the Compensation Committee granted 107,200 SARs with a grant date fair market value of $35.22 to employees during 2007. Compensation expense recorded during the year ended December 31, 2007 and 2006 for all outstanding SARs was $1.5 million and $1.0 million, respectively. Included in 2007 expense was $0.5 million related to the immediate expensing of shares granted to retirement-eligible employees. As no SARs were outstanding during 2005, no compensation expense was recorded for this type of award. Unamortized expense as of December 31, 2007 for all outstanding SARs was $0.6 million. The weighted-average period over which this compensation will be recognized is approximately 1.7 years.
Performance Share Awards
During 2007, the Compensation Committee granted three types of performance share awards to employees for a total of 387,100 performance shares. The performance period for two of these awards commenced on January 1, 2007 and ends December 31, 2009. Both of these types of awards vest at the end of the three year performance period.
Awards totaling 98,200 performance shares are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three year performance period. The grant date per share value of the equity portion of this award was $30.72. Depending on the Company’s performance, employees may receive an aggregate of up to 100% of the fair market value of a share of common stock payable in common stock plus up to 100% of the fair market value of a share of common stock payable in cash.
Awards totaling 196,500 performance shares are earned, or not earned, based on the Company’s internal performance metrics rather than performance compared to a peer group. The grant date per share value of this award was $35.22. These awards represent the right to receive up to 100% of the award in shares of common stock. The actual number of shares issued at the end of the performance period will be determined based on the Company’s performance against three performance criteria set by the Company’s Compensation Committee. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the performance period. These performance criteria measure the Company’s average production, average finding costs and average reserve replacement over three years. Based on the Company’s probability assessment at December 31, 2007, it is currently considered probable that these three criteria will be met.
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The third performance share award, totaling 92,400 performance shares, with a grant date per share value of $35.22, has a three-year graded vesting schedule, vesting one-third on each anniversary date following the date of grant, provided that the Company has positive operating income for the year preceding the vesting date. If the Company does not have positive operating income for the year preceding a vesting date, then the portion of the performance shares that would have vested on that date will be forfeited. As of December 31, 2007, it is considered probable that this performance metric will be met.
For all awards granted to employees after January 1, 2006, an annual forfeiture rate ranging from 0% to 5.0% has been assumed based on the Company’s history for this type of award to various employee groups.
For awards that are based on the internal metrics (performance condition) of the Company and for awards that were granted prior to the adoption of SFAS No. 123(R) on January 1, 2006, fair value is measured based on the average of the high and low stock price of the Company on grant date and expense is amortized over the three year vesting period. To determine the fair value for awards that were granted after January 1, 2006 that are based on the Company’s comparative performance against a peer group (market condition), the equity and liability components are bifurcated. On the grant date, the equity component was valued using a Monte Carlo binomial model and is amortized on a straight-line basis over three years. The liability component is valued at each reporting period by using a Monte Carlo binomial model.
The three primary inputs for the Monte Carlo model are the risk-free rate, volatility of returns and correlation in movement of total shareholder return. The risk-free rate was generated from the Federal Reserve website for constant maturity treasuries for six-month, one, two and three year bonds and is set equal to the yield, for the period over the remaining duration of the performance period, on treasury securities as of the reporting date. Volatility was set equal to the annualized daily volatility measured over a historic four year period ending on the reporting date. Correlation in movement of total shareholder return was determined based on a correlation matrix that was created which identifies total shareholder return correlations for each pair of companies in the peer group, including the Company. The paired returns in the correlation matrix ranged from approximately 35% to approximately 77% for the Company and its peer group. Based on these inputs discussed above, a ranking was projected identifying the Company’s rank relative to the peer group for each award period.
The following assumptions were used as of December 31, 2007 for the Monte Carlo model to value the liability components of the peer group measured performance share awards. The equity portion of the award was valued on the date of grant using the Monte Carlo model and this portion was not marked to market.
| As of December 31, 2007 | |||
Risk Free Rate of Return | 3.0% - 3.4 | % | |
Stock Price Volatility | 30.4% - 34.5 | % | |
Expected Dividend | 0.3 | % |
The Monte Carlo value per share for the liability component for all outstanding market condition performance share awards ranged from $8.89 to $21.36 at December 31, 2007. The long-term liability for all market condition performance share awards, included in Other Liabilities in the Consolidated Balance Sheet, at December 31, 2007 and 2006 was $0.2 million and $3.9 million, respectively. The short-term liability, included in Accrued Liabilities in the Consolidated Balance Sheet, at December 31, 2007 and 2006, for certain market condition performance share awards was $5.5 million and $4.6 million, respectively.
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The following table is a summary of performance share award activity for the year ended December 31, 2007:
Performance Share Awards | Shares | Weighted- Average Grant Date Fair Value per share(1) | Weighted- Average Remaining Contractual Term (in years) | Aggregate Intrinsic Value (in thousands) (2) | |||||||
Non-vested shares outstanding at December 31, 2006 | 940,100 | $ | 14.83 | ||||||||
Granted | 387,100 | 34.08 | |||||||||
Vested | (450,000 | ) | 10.75 | ||||||||
Forfeited | (9,500 | ) | 33.46 | ||||||||
Non-vested shares outstanding at December 31, 2007 | 867,700 | $ | 25.38 | 1.9 | $ | 35,029 | |||||
(1) | The fair value figures in this table represent the fair value of the equity component of the performance share awards. |
(2) | The aggregate intrinsic value of performance share awards is calculated by multiplying the closing market price of theCompany’s stock on December 31, 2007 by the number of non-vested performance share awards outstanding. |
During the year ended December 31, 2006, 285,500 performance share awards were granted with a weighted-average grant date fair value per share of $21.07. During the year ended December 31, 2005, 220,400 performance share awards were granted with a grant date fair value per share of $15.22. During the year ended December 31, 2006, 30,600 performance shares vested as a result of the death of one of the Company’s officers. No performance shares vested in 2005. During 2006 and 2005, 7,100 and 17,400 performance shares, respectively, were forfeited.
Total unamortized compensation cost related to the equity component of performance shares at December 31, 2007 was $9.8 million and will be recognized over the next 1.9 years, computed by using the weighted-average of the time in years remaining to recognize unamortized expense. Total compensation cost recognized for both the equity (including the cumulative effect) and liability components of performance share awards during the years ended December 31, 2007, 2006 and 2005 was $9.4 million, $12.9 million and $3.3 million, respectively.
Supplemental Employee Incentive Plan
On January 16, 2008, the Company’s Board of Directors adopted a Supplemental Employee Incentive Plan. The plan is intended to provide a compensation tool tied to stock market value creation to serve as an incentive and retention vehicle for full-time non-officer employees by providing for cash payments in the event the Company’s common stock reaches a specified trading price. Certain retirees are also eligible to participate in the plan.
The plan provides a total bonus pool of up to $45 million, as determined by the Compensation Committee of the Company’s Board of Directors. The bonus pool becomes available if, for any 20 trading days (which need not be consecutive) that fall within a period of 60 consecutive trading days occurring prior to November 1, 2011, the closing price per share of the Company’s common stock equals or exceeds the price goal of $60 per share. In such event, the 20th trading day on which such price condition is attained is the “Final Trigger Date.” The price goal is subject to adjustment by the Compensation Committee to reflect any stock splits, stock dividends or extraordinary cash distributions to stockholders. Under the plan, each eligible employee will receive a minimum distribution of 50% of his or her base salary as of the Final Trigger Date, as adjusted for persons hired after June 30, 2008 to reflect calendar quarters of service, reduced by any interim distribution previously paid to such employee upon the achievement of the interim price goal discussed below. The Committee will allocate to eligible employees in its discretion the pool remaining after making the minimum distributions.
The plan also provides that up to 20%, or $9 million, of the total bonus pool, as determined by the Compensation Committee, will be paid as interim distributions to eligible employees upon achieving the interim price goal of $50 per share prior to December 31, 2009. Interim distributions are determined as described above except that interim distributions will be based on 10%, rather than 50%, of salary.
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| 11. | 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. The Company uses available marketingmarket 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 the Company’s financial position, results of operations or cash flows.
Long-Term Debt
| December 31, 2004 | December 31, 2003 | |||||||||||
(In thousands) | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||
Debt | ||||||||||||
7.19% Notes | $ | 80,000 | $ | 87,770 | $ | 100,000 | $ | 113,673 | ||||
7.26% Notes | 75,000 | 85,849 | 75,000 | 87,345 | ||||||||
7.36% Notes | 75,000 | 87,111 | 75,000 | 87,770 | ||||||||
7.46% Notes | 20,000 | 23,804 | 20,000 | 24,214 | ||||||||
Credit Facility | — | — | — | — | ||||||||
| $ | 250,000 | $ | 284,534 | $ | 270,000 | $ | 313,002 | |||||
| December 31, 2007 | December 31, 2006 | |||||||||||||||
(In thousands) | Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | ||||||||||||
Long-Term Debt | ||||||||||||||||
7.19% Notes | $ | 40,000 | $ | 41,376 | $ | 60,000 | $ | 61,749 | ||||||||
7.26% Notes | 75,000 | 80,066 | 75,000 | 80,335 | ||||||||||||
7.36% Notes | 75,000 | 81,259 | 75,000 | 82,025 | ||||||||||||
7.46% Notes | 20,000 | 21,799 | 20,000 | 22,547 | ||||||||||||
Credit Facility | 140,000 | 140,000 | 10,000 | 10,000 | ||||||||||||
Current Maturities | ||||||||||||||||
7.19% Notes | (20,000 | ) | (20,466 | ) | (20,000 | ) | (20,299 | ) | ||||||||
Long-Term Debt, excluding Current Maturities | $ | 330,000 | $ | 344,034 | $ | 220,000 | $ | 236,357 | ||||||||
The fair value of long-term debt is the estimated cost to acquire the debt, including a premium or discount for the difference between the issue rate and the year end market rate. The fair value of the 7.19% Notes, the 7.26% Notes, the 7.36% Notes and the 7.46% Notes is based on interest rates currently available to the Company. The Credit Facilitycredit facility approximates fair value because this instrument bears interest at rates based on current market rates.
Derivative Instruments and Hedging Activity
The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. Under the Company’s 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, 2004,2007, the Company had 1516 cash flow hedges open: 712 natural gas price collar arrangements, three natural gas swap arrangements and one crude oil collar arrangement and 7 natural gas price swap arrangements. Additionally, the Company had two crude oil financial instruments open at December 31, 2004, that did not qualify for hedge accounting under SFAS 133.arrangement. At December 31, 2004,2007, a $28.8$7.3 million ($17.84.6 million, net of tax) unrealized lossgain was recorded toin Accumulated Other Comprehensive Income, along with a $38.4$12.7 million short-term derivative liabilityreceivable and a $2.9$5.4 million short-term derivative receivable.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 portion, if any, of the change in the fair value of derivatives designated as hedges, and the changeschange 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,Revenue, as appropriate.
The following table summarizes the realized During 2007 and unrealized impact of derivative activity reflected2006, there was no ineffectiveness recorded in the respective line itemConsolidated Statement of Operations. For the year ended December 31, 2005, a $6.6 million gain was recorded as a component of revenue, which reflected the ineffective portion of the change in Operating Revenues.
| Year Ended December 31, | ||||||||||||||||||||||||
| 2004 | 2003 | 2002 | ||||||||||||||||||||||
(In thousands) | Realized | Unrealized | Realized | Unrealized | Realized | Unrealized | ||||||||||||||||||
Operating Revenues -Increase / (Decrease) to Revenue | ||||||||||||||||||||||||
Natural Gas Production | $ | (55,008 | ) | $ | 914 | $ | (48,829 | ) | $ | (1,468 | ) | $ | (574 | ) | $ | (1,683 | ) | |||||||
Crude Oil | (17,908 | ) | (2,917 | ) | (3,963 | ) | (1,879 | ) | (5,202 | ) | (693 | ) | ||||||||||||
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, 20042007 the Company would expect to reclassify to earnings,the Consolidated Statement of Operations, over the next 12 months, $17.8$4.6 million in after-tax expendituresincome associated with commodity derivatives.hedges. This reclassification represents the net liabilityshort-term receivable associated with open positions currently not reflected in earnings at December 31, 20042007 related to anticipated 20052008 production.
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Hedges on Production -– Swaps
From time to time, the Company enters into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of its production. These derivativescash flow hedges are not held for trading purposes. Under these price swaps, the Company receives a fixed price on a notional quantity of natural gas andor crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. UnderDuring 2007, the Company’s Revolving Credit Agreement, the aggregate level of commodity hedging mustCompany did not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. During 2004,enter into any natural gas price swaps covered 29,617 Mmcf, or 41% of the Company’s gas production, fixing the sales price of this gas at an average of $5.04 per Mcf.
covering its 2007 production.
At December 31, 2004,2007, the Company had open natural gas price swap contracts covering a portion of its 20052008 production as follows:
| Natural Gas Price Swaps | |||||||||
Contract Period | Volume in Mmcf | Weighted Average Contract Price | Unrealized Gain /(Loss) (In thousands) | ||||||
As of December 31, 2004 | |||||||||
Natural Gas Price Swaps on Production in: | |||||||||
First Quarter 2005 | 5,069 | $ | 5.14 | ||||||
Second Quarter 2005 | 5,125 | 5.14 | |||||||
Third Quarter 2005 | 5,181 | 5.14 | |||||||
Fourth Quarter 2005 | 5,181 | 5.14 | |||||||
Full Year 2005 | 20,556 | $ | 5.14 | $ | (27,897 | ) | |||
From time to time the Company enters into natural gas and crude oil derivative arrangements that do not qualify for hedge accounting under SFAS 133. These financial instruments are recorded at fair value at the balance sheet date. At December 31, 2004, the Company had two open crude oil swap arrangements with an unrealized net loss of $5.5 million recognized in Operating Revenues.
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| Natural Gas Price Swaps | ||||||||
Contract Period | Volume in Mmcf | Weighted-Average Contract Price (per Mcf) | Net Unrealized Gain (In thousands) | |||||
As of December 31, 2007 | ||||||||
First Quarter 2008 | 1,233 | $ | 7.44 | |||||
Second Quarter 2008 | 1,233 | 7.44 | ||||||
Third Quarter 2008 | 1,246 | 7.44 | ||||||
Fourth Quarter 2008 | 1,246 | 7.44 | ||||||
Full Year 2008 | 4,958 | $ | 7.44 | $ | 472 | |||
Hedges on Production -– Options
From time to time, the Company enters into natural gas and crude oil collar agreements with counterparties to hedge price risk associated with a portion of its production. These cash flow hedges are not held for trading purposes. Under the collar arrangements, if the index price rises above the ceiling price, the Company pays the counterparty. If the index price falls below the floor price, the counterparty pays the Company. During 2004,2007, natural gas price collars covered 22,95442,533 Mmcf of the Company’s gas production, or 32%53% of the Company’s gas production with a weighted averageweighted-average floor of $4.78$8.99 per Mcf and a weighted averageweighted-average ceiling of $6.06$12.19 per Mcf.
At December 31, 2004,2007, the Company had open natural gas price collar contracts covering a portion of its 20052008 production as follows:
| Natural Gas Price Collars | |||||||||
Contract Period | Volume in Mmcf | Weighted Average Ceiling /Floor | Unrealized Gain / (Loss) (In thousands) | ||||||
As of December 31, 2004 | |||||||||
First Quarter 2005 | 4,982 | $ | 9.09 /$6.16 | ||||||
Second Quarter 2005 | 3,367 | 8.38 / 5.30 | |||||||
Third Quarter 2005 | 3,404 | 8.38 / 5.30 | |||||||
Fourth Quarter 2005 | 3,404 | 8.38 / 5.30 | |||||||
Full Year 2005 | 15,157 | $ | 8.61 /$5.59 | $ | (2,500 | ) | |||
| Natural Gas Price Collars | ||||||||
Contract Period | Volume in Mmcf | Weighted-Average Ceiling / Floor (per Mcf) | Net Unrealized Gain (In thousands) | |||||
As of December 31, 2007 | ||||||||
First Quarter 2008 | 8,523 | $ | 10.14 / $8.17 | |||||
Second Quarter 2008 | 8,523 | 10.14 / 8.17 | ||||||
Third Quarter 2008 | 8,617 | 10.14 / 8.17 | ||||||
Fourth Quarter 2008 | 8,617 | 10.14 / 8.17 | ||||||
Full Year 2008 | 34,280 | $ | 10.14 / $8.17 | $ | 12,072 | |||
During 2007, an oil price collar covered 365 Mbbls of the Company’s crude oil production, or 44% of its crude oil production, with a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl.
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At December 31, 2004, we2007, the Company had one open crude oil price collar contract covering our 2005a portion of its 2008 production as follows:
| Crude Oil Price Collar | ||||||||
Contract Period | Volume in Mbbl | Weighted Average Ceiling /Floor | Unrealized Gain /(Loss) (In thousands) | |||||
As of December 31, 2004 | ||||||||
First Quarter 2005 | 90 | $ | 50.50 /$40.00 | |||||
Second Quarter 2005 | 91 | 50.50 / 40.00 | ||||||
Third Quarter 2005 | 92 | 50.50 / 40.00 | ||||||
Fourth Quarter 2005 | 92 | 50.50 / 40.00 | ||||||
Full Year 2005 | 365 | $ | 50.50 /$40.00 | $ | 454 | |||
| Crude Oil Price Collars | |||||||||
Contract Period | Volume in Mbbl | Ceiling / Floor (per Bbl) | Net Unrealized Loss (In thousands) | ||||||
As of December 31, 2007 | |||||||||
First Quarter 2008 | 91 | $ | 80.00 / $60.00 | ||||||
Second Quarter 2008 | 91 | 80.00 / 60.00 | |||||||
Third Quarter 2008 | 92 | 80.00 / 60.00 | |||||||
Fourth Quarter 2008 | 92 | 80.00 / 60.00 | |||||||
Full Year 2008 | 366 | $ | 80.00 / $60.00 | $ | (5,272 | ) | |||
The Company is 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.
Credit Risk
Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.
In 2004,2007 and 2006, no customer accounted for more than 10% of the Company’s total sales. In 2005, approximately 11% of the Company’s total sales were made to one customer. In 2003 and 2002, approximately 11% and 14%, respectively, of our total sales were made to one customer. In 2002, this customer operated certain properties in which we have interests in the Gulf Coast and purchased all of the production from these wells. This customer would resell the natural gas and oil to third parties with whom we would deal directly if the customer either ceased to exist or stopped buying our portion of the production.
| 12. | Asset Retirement Obligations |
- 82 -
12. Adoption of SFAS 143, “Accounting for Asset Retirement Obligations”
Effective January 1, 2003 theThe Company adopted SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 requires thatrecords the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the assets useful life. The adoption of SFAS 143 resulted in an increase of total liabilities because additional retirement obligations are required to be recognized, an increase in the recognized cost of assets because the retirement costs are added to the carrying amount of the long-lived asset and an increase in operating expense because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities willare also be recorded for meter stations, pipelines, processing plants and compressors. At December 31, 20042007, there arewere no assets legally restricted for purposes of settling asset retirement obligations. The Company recorded a net-of-tax charge for the cumulative effect of change in accounting principle loss, in January of 2003, of approximately $6.8 million ($11.0 million before tax) and recorded a retirement obligation of approximately $35.2 million. There will be no impact on the Company’s cash flows as a result of adopting SFAS 143.
Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense for the yearyears ended December 31, 20042007, 2006 and 2005 was $1.7 million. Accretion$1.1 million, $1.4 million and $1.4 million, respectively, and was included within Depreciation, Depletion and Amortization expense foron the year ended December 31, 2003 was $2.1 million.
Company’s Consolidated Statement of Operations.
The following table reflects the changes of the asset retirement obligations during the current period.
(In thousands)
| ||||
Carrying amount of asset retirement obligations at December 31, 2003 | $ | 36,848 | ||
Liabilities added during the current period | 2,316 | |||
Liabilities settled during the current period | (520 | ) | ||
Current period accretion expense | 1,731 | |||
Revisions to estimated cash flows | — | |||
Carrying amount of asset retirement obligations at December 31, 2004 | $ | 40,375 | ||
If SFAS 143 had been adopted on January 1, 2002, pro forma net income would have been approximately $15.1 million, pro forma basic earnings per share would have been $0.48 and pro forma diluted earnings per share would have been $0.47. These pro forma figures are unaudited.
13. Section 29 Tax Credits
Other revenue includes income generated from the monetization of the value of Section 29 tax credits (monetized credits) from most of the Company’s qualifying East and Rocky Mountains properties. The tax credit wells were repurchased in December 2002 and no tax credits were generated in 2003 or 2004 as the credits expired in 2002. Revenue from these monetized credits was $2.0 million in 2002. The production, revenues, expenses and proved reserves for these properties was reported by the Company as Other Revenue until the credits were repurchased in December 2002. In this repurchase transaction, the Company acquired 26 Bcfe for $7 million, or $0.27 per Mcfe. The effective date of the repurchase was December 31, 2002.
(In thousands) | ||||
Carrying amount of asset retirement obligations at December 31, 2006 | $ | 22,655 | ||
Liabilities added during the current period | 1,565 | |||
Liabilities settled and divested during the current period | (553 | ) | ||
Current period accretion expense | 1,057 | |||
Carrying amount of asset retirement obligations at December 31, 2007 | $ | 24,724 | ||
- 83107 -
14. Earnings per Common Share
| 13. | Earnings per Common Share |
Basic earnings per common share (EPS) is computed by dividing net income (the numerator) by the weighted averageweighted-average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated using the treasury stock method except that the denominator is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock options and stock awards outstanding at the end of the applicable period were exercised for common stock.
The following is a calculation of basic and diluted weighted averageweighted-average shares outstanding for the yearyears ended December 31, 2004, 20032007, 2006 and 2002:2005:
| December 31, | ||||||
| 2004 | 2003 | 2002 | ||||
Shares - basic | 32,488,336 | 32,049,664 | 31,736,975 | |||
Dilution effect of stock options and awards at end of period | 404,198 | 240,621 | 338,972 | |||
Shares - diluted | 32,892,534 | 32,290,285 | 32,075,947 | |||
Stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect | — | 965,777 | 1,174,507 | |||
| December 31, | ||||||
| 2007 | 2006 | 2005 | ||||
Weighted-Average Shares - Basic | 96,977,634 | 96,803,283 | 97,712,982 | |||
Dilution Effect of Stock Options and Awards at End of Period | 1,152,673 | 1,797,700 | 1,737,808 | |||
Weighted-Average Shares - Diluted | 98,130,307 | 98,600,983 | 99,450,790 | |||
Weighted-Average Stock Awards and Shares Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect | 21,639 | — | — | |||
15. Subsequent Event-Stock Split- 108 -
| 14. | Accumulated Other Comprehensive Income |
On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split on the Company’s Common StockChanges in the formcomponents of a stock distribution. The stock dividend will be distributed on March 31, 2005 to shareholdersaccumulated other comprehensive income / (loss), net of record on March 18, 2005. In lieu of issuing fractional shares,taxes, for the Company will pay cash based on the closing price of the Common stock on the record date. The pro forma effect on theyears ended December 31, 2004 balance sheet is to reduce Additional Paid-in-Capital by $1.6 million2007, 2006 and increase Common Stock by $1.6 million. Common shares outstanding, giving retroactive effect to the stock split at December 31, 2004 and 2003 would have been 48.6 million and 48.4 million, respectively. Pro forma earnings per share, giving retrospective effect to the stock split is2005 were as follows:
| December 31, | |||||||||
| 2004 | 2003 | 2002 | |||||||
Basic Earnings per Share – as reported (pre-stock split) | $ | 2.72 | $ | 0.66 | $ | 0.51 | |||
Basic Earnings per Share – pro forma (post-stock split) | 1.81 | 0.44 | 0.34 | ||||||
Diluted Earnings per Share – as reported (pre-stock split) | 2.69 | 0.65 | 0.50 | ||||||
Diluted Earnings per Share – pro forma (post-stock split) | 1.79 | 0.43 | 0.33 | ||||||
Accumulated Other Comprehensive Income / (Loss)(In thousands) | Net Gains / (Losses) on Cash Flow Hedges | Defined Benefit Pension and Postretirement Plans | Foreign Currency Translation Adjustment | Total | ||||||||||||
Balance at December 31, 2004 | $ | (17,843 | ) | $ | (3,042 | ) | $ | 534 | $ | (20,351 | ) | |||||
Net change in unrealized gains on cash flow hedges, net of taxes of $(3,111) | 4,983 | — | — | 4,983 | ||||||||||||
Net change in minimum pension liability, net of taxes of $77 | — | (128 | ) | — | (128 | ) | ||||||||||
Change in foreign currency translation adjustment, net of taxes of $(427) | — | — | 381 | 381 | ||||||||||||
Balance at December 31, 2005 | $ | (12,860 | ) | $ | (3,170 | ) | $ | 915 | $ | (15,115 | ) | |||||
Net change in unrealized gains on cash flow hedges, net of taxes of $(38,625) | 64,099 | — | — | 64,099 | ||||||||||||
Net change in minimum pension liability, net of taxes of $(1,848) | — | 3,081 | — | 3,081 | ||||||||||||
Effect of adoption of SFAS No. 158, net of taxes of $8,447 | — | (14,079 | ) | — | (14,079 | ) | ||||||||||
Change in foreign currency translation adjustment, net of taxes of $507 | — | — | (826 | ) | (826 | ) | ||||||||||
Balance at December 31, 2006 | $ | 51,239 | $ | (14,168 | ) | $ | 89 | $ | 37,160 | |||||||
Net change in unrealized gains on cash flow hedges, net of taxes of $28,024 | (46,686 | ) | — | — | (46,686 | ) | ||||||||||
Net change in defined benefit pension and postretirement plans, net of taxes of $(100) | — | 141 | — | 141 | ||||||||||||
Change in foreign currency translation adjustment, net of taxes of $(5,072) | — | — | 8,491 | 8,491 | ||||||||||||
Balance at December 31, 2007 | $ | 4,553 | $ | (14,027 | ) | $ | 8,580 | $ | (894 | ) | ||||||
- 84109 -
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Gas Reserves
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made.
Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.
Estimates of proved and proved developed reserves at December 31, 2004, 2003,2007, 2006, and 20022005 were based on studies performed by the Company’s petroleum engineering staff. The estimates were computed based on year end prices for oil, natural gas, and natural gas liquids. The estimates were reviewed by Miller and Lents, Ltd., who indicated in their letter dated February 7, 2005,6, 2008, that based on their investigation and subject to the limitations described in their letter, they believe the results of those estimates and projections were reasonable in the aggregate.
No major discovery or other favorable or unfavorable event after December 31, 2004,2007, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
The following table illustrates the Company’s net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by the Company’s engineering staff.
| Natural Gas | Natural Gas | |||||||||||||||||
| December 31, | December 31, | |||||||||||||||||
(Millions of cubic feet) | 2004 | 2003 | 2002 | 2007 | 2006 | 2005 | ||||||||||||
Proved Reserves | ||||||||||||||||||
Beginning of Year | 1,069,484 | 1,060,959 | 1,036,004 | 1,368,293 | 1,262,096 | 1,134,081 | ||||||||||||
Revisions of Prior Estimates | (7,850 | ) | (6,122 | ) | 14,405 | 2,604 | (17,675 | ) | (1,543 | ) | ||||||||
Extensions, Discoveries and Other Additions | 140,986 | 105,497 | 64,945 | 265,830 | 246,197 | 185,884 | ||||||||||||
Production | (72,833 | ) | (71,906 | ) | (73,670 | ) | (80,475 | ) | (79,722 | ) | (73,879 | ) | ||||||
Purchases of Reserves in Place | 5,384 | 1,590 | 26,262 | 3,701 | 1,946 | 17,567 | ||||||||||||
Sales of Reserves in Place | (1,090 | ) | (20,534 | ) | (6,987 | ) | — | (44,549 | ) | (14 | ) | |||||||
End of Year | 1,134,081 | 1,069,484 | 1,060,959 | 1,559,953 | 1,368,293 | 1,262,096 | ||||||||||||
Proved Developed Reserves | 857,834 | 812,280 | 819,412 | 1,133,937 | 996,850 | 944,897 | ||||||||||||
Percentage of Reserves Developed | 75.6 | % | 76.0 | % | 77.2 | % | 72.7 | % | 72.9 | % | 74.9 | % | ||||||
- 85110 -
| Liquids | |||||||||
| December 31, | |||||||||
(Thousands of barrels) | 2004 | 2003 | 2002 | ||||||
Proved Reserves | |||||||||
Beginning of Year | 12,103 | 18,393 | 19,684 | ||||||
Revisions of Prior Estimates | 185 | 307 | 1,871 | ||||||
Extensions, Discoveries and Other Additions | 1,074 | 1,723 | 851 | ||||||
Production | (2,002 | ) | (2,846 | ) | (2,909 | ) | |||
Purchases of Reserves in Place | 24 | — | 261 | ||||||
Sales of Reserves in Place | — | (5,474 | ) | (1,365 | ) | ||||
End of Year | 11,384 | 12,103 | 18,393 | ||||||
Proved Developed Reserves | 8,652 | 9,405 | 13,267 | ||||||
Percentage of Reserves Developed | 76.0 | % | 77.7 | % | 72.1 | % | |||
| Liquids | |||||||||
| December 31, | |||||||||
(Thousands of barrels) | 2007 | 2006 | 2005 | ||||||
Proved Reserves | |||||||||
Beginning of Year | 7,973 | 11,463 | 11,384 | ||||||
Revisions of Prior Estimates | 771 | 673 | 1,073 | ||||||
Extensions, Discoveries and Other Additions | 1,381 | 1,066 | 334 | ||||||
Production | (830 | ) | (1,415 | ) | (1,747 | ) | |||
Purchases of Reserves in Place | 33 | 38 | 419 | ||||||
Sales of Reserves in Place | — | (3,852 | ) | — | |||||
End of Year | 9,328 | 7,973 | 11,463 | ||||||
Proved Developed Reserves | 7,026 | 5,895 | 9,127 | ||||||
Percentage of Reserves Developed | 75.3 | % | 73.9 | % | 79.6 | % | |||
Capitalized Costs Relating to Oil and Gas Producing Activities
The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization.
| December 31, | |||||||||
(In thousands) | 2004 | 2003 | 2002 | ||||||
Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities | $ | 1,933,848 | $ | 1,732,236 | $ | 1,704,746 | |||
Aggregate Accumulated Depreciation, Depletion and Amortization | 940,447 | 837,060 | 750,857 | ||||||
| December 31, | |||||||||
(In thousands) | 2007 | 2006 | 2005 | ||||||
Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities | $ | 3,007,849 | $ | 2,462,693 | $ | 2,290,147 | |||
Aggregate Accumulated Depreciation, Depletion and Amortization | 1,100,369 | 983,079 | 1,052,654 | ||||||
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities were as follows:
| Year Ended December 31, | |||||||||
(In thousands) | 2004 | 2003 | 2002 | ||||||
Property Acquisition Costs, Proved | $ | 3,953 | $ | 1,524 | $ | 8,799 | |||
Property Acquisition Costs, Unproved | 18,250 | 14,056 | 4,869 | ||||||
Exploration and Extension Well Costs(1) | 85,415 | 83,147 | 52,012 | ||||||
Development Costs | 136,311 | 77,006 | 55,165 | ||||||
Total Costs | $ | 243,929 | $ | 175,733 | $ | 120,845 | |||
| Year Ended December 31, | |||||||||
(In thousands) | 2007 | 2006 | 2005 | ||||||
Property Acquisition Costs, Proved | $ | 3,982 | $ | 6,688 | $ | 73,127 | |||
Property Acquisition Costs, Unproved | 22,186 | 42,551 | 22,126 | ||||||
Exploration Costs(1) | 70,242 | 109,525 | 102,957 | ||||||
Development Costs | 494,204 | 346,787 | 208,124 | ||||||
Total Costs | $ | 590,614 | $ | 505,551 | $ | 406,334 | |||
(1) | Includes administrative exploration costs of |
- 86111 -
Historical Results of Operations from Oil and Gas Producing Activities
The results of operations for the Company’s oil and gas producing activities were as follows:
| Year Ended December 31, | |||||||||
(In thousands) | 2004 | 2003 | 2002 | ||||||
Operating Revenues | $ | 439,988 | $ | 404,503 | $ | 280,379 | |||
Costs and Expenses | |||||||||
Production | 84,015 | 77,315 | 63,823 | ||||||
Other Operating | 27,787 | 20,090 | 21,731 | ||||||
Exploration(1) | 48,130 | 58,119 | 40,167 | ||||||
Depreciation, Depletion and Amortization | 114,906 | 195,659 | 102,086 | ||||||
Total Costs and Expenses | 274,838 | 351,183 | 227,807 | ||||||
Income Before Income Taxes | 165,150 | 53,320 | 52,572 | ||||||
Provision for Income Taxes | 60,361 | 18,662 | 18,400 | ||||||
Results of Operations | $ | 104,789 | $ | 34,658 | $ | 34,172 | |||
| Year Ended December 31, | |||||||||
(In thousands) | 2007 | 2006 | 2005 | ||||||
Operating Revenues | $ | 637,195 | $ | 659,884 | $ | 581,849 | |||
Costs and Expenses | |||||||||
Production | 116,020 | 115,786 | 103,477 | ||||||
Other Operating | 40,620 | 46,212 | 30,120 | ||||||
Exploration(1) | 39,772 | 49,397 | 61,840 | ||||||
Depreciation, Depletion and Amortization | 140,957 | 124,204 | 106,156 | ||||||
Impairment of Unproved Properties | 19,042 | 11,117 | 12,966 | ||||||
Impairment of Oil & Gas Properties | 4,614 | 3,886 | — | ||||||
Total Costs and Expenses | 361,025 | 350,602 | 314,559 | ||||||
Income Before Income Taxes | 276,170 | 309,282 | 267,290 | ||||||
Provision for Income Taxes | 100,755 | 113,355 | 100,353 | ||||||
Results of Operations | $ | 175,415 | $ | 195,927 | $ | 166,937 | |||
(1) | Includes administrative exploration costs of |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information has been developed utilizing SFAS No. 69,“Disclosures about Oil and Gas Producing Activities”, procedures and based on natural gas and crude oil reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account when reviewing the following information:
Future costs and selling prices will probably differ from those required to be used in these calculations.
Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations.
Selection of a 10% discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues.
Future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by applying year end oil and gas prices to the estimated future production of year end proved reserves.
The average prices related to proved reserves at December 31, 2004, 2003,2007, 2006, and 20022005 for natural gas ($ per Mcf) were $6.26, $5.96,$6.91, $5.54 and $4.41,$9.53, respectively, and for oil ($ per Bbl) were $41.24, $30.94,$94.94, $59.50 and $30.39,$58.48, respectively. Future cash inflows were reduced by estimated future development and production costs based on year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved. SFAS No. 69 requires the use of a 10% discount rate.
Management does not use only the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.
- 87112 -
Standardized Measure is as follows:
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
(In thousands) | 2004 | 2003 | 2002 | 2007 | 2006 | 2005 | ||||||||||||||||||
Future Cash Inflows | $ | 7,561,728 | $ | 6,742,214 | $ | 5,236,349 | $ | 11,671,078 | $ | 8,054,737 | $ | 12,700,390 | ||||||||||||
Future Production Costs | (1,577,787 | ) | (1,390,398 | ) | (1,137,615 | ) | (2,690,695 | ) | (2,000,993 | ) | (2,271,917 | ) | ||||||||||||
Future Development Costs | (396,431 | ) | (310,923 | ) | (284,165 | ) | (909,374 | ) | (688,955 | ) | (536,333 | ) | ||||||||||||
Future Income Tax Expenses | (2,009,644 | ) | (1,800,519 | ) | (1,195,082 | ) | (2,684,271 | ) | (1,763,458 | ) | (3,588,877 | ) | ||||||||||||
Future Net Cash Flows | 3,577,866 | 3,240,374 | 2,619,487 | 5,386,738 | 3,601,331 | 6,303,263 | ||||||||||||||||||
10% Annual Discount for Estimated Timing of Cash Flows | (1,997,509 | ) | (1,760,966 | ) | (1,364,134 | ) | (3,216,087 | ) | (2,125,081 | ) | (3,652,030 | ) | ||||||||||||
Standardized Measure of Discounted Future Net Cash Flows | $ | 1,580,357 | $ | 1,479,408 | $ | 1,255,353 | $ | 2,170,651 | $ | 1,476,250 | $ | 2,651,233 | ||||||||||||
(1) | The standardized measures of discounted future net cash flows before taxes were $3,007,661, $2,010,228 and $4,001,769 for the years ended December 31, 2007, 2006 and 2005, respectively. |
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure:
| Year Ended December 31, | ||||||||||||
(In thousands) | 2004 | 2003 | 2002 | |||||||||
Beginning of Year | $ | 1,479,408 | $ | 1,255,353 | $ | 766,026 | ||||||
Discoveries and Extensions, | ||||||||||||
Net of Related Future Costs | 321,026 | 235,079 | 112,269 | |||||||||
Net Changes in Prices and Production Costs | (17,976 | ) | 475,026 | 703,874 | ||||||||
Accretion of Discount | 219,604 | 171,590 | 95,110 | |||||||||
Revisions of Previous Quantity Estimates, Timing and Other | (46,115 | ) | (35,691 | ) | 51,944 | |||||||
Development Costs Incurred | 32,940 | 27,529 | 20,516 | |||||||||
Sales and Transfers, Net of Production Costs | (357,939 | ) | (330,800 | ) | (216,555 | ) | ||||||
Net Purchases (Sales) of Reserves in Place | 10,853 | (62,596 | ) | (2,357 | ) | |||||||
Net Change in Income Taxes | (61,444 | ) | (256,082 | ) | (275,474 | ) | ||||||
End of Year | $ | 1,580,357 | $ | 1,479,408 | $ | 1,255,353 | ||||||
| Year Ended December 31, | ||||||||||||
(In thousands) | 2007 | 2006 | 2005 | |||||||||
Beginning of Year | $ | 1,476,250 | $ | 2,651,233 | $ | 1,580,357 | ||||||
Discoveries and Extensions, Net of Related Future Costs | 430,918 | 278,258 | 494,773 | |||||||||
Net Changes in Prices and Production Costs | 864,630 | (1,843,272 | ) | 1,278,303 | ||||||||
Accretion of Discount | 201,023 | 400,177 | 235,843 | |||||||||
Production, Timing and Other | (122,908 | ) | (106,253 | ) | (49,550 | ) | ||||||
Development Costs Incurred | 136,781 | 85,993 | 61,802 | |||||||||
Sales and Transfers, Net of Production Costs | (521,558 | ) | (544,650 | ) | (471,638 | ) | ||||||
Net Purchases / (Sales) of Reserves in Place | 8,548 | (261,795 | ) | 91,180 | ||||||||
Net Change in Income Taxes | (303,033 | ) | 816,559 | (569,837 | ) | |||||||
End of Year | $ | 2,170,651 | $ | 1,476,250 | $ | 2,651,233 | ||||||
- 88113 -
SELECTED DATA (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(In thousands, except per share amounts) | First | Second | Third | Fourth | Total | |||||||||||
2004 | ||||||||||||||||
Operating Revenues | $ | 136,604 | $ | 119,742 | $ | 119,423 | $ | 154,639 | $ | 530,408 | ||||||
Impairment of Oil and Gas Properties | — | — | 3,458 | — | 3,458 | |||||||||||
Operating Income | 36,090 | 36,439 | 34,278 | 53,846 | 160,653 | |||||||||||
Income Before Cumulative Effect of Accounting Change | 19,011 | 19,318 | 17,822 | 32,227 | 88,378 | |||||||||||
Net Income | 19,011 | 19,318 | 17,822 | 32,227 | 88,378 | |||||||||||
Basic Earnings per Share -Before Accounting Change | $ | 0.59 | $ | 0.59 | $ | 0.55 | $ | 0.99 | $ | 2.72 | ||||||
Diluted Earnings per Share -Before Accounting Change | $ | 0.58 | $ | 0.59 | $ | 0.54 | $ | 0.98 | $ | 2.69 | ||||||
Basic Earnings per Share | $ | 0.59 | $ | 0.59 | $ | 0.55 | $ | 0.99 | $ | 2.72 | ||||||
Diluted Earnings per Share | $ | 0.58 | $ | 0.59 | $ | 0.54 | $ | 0.98 | $ | 2.69 | ||||||
2003 | ||||||||||||||||
Operating Revenues | $ | 135,916 | $ | 126,756 | $ | 125,471 | $ | 121,248 | $ | 509,391 | ||||||
Impairment of Oil and Gas Properties | 87,926 | — | 5,870 | — | 93,796 | |||||||||||
Operating Income (Loss) | (46,691 | ) | 34,850 | 43,630 | 34,798 | 66,587 | ||||||||||
Income (Loss) Before Cumulative Effect of Accounting Change | (32,376 | ) | 17,904 | 23,220 | 19,231 | 27,979 | ||||||||||
Net Income (Loss)(1) | (39,223 | ) | 17,904 | 23,220 | 19,231 | 21,132 | ||||||||||
Basic Earnings (Loss) per Share -Before Accounting Change(1) | $ | (1.02 | ) | $ | 0.56 | $ | 0.73 | $ | 0.60 | $ | 0.87 | |||||
Diluted Earnings (Loss) per Share -Before Accounting Change(1) | $ | (1.02 | ) | $ | 0.55 | $ | 0.73 | $ | 0.60 | $ | 0.87 | |||||
Basic Earnings (Loss) per Share(1) | $ | (1.23 | ) | $ | 0.56 | $ | 0.73 | $ | 0.60 | $ | 0.66 | |||||
Diluted Earnings (Loss) per Share(1) | $ | (1.23 | ) | $ | 0.55 | $ | 0.73 | $ | 0.60 | $ | 0.65 | |||||
(In thousands, except per share amounts) | First | Second | Third | Fourth | Total | ||||||||||
2007 | |||||||||||||||
Operating Revenues | $ | 191,573 | $ | 175,832 | $ | 170,848 | $ | 193,917 | $ | 732,170 | |||||
Impairment of Oil and Gas Properties(1) | — | — | 4,614 | — | 4,614 | ||||||||||
Operating Income(2) | 79,185 | 70,245 | 55,521 | 69,742 | 274,693 | ||||||||||
Net Income(2) | 48,547 | 41,376 | 35,453 | 42,047 | 167,423 | ||||||||||
Basic Earnings per Share | 0.50 | 0.43 | 0.37 | 0.43 | 1.73 | ||||||||||
Diluted Earnings per Share | 0.50 | 0.42 | 0.36 | 0.43 | 1.71 | ||||||||||
2006 | |||||||||||||||
Operating Revenues | $ | 214,768 | $ | 190,794 | $ | 184,744 | $ | 171,682 | $ | 761,988 | |||||
Impairment of Oil and Gas Properties(1) | — | — | — | 3,886 | 3,886 | ||||||||||
Operating Income(2) (3) | 91,224 | 77,881 | 304,746 | 55,095 | 528,946 | ||||||||||
Net Income(2) | 53,165 | 46,864 | 189,020 | 32,126 | 321,175 | ||||||||||
Basic Earnings per Share(4) | 0.55 | 0.48 | 1.96 | 0.33 | 3.32 | ||||||||||
Diluted Earnings per Share(4) | 0.54 | 0.47 | 1.92 | 0.33 | 3.26 | ||||||||||
(1) | For discussion of impairment of oil and gas properties, refer to Note 2 of the Notes to the Consolidated Financial Statements. |
(2) | Operating Income and Net |
(3) | Included in Operating Income in the first quarter is the cumulative effect loss of $0.4 million, previously reported in |
(4) | All earnings per share figures have been |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
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ITEM 9A. CONTROLS AND PROCEDURES
| ITEM 9A. | CONTROLS AND PROCEDURES |
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Changes in Internal Control over Financial Reporting
As of the end of December 31, 2004,2007, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are
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effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the issuerCompany in the reports that it files or submits under the Exchange Act.
There were no significant changes in the Company’s internal control over financial reporting that occurred during the fourth quarter that has materially affected, or is reasonably likely to materially effect, the Company’s internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
The management of Cabot Oil & Gas Corporation is responsible for establishing and maintaining adequate internal control over financial reporting. Cabot Oil & Gas Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Cabot Oil & Gas Corporation’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004.2007. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we have concluded that, as of December 31, 2004,2007, the Company’s internal control over financial reporting is effective based on those criteria.
The effectiveness of Cabot Oil & Gas Corporation’s independent registered public accounting firm has audited management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 20042007, has been audited by Pricewaterhouse Coopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. This report appears on page 50.
| ITEM 9B. | OTHER INFORMATION |
None.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
The information under the caption “Election of Directors”, “Audit Committee” and “Code of Business Conduct” inrequired by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20052008 annual stockholders’ meetingmeeting. In addition, the information set forth under the caption “Business-Other Business Matters-Corporate Governance Matters” in Item 1 regarding our Code of Business Conduct is incorporated by reference.reference in response to this Item.
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ITEM 11. EXECUTIVE COMPENSATION
| ITEM 11. | EXECUTIVE COMPENSATION |
The information under the caption “Executive Compensation” inrequired by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20052008 annual stockholders’ meeting is incorporated by reference.meeting.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The information under the captions “Beneficial Ownership of Over Five Percent of Common Stock”, “Beneficial Ownership of Directors and Executive Officers”, and “Equity Compensation Plan Information” inrequired by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20052008 annual stockholders’ meetingmeeting.
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| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
The information required by this Item is incorporated by reference.reference to the Company’s definitive Proxy Statement in connection with the 2008 annual stockholders’ meeting.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
| ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The information under the caption “Fees Billedrequired by Independent Registered Public Accounting Firm for Services in 2003 and 2002” inthis Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 20052008 annual stockholders’ meeting is incorporated by reference.
meeting.
| ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
A. INDEX
| A. | INDEX |
| 1. | Consolidated Financial Statements |
See Index on page 49.62.
| 2. | Financial Statement Schedules |
None.
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3. Exhibits
| 3. | Exhibits |
The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.
Exhibit
| Description | |
| 3.1 | Certificate of Incorporation of the Company (Registration Statement No. 33-32553). | |
| 3.2 | Amended and Restated Bylaws of the Company amended | |
| 3.3 | Certificate of Amendment of Certificate of Incorporation (Form 8-K for July | |
| 3.4 | Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock (Form 8-K for July | |
| 3.5 | Certificate of Amendment of Certificate of Incorporation (Form 8-K for June 1, 2006). | |
| 3.6 | Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock (Form 8-K for June 1, 2006). | |
| 4.1 | Form of Certificate of Common Stock of the Company (Registration Statement No. 33-32553). | |
| 4.2 | Certificate of Designation for Series A Junior Participating Preferred Stock (Form 10-K for 1994). | |
| 4.3 | Rights Agreement dated as of March 28, 1991, between the Company and The First National Bank of Boston, as Rights Agent, which includes as Exhibit A the form of Certificate of Designation of Series A Junior Participating Preferred Stock (Form 8-A, File No. 1-10477). | |
(a) Amendment No. 1 to the Rights Agreement dated February 24, 1994 (Form 10-K for 1994). | ||
(b) Amendment No. 2 to the Rights Agreement dated December 8, 2000 (Form 8-K for December 21, 2000). | ||
| (c) Amendment to the Rights Agreement dated January 1, 2003 (The Bank of New York as rights agent) (Form 10-Q for the quarter ended March 31, 2007). | ||
| (d) Amendment to the Rights Agreement dated March 30, 2007 (regarding uncertified shares) (Form 10-Q for the quarter ended March 31, 2007). | ||
| 4.4 | Certificate of Designation for 6% Convertible Redeemable Preferred Stock (Form 10-K for 1994). | |
| 4.5 | Amended and Restated Credit Agreement dated as of May 30, 1995, among the Company, Morgan Guaranty Trust Company, as agent and the banks named | |
(a) Amendment No. 1 to Credit Agreement dated September 15, 1995 (Form 10-K for 1995). | ||
(b) Amendment No. 2 to Credit Agreement dated December 24, 1996 (Form 10-K for 1996). | ||
| Note Purchase Agreement dated November 14, 1997, among the Company and the purchasers named therein (Form 10-K for 1997). | ||
| Note Purchase Agreement dated as of July 26, 2001 among Cabot Oil & Gas Corporation and the Purchasers listed therein (Form 8-K for August 30, 2001). | ||
| Credit Agreement dated as of October 28, 2002 among the Company, the Banks Parties Hereto and Fleet National Bank, as administrative agent (Form 10-Q for the quarter ended September 30, 2002). | ||
(a) Amendment No. 1 to Credit Agreement dated December 10, | ||
| Form of Change in Control Agreement between the Company and Certain Officers (Form 10-K for 2001). | ||
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|
| |
| ||
| ||
| ||
| ||
| Supplemental Executive Retirement Agreements of the Company (Form 10-K for 1991). | ||
| 1990 Non-employee Director Stock Option Plan of the Company (Form S-8 dated June 23, 1990). | ||
(a) First Amendment to 1990 Non-employee Director Stock Option Plan (Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994). | ||
(b) Second Amendment to 1990 Non-employee Director Stock Option Plan (Form 10-K for 1995). | ||
| Second Amended and Restated 1994 Long-Term Incentive Plan of the Company (Form 10-K for 2001) | ||
| Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form 10-K for 2001). | ||
| Form of Indemnity Agreement between the Company and Certain Officers (Form 10-K for 1997). | ||
| Deferred Compensation Plan of the Company as Amended September 1, 2001 (Form 10-K for 2001). | ||
| Trust Agreement dated September 2000 between Harris Trust and Savings Bank and the Company (Form 10-K for 2001). | ||
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Exhibit | Description | |
| 10.9 | Lease Agreement between the Company and DNA COG, Ltd. dated April 24, 1998 (Form 10-K for 1998). | |
| Credit Agreement dated as of December 17, 1998, between the Company and the banks named therein (Form 10-K for 1998). | ||
| ||
| ||
| Employment Agreement between the Company and Dan O. Dinges dated August 29, 2001 (Form 10-K for 2001). | ||
| 2004 Incentive Plan (Form 10-Q for the quarter ended June 30, 2004). | ||
| (a) First Amendment to the 2004 Incentive Plan effective February 23, 2007 (Form 10-Q for the quarter ended March 31, 2007). | ||
| *10.13 | 2004 Performance Award Agreement (Form 10-Q for the quarter ended June 30, 2004). | |
| 2004 Annual Target Cash Incentive Plan Measurement Criteria for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005). | ||
| Form of Restricted Stock Awards Terms and Conditions for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005). | ||
| *10.16 | 2005 Form of Non-Employee Director Restricted Stock Unit Award Agreement (Form 8-K for May 24, 2005). | |
| *10.17 | Savings Investment Plan of the Company, as amended and restated effective January 1, 2001 (Form 10-K for 2005). | |
| (a) First Amendment to the Savings Investment Plan effective January 1, 2002 (Form 10-K for 2005). | ||
| (b) Second Amendment to the Savings Investment Plan effective January 1, 2003 (Form 10-K for 2005). | ||
| (c) Third Amendment to the Savings Investment Plan effective January 1, 2005 (Form 10-K for 2005). | ||
| *10.18 | Forms of Award Agreements for Executive Officers under 2004 Incentive Plan (Form 10-K for 2006). | |
| (a) Form of Restricted Stock Award Agreement (Form 10-K for 2006). | ||
| (b) Form of Stock Appreciation Rights Award Agreement (Form 10-K for 2006). | ||
| (c) Form of Performance Share Award Agreement (Form 10-K for 2006). | ||
| 10.19 | Cabot Oil & Gas Corporation Mineral, Royalty and Overriding Royalty Interest Plan (Registration Statement No. 333-135365). | |
| (a) Form of Conveyance of Mineral and/or Royalty Interest (Registration Statement No. 333-135365). | ||
| (b) Form of Conveyance of Overriding Royalty Interest (Registration Statement No. 333-135365). | ||
| 10.20 | Purchase and Sale Agreement dated August 25, 2006 between Cabot Oil & Gas Corporation, a Delaware corporation, Cody Energy LLC, a Colorado limited liability company, and Phoenix Exploration Company LP, a Delaware limited partnership (Form 8-K for September 29, 2006). | |
| *10.21 | Form of Amendment of Employee Award Agreements (Form 8-K for December 19, 2006). | |
| *10.22 | Savings Investment Plan of the Company, as amended and restated effective January 1, 2006 (Form 10-K for 2006). | |
| (a) First Amendment to the Savings Investment Plan of the Company effective January 1, 2006. | ||
| *10.23 | Pension Plan of the Company, as amended and restated effective January 1, 2006 (Form 10-K for 2006). | |
| (a) First Amendment to the Pension Plan of the Company effective January 1, 2006. | ||
| 14.1 | Amendment of Code of Business Conduct (as amended on July 28, 2005 to revise Section III. F. relating to Transactions in Securities and Article V. relating to Safety, Health and the Environment) (Form 10-Q for the quarter ended June 30, 2005). | |
| 16.1 | Letter, dated March 12, 2007, from UHY Mann Frankfort Stein & Lipp CPAs, LLP to the Securities and Exchange Commission (Form 8-K for March 8, 2007). | |
| 21.1 | Subsidiaries of Cabot Oil & Gas Corporation. | |
| 23.1 | Consent of PricewaterhouseCoopers LLP. | |
| 23.2 | Consent of Miller and Lents, Ltd. | |
| 31.1 | 302 Certification – Chairman, President and Chief Executive Officer. | |
| 31.2 | 302 Certification – Vice President and Chief Financial Officer. | |
| 32.1 | 906 Certification. | |
| 99.1 | Miller and Lents, Ltd. Review Letter. | |
| * | Compensatory plan, contract or arrangement. |
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SIGNATURES
Pursuant to the requirements of Section 13 and 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 2nd27th of March 2005.February 2008.
CABOT OIL & GAS CORPORATION | ||
By: | /s/ Dan O. Dinges | |
Dan O. Dinges | ||
Chairman, President and Chief Executive Officer | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ Dan O. Dinges | Chairman, President and | February 27, 2008 | ||
| Dan O. Dinges |
Chief Executive Officer (Principal Executive Officer) | |||
/s/ Scott C. Schroeder
| Vice President and Chief Financial Officer | February 27, 2008 | ||
| Scott C. Schroeder | (Principal Financial Officer) | |||
/s/ Henry C. Smyth
| Vice President, Controller and Treasurer | February 27, 2008 | ||
| Henry C. Smyth | (Principal Accounting Officer) | |||
| ||||
/s/ John G. L. Cabot
| Director | |||
| John G. L. Cabot | ||||
/s/
| Director | |||
| David M. Carmichael | ||||
/s/ Robert L. Keiser | Director | February 27, 2008 | ||
| Robert L. Keiser | ||||
/s/ Robert Kelley
| Director | |||
| ||||
/s/ P. Dexter Peacock
| Director | |||
| P. Dexter Peacock | ||||
/s/ William P. Vititoe
| Director | |||
| William P. Vititoe | ||||
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