Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K x.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is ~~an accelerated filer~~a shell company (as defined in Rule 12b-2 of the Act). Yes x No ¨

The aggregate market value of Common Stock, par value $.10 per share (“Common Stock”), held by non-affiliates (based upon the closing sales price on the New York Stock Exchange on June 30, ~~2003)~~2005), as of the last business day of registrant’s most recently completed second fiscal quarter was approximately ~~$889,100,000.~~

As of January ~~30, 2004,~~31, 2006, there were ~~32,390,158~~48,610,408 shares of Common Stock outstanding.

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held ~~April 29, 2004~~May 4, 2006 are incorporated by reference into Part III of this report.

This Amendment No. 1 to annual report on Form 10-K/A (“Form 10-K/A”) is being filed to amend the Company’s annual report on Form 10-K for the year ended December 31, 2003, which was filed with the SEC on February 18, 2004 (“Original Form 10-K”). Accordingly, pursuant to rule 12b-15 under the Securities Exchange Act of 1934, as amended, this Form 10-K/A contains the complete text of items 6, 8 and 9A of Part II and item 15 of Part IV, as amended, as well as certain currently dated certifications. Unaffected items have not been repeated in this Amendment No. 1.

In August 2004 we determined that deferred tax assets and liabilities associated with current and non-current assets and liabilities that had historically been classified in long-term deferred income taxes should instead be classified as current and non-current deferred tax assets and liabilities based on the classification of the related asset and liability for financial reporting purposes. Accordingly, we have revised our consolidated balance sheet to reflect this change in classification. The net effect of these revisions on the Company’s balance sheets at December 31, 2003 and 2002 was an increase to current assets, non-current assets, total assets, current liabilities, long-term deferred income taxes and total liabilities and stockholders’ equity. Such revisions had no impact on our Consolidated Statement of Operations, Consolidated Statement of Cash Flows, Consolidated Statement of Stockholders’ Equity or Consolidated Statement of Comprehensive Income.

~~The significant effects of the revisions on our consolidated balance sheets from the amounts previously reported are summarized in the following tables (in thousands of dollars):~~

This amendment does not reflect events occurring after the filing of the Original Form 10-K, and does not modify or update the disclosures therein in any way other than as required to reflect the amendments as described above and set forth below.

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. 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. 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.

Cabot Oil & Gas is an independent oil and gas company engaged in the exploration, development, acquisition and exploitation of oil and gas properties located in North America. The five principal areas of operation are Appalachian Basin, Rocky Mountains, Anadarko Basin, onshore and offshore the Texas and Louisiana Gulf Coast, and the gas basin of Western Canada. Operationally, we have four regional offices located in Houston, Texas; Charleston, West Virginia; Denver, Colorado; and Calgary, Alberta.

Net income for 2005 of $148.4 million, or $3.04 per share, exceeded the prior year’s net income of $88.4 million or $1.81 per share, by $60.0 million, or $1.23 per share. The per share data for 2004 has been adjusted for the 3-for-2 split of our stock that occurred in March 2005. The year-over-year net income increase was achieved due to higher natural gas and crude oil production revenues, primarily as a result of higher commodity prices, partially offset by higher operating expenses and taxes. Operating Revenues increased by $152.4 million or 29% due to strong commodity prices. Natural gas production revenues increased by $119.5 million over the prior year. Crude oil and condensate revenues and brokered natural gas revenues also increased by $14.2 million and $22.3 million, respectively. Partially offsetting these increased revenues, operating expenses increased by $54.5 million between 2005 and 2004. This increase was principally due to increased exploration costs, brokered natural gas costs and taxes other than income. Net income in 2005 was also reduced by an increase in income tax expense of $37.6 million. At December 31, 2005, our debt-to-total-capital ratio was 36%, down slightly from 37% at the end of 2004.

Natural gas production increased to 73.9 Bcf in 2005 from 72.8 Bcf in 2004. This growth resulted from our 2004 and 2005 drilling programs, which focused on natural gas projects, especially in the East. On an equivalent basis, our production level in 2005 was down slightly from 2004. We produced 84.4 Bcfe, or 231.1 Mmcfe per day, in 2005, as compared to 84.8 Bcfe, or 232.3 Mmcfe per day, in 2004. The growth in natural gas production was offset by the natural decline in oil production in south Louisiana, as well as the impact of the hurricanes which included the shutting in and deferring of production at the Breton Sound offshore lease, one of our largest areas of offshore oil production.

In 2005, energy commodity prices remained strong throughout the year. Our 2005 realized natural gas price was $6.74 per Mcf, compared to a 2004 price of $5.20. Our realized crude oil price was $44.19 per Bbl, compared to a 2004 price of $31.55. These realized prices include the realized impact of derivative instruments. This strong price environment allowed us to pursue our largest organic capital program ever while still maintaining our financial flexibility. In the current year, this flexibility allowed us the ability to acquire additional interests in two fields in the Gulf Coast. We believe that as a result of our strong capital program and financial flexibility, we should be able to continue to take advantage of additional attractive acquisition opportunities that may arise.

A portion of our production was covered by oil and gas hedge instruments throughout 2005 to cover production in 2005 and 2006. At December 31, 2005, 33% and 26% of our natural gas and crude oil anticipated production, respectively, are hedged for 2006 through the use of derivatives that qualify for hedge accounting. As of December 31, 2005, no derivatives are in place for 2007. Our decision to hedge 2006 production fits with our risk management strategy and allows us to lock in the benefit of high commodity prices on a portion of our anticipated production. Our average hedged prices on natural gas and crude oil for 2006 anticipated production are expected to be higher than comparable prices realized in 2005.

For the year ended December 31, 2005, we drilled 316 gross wells with a success rate of 95% compared to 256 gross wells with a success rate of 95% for the prior year. In 2006, we plan to drill approximately 391 gross wells.

Our proved reserves totaled approximately 1,331 Bcfe at December 31, 2005, of which 95% was natural gas. This reserve level was up by 11% from 1,202 Bcfe at December 31, 2004 on the strength of results from our drilling program and the increase in our capital spending.

Our 2005 capital and exploration spending was $425.6 million, including $73.1 million, primarily in the Gulf Coast, to acquire proved producing properties, compared to $259.5 million of total capital and exploration spending in 2004. We remain focused on our strategies of balancing our capital investments between acceptable risk and strongest economics, along with balancing longer life investments with impact exploration opportunities. In the past, we have used a portion of the cash flow from our long-lived East and Mid-Continent natural gas reserves to fund our exploration and development efforts in the Gulf Coast and Rocky Mountains areas. We have continued that practice, and the allocation of capital among regions in 2005 was similar in percentage to the allocation in 2004, with the Gulf Coast region being allocated an additional 12% in capital over the previous year. In 2006, we plan to spend approximately $396 million which includes a layer of investment for new projects or property acquisitions that may arise during the year.

In March 2005, we completed a 3-for-2 split of our common stock in the form of a stock distribution. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of our common stock.

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. See “Forward-Looking Information” for further details.

The following table presents certain reserve, production and well information as of December 31, 2005.

Our East activities are concentrated primarily in West Virginia. In this region, our assets include a large acreage position, a high concentration of wells, natural gas gathering and pipeline systems, and storage capacity. Capital and exploration expenditures were $99.0 million, or 23% of our total 2005 capital spending, and $75.2 million, or 29% of our total 2004 capital spending. For 2006, we have budgeted $116.1 million for capital and exploration expenditures in the region.

At December 31, 2005, we had 2,745 wells (2,550.2 net), of which 2,657 wells are operated by us. There are multiple producing intervals that include the Big Lime, Weir, Berea and Devonian Shale formations at depths primarily ranging from 1,000 to 9,500 feet. Average net daily production in 2005 was 59.2 Mmcfe. 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 reserves is relatively long. At December 31, 2005, we had 637.4 Bcfe of proved reserves (substantially all natural gas) in the East region, constituting 48% of our total proved reserves. This region is managed from our office in Charleston, West Virginia.

In 2005, we drilled 185 wells (179.8 net) in the East region, of which 182 wells (176.8 net) were development and extension wells. In 2006, we plan to drill approximately 239 wells.

In 2005, we produced and marketed approximately 70 barrels of crude oil/condensate per day in the East region at market responsive prices.

Ancillary to our exploration, development and production operations, we operate a number of gas gathering and transmission pipeline systems with interconnects to three interstate transmission systems, seven local distribution companies and numerous end users as of the end of 2005. The majority of our pipeline infrastructure in West Virginia is regulated by the Federal Energy Regulatory Commission (FERC). 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. Our natural gas gathering and transmission pipeline systems enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, local distribution companies and industrial end users. Control of our gathering and transmission pipeline systems also enables us to purchase, transport and sell natural gas produced by third parties. In addition, we can engage in development drilling without relying upon third parties to transport our natural gas and incur only the incremental costs of pipeline and compressor additions to our system.

We have two natural gas storage fields located in West Virginia with a combined working capacity of approximately 4 -Bcf. We use these storage fields to take advantage of the seasonal variations in the demand for natural gas and the higher prices typically associated with winter natural gas sales, while maintaining production at a nearly constant rate throughout the year. The storage fields also enable us to increase for shorter intervals of time the volume of natural gas that we can deliver by more than 40% above the volume that we could deliver solely from our production in the East region. The pipeline systems and storage fields are fully integrated with our operations.

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.

Approximately 65% 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 under month-to-month contracts, while industrial and utility sales generally are made under year-to-year contracts. Approximately 2% of East production is sold on fixed price contracts that typically renew annually.

Our activities in the West region are managed by a regional office in Denver, Colorado. At December 31, 2005, we had 432.3 Bcfe of proved reserves (96% natural gas) in the West region, constituting 32% of our total proved reserves.

Activities in the Rocky Mountains are concentrated in the Green River, Washakie and Big Horn Basins in Wyoming and Paradox Basin in Colorado. At December 31, 2005, we had 241.2 Bcfe of proved reserves (95% natural gas) in the Rocky Mountains area, or 18% of our total proved reserves. Capital and exploration expenditures in the Rocky Mountains were $45.4 million for 2005, or 11% of our total capital and exploration expenditures, and $41.5 million for 2004. For 2006, we have budgeted $57.8 million for capital and exploration expenditures in the area.

We had 576 wells (252.4 net) in the Rocky Mountains area as of December 31, 2005, of which 295 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 2005 was 37.3 Mmcfe.

In 2005, we drilled 49 wells (16.1 net) in the Rocky Mountains, of which 45 wells (13.3 net) were development wells. In 2006, we plan to drill 42 wells.

Our Mid-Continent activities are concentrated in the Anadarko Basin in southwest Kansas, Oklahoma and the panhandle of Texas. Capital and exploration expenditures were $23.7 million for 2005, or 6% of our total 2005 capital and exploration expenditures, and $12.1 million for 2004. For 2006, we have budgeted $33.1 million for capital and exploration expenditures in the area.

As of December 31, 2005, we had 680 wells (471.8 net) in the Mid-Continent area, of which 523 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 2005 was 29.1 Mmcfe. At December 31, 2005, we had 191.1 Bcfe of proved reserves (97% natural gas) in the Mid-Continent area, or 14% of our total proved reserves.

In 2005, we drilled 34 wells (21.5 net) in the Mid-Continent, all of which were development and extension wells. In 2006, we plan to drill 42 wells.

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 2005, we produced and marketed approximately 450 barrels of crude oil/condensate per day in the West region at market responsive prices.

Our exploration, development and production activities in the Gulf Coast region are primarily concentrated in north and south Louisiana, south Texas and, to a lesser extent, the Gulf of Mexico. A regional office in Houston manages the operations. Principal producing intervals are in the Cotton Valley, Hosston, Miocene and Frio age formations in Louisiana and the Frio, Vicksburg and Wilcox formations in Texas at depths ranging from 3,000 to 25,000 feet. Capital and exploration expenditures were $233.5 million for 2005, or 55% of our total capital and exploration expenditures, and $112.6 million for 2004. During 2005, we spent $72.1 million on proved property acquisitions. For 2006, we have budgeted $154.4 million of our total budget for capital and exploration expenditures in the region. Our 2006 Gulf Coast drilling program will emphasize activity in our focus areas of east Texas, north Louisiana and south Texas.

In 2005, we drilled 39 wells (26.2 net) in the Gulf Coast region, of which 23 wells (17.4 net) were development wells. In 2006, we plan to drill 55 wells. We had 788 wells (515.7 net) in the Gulf Coast region as of December 31, 2005, of which 582 wells are operated by us. Average daily production in 2005 was 102.1 Mmcfe, compared to 115.3 Mmcfe in 2004. The decline is the result of lower production from our properties in south Louisiana, offset partially by increased production from the coastal Texas area. At December 31, 2005, we had 240.9 Bcfe of proved reserves (80% natural gas) in the Gulf Coast region, which represented 18% of our total proved reserves.

Our principal markets for Gulf Coast region natural gas are in the industrialized Gulf Coast area and the northeast United States. We sell natural gas to intrastate pipelines, natural gas processors and marketing companies. Currently, approximately 50% of our natural gas sales volumes in the Gulf Coast region are sold at index-based prices under contracts with terms of one to three years. The remaining 50% of our sales volumes are sold at index-based prices under short-term agreements. The Gulf Coast properties are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets.

In 2005, we produced and marketed approximately 4,100 barrels of crude oil/condensate per day in the Gulf Coast region at market responsive prices.

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 Provinces of Alberta and British Columbia. At December 31, 2005, we had 20.3 Bcfe of proved reserves (97% natural gas) in the Canada region, constituting 2% of our total proved reserves.

Capital and exploration expenditures in Canada were $22.9 million for 2005, or 5% of our total capital and exploration expenditures, and $16.2 million for 2004. For 2006, we have budgeted $30.7 million for capital and exploration expenditures in the area.

We had 20 wells (3.9 net) in the Canada region as of December 31, 2005, of which 8 wells are operated by us. Principal producing intervals in the Canada region are in the Falher, Bluesky, Cadomin and the Swan Hills formations at depths ranging from 9,500 to 16,000 feet. Average net daily production in Canada during 2005 was 3.4 Mmcfe.

In 2005, we drilled 9 wells (3.5 net) in Canada, of which 5 wells (1.7 net) were development and extension wells. In 2006, we plan to drill 13 wells.

In 2005, we produced and marketed approximately 50 barrels of crude oil/condensate per day in the Canada region at market responsive prices.

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 2005 we primarily employed natural gas and crude oil price swap and collar agreements 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.

We will continue to evaluate the benefit of employing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk” for further discussion concerning our use of derivatives.

The following table presents our estimated proved reserves at December 31, 2005.

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) we used appropriate engineering, geologic and evaluation principles 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 2005, we filed estimates of our oil and gas reserves for the year 2004 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 2005. If we had considered the impact of our hedging activities in our proved reserves, there would not have been any significant effect.

For additional information about the risks inherent in our estimates of proved reserves, see “Risk Factors—Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated” in Item 1A.

The following table presents our estimated proved reserves for the periods indicated.

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.


	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
*Leasehold Acreage by State*
Arkansas	1,981	425	0	0	1,981	425
Colorado	16,268	14,053	208,597	131,490	224,865	145,543
Kansas	29,067	27,745	0	0	29,067	27,745
Louisiana	67,324	43,186	182,211	151,840	249,535	195,026
Montana	397	210	14,102	10,835	14,499	11,045
New York	2,956	1,105	10,642	5,683	13,598	6,788
Ohio	6,247	2,384	1,625	436	7,872	2,820
Oklahoma	173,208	120,257	15,407	11,110	188,615	131,367
Pennsylvania	112,522	63,986	108	43	112,630	64,029
Texas	109,837	75,737	83,540	67,690	193,377	143,427
Utah	1,740	529	180,257	96,425	181,997	96,954
Virginia	22,298	20,201	2,642	1,558	24,940	21,759
West Virginia	582,411	549,728	206,725	192,171	789,136	741,899
Wyoming	141,317	73,074	297,342	171,176	438,659	244,250

Total	1,267,573	992,620	1,203,198	840,457	2,470,771	1,833,077

*Mineral Fee Acreage by State*
Colorado	0	0	2,899	271	2,899	271
Kansas	160	128	0	0	160	128
Louisiana	628	276	0	0	628	276
Montana	0	0	589	75	589	75
New York	0	0	6,545	1,353	6,545	1,353
Oklahoma	16,580	13,979	730	179	17,310	14,158
Pennsylvania	524	524	1,573	502	2,097	1,026
Texas	27	27	754	327	781	354
Virginia	17,817	17,817	100	34	17,917	17,851
West Virginia	97,455	79,488	51,603	49,671	149,058	129,159

Total	133,191	112,239	64,793	52,412	197,984	164,651

Aggregate Total	1,400,764	1,104,859	1,267,991	892,869	2,668,755	1,997,728


	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
*Canada Leasehold Acreage by Province*
Alberta	5,760	1,910	38,472	9,128	44,232	11,038
British Columbia	700	280	11,988	4,731	12,688	5,011
Sasketchewan	0	0	9,903	9,903	9,903	9,903

Total	6,460	2,190	60,363	23,762	66,823	25,952

The following table presents our net undeveloped acreage expiring over the next three years by operating region as of December 31, 2005. The figures below assume no future successful development or renewal of undeveloped acreage.

The following table presents our ownership at December 31, 2005, in productive natural gas and oil wells in the East region (consisting of various fields located in West Virginia, Virginia and Ohio), in the West region (consisting of various fields located in Oklahoma, Kansas, Colorado and Wyoming), in the Gulf Coast region (consisting primarily of various fields located in Louisiana and Texas) and in the Canada region (consisting of various fields located in the Provinces of Alberta and British Columbia). This summary includes natural gas and oil wells in which we have a working interest.

We drilled wells, participated in the drilling of wells, or acquired wells as indicated in the region table below.

Competition in our primary producing areas is intense. Price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery records, affect competition. We believe that our extensive acreage position, existing natural gas gathering and pipeline systems 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 actively compete against other companies with substantially larger financial and other resources, particularly in the West and Gulf Coast regions and Canada.

In each of 2005, 2004 and 2003, approximately 11% of our total sales were made to one customer.

Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the colder winter months.

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 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.

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, and the FERC has been directed to establish new regulations that are intended to increase natural gas pricing transparency through, among other things, expanded dissemination of information about the availability and prices of gas sold. 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 developed rules governing the relationship of the pipelines with their marketing affiliates, and 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, 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 pipeline facilities within the next ten years, and at least every seven years thereafter. In addition, beginning in early 2006, the DOT’s Pipeline and Hazardous Materials Safety Administration commenced a rulemaking proceeding to develop rules that would better distinguish onshore gathering lines from production facilities and transmission lines, and to develop safety requirements better tailored to gathering line risks. We are not able to predict with certainty the final outcome of this rulemaking proposal.

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.

Our sales of oil and natural gas liquids are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The second of these required reviews commenced in July 2005, where the FERC proposed to continue use of the indexing methodology for a further five year period.

Another FERC proceeding that may impact our transportation costs relates to an ongoing proceeding to determine whether and to what extent pipelines should be permitted to include in their transportation rates an allowance for

income taxes attributable to non-corporate partnership interests. Following a court remand, the FERC has established a policy that a pipeline structured as a master limited partnership or similar non-corporate entity is entitled to a tax allowance with respect to income for which there is an “actual or potential income tax liability,” to be determined on a case by case basis. Generally speaking, where the holder of a partnership unit interest is required to file a tax return that includes partnership income or loss, such unit-holder is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income.

We are not able to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index, or the final outcome of the application of the FERC’s new policy on income tax allowances.

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. 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, permit holders 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.

Solid and Hazardous Waste. We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other solid wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become more strict over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination. We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today.

Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the owner

and operator of a site and any party that disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In the course of business, we have generated and will continue to generate wastes that may fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such wastes have been disposed.

Oil Pollution Act. The federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term “waters of the United States” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. We believe that we substantially comply with the Oil Pollution Act and related federal regulations.

Clean Water Act. The Federal Water Pollution Control Act (FWPCA or 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 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.

As of December 31, 2005, Cabot Oil & Gas had 354 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.

We make available free of charge through our website,www.cabotog.com, our annual report 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. 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 filed by the Company.

The Company’s Corporate Governance Guidelines, 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 2005, we submitted to the New York Stock Exchange the chief executive officer certification required by Section 303A.12(a) of the NYSE’s Listed Company Manual.

Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. Because our reserves are predominantly natural gas, changes in natural gas prices may have a particularly large impact on our financial results.

Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

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.

Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:

Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate for activity within a particular geographic area may decline. We may ultimately not be able to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may not be able to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:

These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil.

Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.

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 uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysic, engineering and production data. As a result, estimates of different engineers may vary. In addition, 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 natural gas and oil 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:

Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original

estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and crude oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.

You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board in Statement of Financial Accounting Standards No. 69 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable.

In general, the production rate of natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and oil production and lower revenues and cash flow from operations. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low natural gas and oil prices may further limit the kinds of reserves that we can develop economically. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.

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.

We are continually identifying and evaluating 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.

In addition, we conduct operations in shallow offshore areas, which are subject to additional hazards of marine operations, such as capsizing, collision and damage from severe weather. Any of these events could result in injury or loss of human life, loss of hydrocarbons, significant damage to or destruction of property, environmental pollution, regulatory investigations and penalties, impairment of our operations and substantial losses to us.

Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. As of December 31, 2005, we owned or operated approximately 3,400 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.

In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. We do not carry business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Terrorist activities and the potential for military and other actions could adversely affect our business.

The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.

Our ability to sell our natural gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.

The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. Our failure to obtain these services on acceptable terms could materially harm our business.

Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.

Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours, particularly in the Rocky Mountains, Mid-Continent and Gulf Coast areas. 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 2005 we primarily employed natural gas and crude oil price swap and collar agreements to attempt to manage price risk. 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.

These hedging arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

We will continue to evaluate the benefit of employing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A for further discussion concerning our use of derivatives.

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.

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

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.

We are a defendant in various legal proceedings arising in the normal course of our business. All known liabilities are accrued based on management’s best estimate of the potential loss. While the outcome and impact of such legal proceedings on us cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

In January 2002, we were sued by 13 overriding royalty owners in Wyoming federal district court, as reported in previous filings. The plaintiffs made claims pertaining to deductions from their overriding royalty and claims concerning penalties for improper reporting. As a result of several decisions by the Court favorable to us, the case was settled in September 2005 with no payment from us and a dismissal with prejudice of all claims by plaintiffs. The settlement included provisions for reporting and payment going forward. In the third quarter of 2005, management reversed the reserve we had recorded regarding this case, which did not have a material impact on our consolidated financial statements.

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 and allege that we failed to pay royalty based upon the wholesale market value of the gas, that we had taken improper deductions from the royalty and failed to properly inform royalty owners of the deductions. The plaintiffs also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that we reached with Columbia Gas Transmission Corporation in 1995 bankruptcy proceedings.

Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. The Court entered an order on June 1, 2005 granting the motion for class certification. The parties have negotiated a modification to the order which will result in the dismissal of the claims related to the gas sales contract settlement in connection with the Columbia Gas Transmission bankruptcy proceedings and that will limit the claims to those arising on and after December 17, 1991. The Court has postponed the trial date from April 17, 2006, in light of a case pending before the West Virginia Supreme Court of Appeals which may decide issues of law that may apply to the issue of deductibility of post-production expenses. We intend to challenge the class certification order by filing a Petition for Writ of Prohibition with the West Virginia Supreme Court of Appeals.

We are vigorously defending the case. We have established a reserve that management believes is adequate based on their estimate of the probable outcome of this case.

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 Second Supplemental Original Petition on November 12, 2004 and their Third Supplemental Original Petition on February 22, 2005 (which added Wynn-Crosby 1996, Ltd. and Dominion Oklahoma Texas Exploration & Production, Inc.). Plaintiffs allege that they are the owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. Cody Energy, LLC, our subsidiary, acquired certain leases and wells in 1997 and 1998.

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. Plaintiffs claim that they acquired title to the property by adverse possession. Plaintiffs also assert the discovery rule and a claim of fraudulent concealment to avoid the affirmative defense of limitations. In August 2005, the case was abated until late February 2006, during which time the parties are allowed to amend pleadings or add additional parties to the litigation. Due to the abatement of the case, we have

not had the opportunity to conduct discovery in this matter. We estimate that production revenue from this field since Cody Energy, LLC acquired title is approximately $15.7 million, and that the carrying value of this property is approximately $33.6 million.

Although the investigation into this claim continues, we intend to vigorously defend the case. Should we receive an adverse ruling in this case, an impairment review would be assessed to determine whether 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, we have not established a reserve for this matter.

In April 2004, our wholly owned subsidiary, Cody Energy, LLC, filed suit in state court 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 under the terms of the Joint Operating Agreement. Some of the co-working interest owners elected not to participate. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.

The working interest owners who elected not to participate notified Cody that they believed that they had the right to participate in wells drilled after the initial well. Cody contends that the working interest owners that elected not to participate are required to assign their interest in the prospect to those who elected to participate. 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 has signed a settlement agreement with certain of the defendants representing approximately 3% of the interest in the area. Cody and the remaining defendant filed cross motions for summary judgment. In August 2005, the trial judge entered an order granting Cody’s Motion for Summary Judgment requiring the remaining defendant to assign to Cody all of its interest in the prospect and to remove the lien filed against Cody’s interest. The defendant has filed a Motion for Reconsideration and Opposition to Proposed Order. The Court has not yet made a decision on these two motions.

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 $10.2 million of additional loss with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

While the outcome and impact on us cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

No matters were submitted to a vote of security holders during the fourth quarter of 2005.

The following table shows certain information about our executive officers as of February 17, 2006, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.

All officers are elected annually by our Board of Directors. Except for the following, all 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 B.B.A. degree in Petroleum Land Management from The University of Texas.

Thomas S. Liberatorejoined Cabot in January 2002 as Regional Manager, East and was promoted to his current position in July 2003. Prior to joining the Company, Mr. 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. Mr. Liberatore received his B.S. in Geology from West Virginia University.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The common stock is listed and principally traded on the New York Stock Exchange under the ticker symbol “COG.” The following table presents the high and low closing sales prices per share of the common stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the common stock are also shown. On February 28, 2005, we announced that our Board of Directors had declared a 3-for-2 split of our 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, we paid cash based on the closing price of the common stock on the record date. All common stock accounts and per share data, including cash dividends per share, have been retroactively adjusted to give effect to the 3-for-2 split of our common stock.

As of January 31, 2006, there were 632 registered holders of the common stock. Shareholders include individuals, brokers, nominees, custodians, trustees, and institutions such as banks, insurance companies and pension funds. Many of these hold large blocks of stock on behalf of other individuals or firms.

On August 13, 1998, we announced that our Board of Directors authorized the repurchase of two million shares of our common stock in the open market or in negotiated transactions. As a result of the 3-for-2 stock split effected in March 2005, this figure has been adjusted to three million shares. All purchases executed have been through open market transactions. There is no expiration date associated with the authorization to repurchase our securities.

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, and the Consolidated Financial Statements and related Notes.


	Year Ended December 31,										Year Ended December 31,
(In Thousands, Except Per Share Amounts)	2003		2002		2001		2000		1999
Income Statement Data
*(In thousands, except per share amounts)*											2005		2004		2003		2002		2001
Statement of Operations Data
Operating Revenues	$	509,391	$	353,756	$	447,042	$	368,651	$	294,037	$	682,797	$	530,408	$	509,391	$	353,756	$	447,042
Impairment of Oil and Gas Properties⁽¹⁾												—		3,458		93,796		2,720		6,852
Income from Operations		66,587		49,088		95,366		64,817		39,498		258,731		160,653		66,587		49,088		95,366
Net Income Available to Common Stockholders		21,132		16,103		47,084		29,221		5,117
Net Income												148,445		88,378		21,132		16,103		47,084

Basic Earnings per Share	$	0.66	$	0.51	$	1.56	$	1.07	$	0.21
Basic Earnings per Share⁽²⁾⁽³⁾											$	3.04	$	1.81	$	0.44	$	0.34	$	1.04

Dividends per Common Share	$	0.16	$	0.16	$	0.16	$	0.16	$	0.16
Dividends per Common Share⁽²⁾											$	0.147	$	0.107	$	0.107	$	0.107	$	0.107

Balance Sheet Data
Properties and Equipment, Net	$	895,955	$	971,754	$	981,338	$	623,174	$	590,301	$	1,238,055	$	994,081	$	895,955	$	971,754	$	981,338
Total Assets (1)		1,055,056		1,100,947		1,092,810		776,353		706,887
Total Assets												1,495,370		1,210,956		1,055,056		1,100,947		1,092,810
Current Portion of Long-Term Debt												20,000		20,000		—		—		—
Long-Term Debt		270,000		365,000		393,000		253,000		277,000		320,000		250,000		270,000		365,000		393,000
Stockholders’ Equity		365,197		350,657		346,552		242,505		186,496		600,211		455,662		365,197		350,657		346,552

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 Notes included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. Please read “Forward-Looking Information” for further details.

We operate in one segment, natural gas and oil exploration and exploitation, exclusively within the United States and Canada.

Cabot Oil & Gas and its subsidiaries are a leading independent oil and gas company engaged in the exploration, development, acquisition, exploitation, production and marketing of natural gas, and to a lesser extent, crude oil and natural gas liquids from its properties in North America. We also transport, store, gather and produce natural gas for resale. Our 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: drilling opportunities, acquisition opportunities and financial opportunities such as debt repayment or repurchase of common stock. 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.

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 2004 and 2005, the futures market reported unprecedented natural gas and crude oil contract prices. Our realized natural gas and crude oil price was $6.74 per Mcf and $44.19 per Bbl, respectively, in 2005. These realized prices include the realized impact of derivative instruments. In an effort to manage commodity price risk, we entered into a series of crude oil and natural gas price collars and swaps. These financial instruments are an element of our risk management strategy but prevented us from realizing the full impact of the price environment.

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, natural gas liquids and crude oil prices, and therefore, we cannot determine 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.

The tables below illustrate how natural gas prices have fluctuated by month over 2004 and 2005. “Index” represents the first of the month Henry Hub index price per Mmbtu. The “2004” and “2005” 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:

Prices for crude oil have followed a similar path as the commodity price continued to maintain strength in 2004 and rose further in 2005. The tables below contain the NYMEX monthly average crude oil price (Index) and our realized per barrel (Bbl) crude oil prices by month for 2004 and 2005. The “2004” and “2005” price is the crude oil price per Bbl realized by us and includes the realized impact of our crude oil derivative arrangements:

We reported earnings of $3.04 per share, or $148.4 million, for 2005. This is up from the $1.81 per share, or $88.4 million, reported in 2004. The stronger price environment was a primary contributor to the earnings increase due to the increase in natural gas and oil revenues. Prices, including the realized impact of derivative instruments, rose 30% for natural gas and 40% for oil.

We drilled 316 gross wells with a success rate of 95% in 2005 compared to 256 gross wells with a 95% success rate in 2004. Total capital and exploration expenditures increased by $166.1 million to $425.6 million, of which $73.1 million was for property acquisitions, in 2005 compared to $259.5 million for 2004. We believe our operating cash flow in 2006 will be sufficient to fund our capital and exploration budgeted spending of approximately $396 million and again provide excess cash flow. Any excess cash flow may be used for acquisitions, to pay current debt due, repurchase common stock, expand our capital program or other opportunities.

Our 2006 strategy will remain consistent with 2005. We will remain focused on our strategies of balancing our capital investments between higher risk projects with the potential for higher returns and lower risk projects with more stable returns, along with balancing longer life investments with impact exploration opportunities. In the current year we have allocated our planned program for capital and exploration expenditures among our various operating regions. We believe these strategies are appropriate in the current industry environment and will continue to add shareholder value over the long term.

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read “Forward-Looking Information” for further details.

Our primary source of cash in 2005 was from funds generated from operations, as well as borrowings on our revolving credit facility and, to a lesser extent, proceeds from the exercise of stock options under our stock plans. 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 to seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout the recent years. Working capital is also substantially influenced by these variables. During 2005, approximately 1.4 Bcfe of expected production in our Gulf Coast region was deferred due to the impacts of Hurricanes Katrina and Rita. These hurricanes did not have a material adverse impact on our capital resources nor liquidity. Fluctuation in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on sales. Cash flows provided by operating activities were primarily used to fund exploration and development expenditures, purchase treasury stock and pay dividends. Proceeds from the exercise of stock options under stock option plans during 2005 partially offset our repurchase of 452,300 treasury shares of common stock at a weighted average purchase price of $42.41. See below for additional discussion and analysis of cash flow.

Operating Activities. Net cash provided by operating activities in 2005 increased $91.5 million over 2004. This increase is primarily due to higher commodity prices. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased 30% over 2004, while crude oil realized prices increased 40% over the same period. Production volumes declined slightly, with a less than one percent reduction of equivalent production in 2005 compared to 2004. While we believe 2006 commodity production may exceed 2005 levels, 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 2004 increased $31.4 million over 2003. This increase is primarily due to higher commodity prices. Key components of net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased 15% over 2003, while crude oil realized prices increased 7% over the same period. Production volumes declined, with a 5% reduction of equivalent production in 2004 compared to 2003. See “Results of Operations” for a discussion on commodity prices and a review of the impact of prices and volumes on sales revenue.

Investing Activities. The primary uses of cash by investing activities are capital spending and exploration expense. We establish the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices, our capital expenditures may be periodically adjusted during any given year. Cash flows used in investing activities increased for the years ended December 31, 2005 and 2004 in the amounts of $156.8 million and $103.5 million, respectively. The increase from 2004 to 2005 is primarily due to an increase in drilling activity in the East region and the Rocky Mountains area of our West region in response to higher commodity prices. Our continued drilling activity in Canada also contributed to the increase. In addition, we spent $73.1 million in proved property acquisitions, primarily in the Gulf Coast. The increase from 2003 to 2004 was also primarily due to an increase in drilling activity in response to higher commodity prices. This increase largely occurred in our East region and the Rocky Mountains area of our West region. Our initial drilling activity in Canada also contributed to the increase.

Financing Activities. Cash flows provided by financing activities were $48.2 million for the year ended December 31, 2005, resulting from borrowings under the credit facility, partially offset by the purchase of treasury stock and dividend payments. Cash flows used by financing activities for the year ended December 31, 2004 were $8.4 million. This is the result of proceeds from the exercise of stock options, offset by the purchase of treasury shares and dividend payments. Cash flows used by financing activities for the year ended December 31, 2003 were $90.7 million. This is substantially due to a net repayment on our revolving credit facility in the amount of $95.0 million. Cash utilized for the repayments was generated from operating cash flows.

At December 31, 2005, we had $90 million of debt outstanding under our credit facility. The credit facility provides for an available credit line of $250 million, which can be expanded up to $350 million, either with the existing banks or new banks. The available credit line is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the banks’ petroleum engineer) and other assets. The revolving term of the credit facility ends in December 2009. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Management believes that we have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including potential acquisitions.

In August 1998, we announced that our Board of Directors authorized the repurchase of two million shares of our common stock in the open market or in negotiated transactions. As a result of the 3-for-2 stock split effected in March 2005, this figure has been adjusted to three million shares. During 2005, we repurchased 452,300 shares of our common stock at a weighted average price of $42.41. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase our securities. The maximum number of shares that may yet be purchased under the plan as of December 31, 2005 was 1,486,150. See Item 5 “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for additional information.

For the year ended December 31, 2005, we paid dividends of $7.2 million on our common stock. A regular dividend of $0.04 per share of common stock, or $0.027 per share for dividends prior to the 3-for-2 stock split as adjusted for the split, has been declared for each quarter since we became a public company.

On an annual basis, we generally fund most of our capital and exploration activities, excluding 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, 2005.

We plan to drill about 391 gross wells in 2006 compared with 316 gross wells drilled in 2005. This 2006 drilling program includes approximately $396 million in total capital and exploration expenditures, down from $425.6 million in 2005. Capital and exploration expenditures in 2005 included a layer of $73.1 million in proved property acquisitions as shown in the table above. 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 rate. These include reserve additions and revisions, development costs, impairments and changes in anticipated production in a future period. In 2006 management expects an increase in our depreciation, depletion and amortization rate due to negative reserve revisions and higher capital costs. This change may result in an increase of depreciation, depletion and amortization of 10% to 15% greater than 2005 levels. This increase will not have an impact on our cash flows.

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, and we have not guaranteed the debt of any other party.

A summary of our known contractual obligations as of December 31, 2005 are set forth in the following table:

Amounts related to our asset retirement obligations are not included in the above table given the uncertainty regarding the actual timing of such expenditures. The total amount of asset retirement obligations at December 31, 2005 is $43.0 million.

Subsequent to December 31, 2005, we entered into an agreement for one additional drilling rig in the Gulf Coast. The total commitment over the next four years is $27.4 million, of which $0.8 million, $9.1 million, $9.1 million and $8.4 million will be paid out during the years 2006, 2007, 2008 and 2009, respectively.

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.

The process of estimating quantities of proved reserves is inherently uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysic, 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:

Since 1990, 100% of our reserves have been reviewed by Miller & Lents, Ltd., an independent oil and gas reservoir engineering consulting firm, who in their opinion determined the estimates presented to be reasonable in the aggregate. We have not been required to record a significant reserve revision in the past three years. For more information regarding reserve estimation, including historical reserve revisions, refer to the “Supplemental Oil and Gas Information.”

Our rate of recording depreciation, depletion and amortization 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 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 $0.05 to $0.06 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 impact on our total DD&A rate. These estimated impacts are based on current data, and actual events could require different adjustments to DD&A.

In addition, a decline in proved reserve estimates may impact the outcome of our annual impairment test under Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Due to the inherent imprecision of the reserve estimation process, risks associated with the operations of proved producing properties, and market sensitive commodity prices utilized in our impairment analysis, management cannot determine if an impairment is reasonably likely to occur in the future.

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 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 of the Notes to the Consolidated Financial Statements. In 2004 and 2005, there were no unusual or unexpected occurrences that caused significant revisions in estimated cash flows which were utilized in our impairment test.

Costs attributable to our unproved properties are not subject to the impairment analysis described above; however, a portion of the costs associated with such properties is subject to amortization based on past experience and average property lives. Average property lives are determined on a regional basis and based on the estimated life of unproved property leasehold rights. Historically, the average property lives in each of the regions have not significantly changed. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $2.7 million or decrease by approximately $1.6 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 Gulf Coast, East and West regions have been four, seven and seven years, respectively. Average property lives in Canada are estimated to be six 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.

Periodically we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. We follow the accounting prescribed in SFAS No. 133. Under SFAS No. 133, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each quarterly period, these instruments are marked-to-market. The gain or loss on the change in fair value is recorded as Accumulated Other Comprehensive Income, a component of equity, to the extent that the derivative instrument is designated as a hedge and is effective. Under SFAS No. 133, effectiveness is a measurement of how closely correlated the hedge instrument is with the underlying physical sale. For example, a natural gas price swap that converts Henry Hub index to a fixed price would be perfectly correlated, and 100% effective, if the underlying gas were sold at the Henry Hub index. Any portion of the gains or losses that are considered ineffective under the SFAS No. 133 test are recorded immediately as a component of Operating Revenue, either in Natural Gas Production or Crude Oil and Condensate Revenue, on the Statement of Operations.

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 5.48% annualized for 2005, and the Citigroup Pension Liability Index, which was 5.55% for 2005. 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 5.5% at December 31, 2005 is reasonable.

In order to value our pension liabilities, we use the RP-2000 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 prior years’ 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 4% 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, 2005, the assumed rate of increase was 9.0%. The net periodic cost of pension benefits included in expense also is affected by the expected long-term rate of return on plan assets assumption. The expected return on plan assets rate is normally changed less frequently than the assumed discount rate, and reflects long-term expectations, rather than current fluctuations in market conditions. The actual rate of return on plan assets may differ from the expected rate due to the volatility normally experienced in capital markets. Management’s goal is to manage the investments over the long term to achieve optimal returns with an acceptable level of risk and volatility.

We have established objectives regarding plan assets in the pension plan. In our pension calculations, we have used 8% as the expected long-term return on plan assets for 2005, 2004 and 2003. However, we expect to achieve a minimum 5% annual real rate of return on the total portfolio over the long term. We believe that this is a reasonable estimate based on our actual results. The actual rate of return on plan assets annualized over the past ten years is approximately 10%.

We generally target a portfolio of assets that are within a range of approximately 60% 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.

Prior to the issuance of SFAS No. 123(R) “Share Based Payment (revised 2004)”, there were two alternative methods that could be used to account for stock-based compensation. The first method is the Intrinsic Value method and recognizes 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 second method is the Fair Value method. 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. As of December 31, 2005, we account for stock-based compensation in accordance with the Intrinsic Value method. SFAS No. 123(R) 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 expense performance share awards; however, beginning in the first quarter of 2006, we will be required to expense all stock-based compensation. Further discussion of SFAS No. 123(R) and stock compensation is included in “Recently Issued Accounting Pronouncements.”

On October 26, 2005, the Compensation Committee of our Board of Directors 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 accelerated vesting of the options did not have an impact on our results of operations or cash flows for 2005. The acceleration of vesting is expected to reduce our compensation expense related to these options by approximately $0.2 million for 2006.

Corporate Income Tax.We have benefited in the past and may benefit in the future from the alternative minimum 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 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 not reduce a taxpayer’s alternative minimum taxable income by more than 40% of the amount of such income determined without regard to the repeal of such preference.

Regulations. Our operations are subject to various types of regulation by federal, state and local authorities. See “Regulation of Oil and Natural Gas Exploration and Production”, “Natural Gas Marketing, Gathering and Transportation”, “Federal Regulation of Petroleum” and “Environmental Regulations” in the “Other Business Matters” section of Item 1 “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’s various debt instruments. Among other requirements, our revolving credit agreement and our senior notes specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. At December 31, 2005, we are in compliance in all material respects with all restrictive covenants on both the revolving credit agreement and notes. In the unforeseen event that we fail to comply with these covenants, the Company may apply for a temporary waiver with the lender, which, if granted, would allow us a period of time to remedy the situation. See further discussion in Capital Resources and Liquidity.

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 SFAS No. 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 impairment charge in the first quarter of 2003 of $87.9 million ($54.4 million after-tax). This impairment charge is reflected in the 2003 Statement of Operations as an operating expense but did not impact our cash flows.

Operating Risks and Insurance Coverage.Our business involves a variety of operating risks. See “Risk Factors—We face a variety of hazards and risks that could cause substantial financial losses” in Item 1A. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The costs of these insurance policies are somewhat dependent on our historical claims experience and also the areas in which we choose to operate. During the past few years, we have invested a significant portion of our drilling dollars in the Gulf Coast, where insurance rates are significantly higher than in other regions such as the East.

Commodity Pricing and Risk Management Activities.Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Declines in oil and gas prices may have a material adverse effect on our financial condition, liquidity, ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that we can produce economically. Historically, oil and gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenue and could potentially impact the outcome of our annual impairment test under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Because our reserves are predominantly natural gas, changes in natural gas prices may have a particularly large impact on our financial results.

The majority of our production is sold at market responsive prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. However, management may mitigate this price risk with the use of derivative financial instruments. Most recently, we have used financial instruments such as price collar 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 Company not being able to realize the full benefit of a market improvement.

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in SFAS No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN No. 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN No. 47 is effective for fiscal years ending after December 15, 2005. Our financial position, results of operations and cash flows were not impacted by this Interpretation, since we currently record all asset retirement obligations.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 “Accounting for Suspended Well Costs.” This staff position amends 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 position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made 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 salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the Staff Position requires the annual 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 for a period greater than one year after the completion 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. For our disclosures, refer to Note 2 of the Notes to the Consolidated Financial Statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections-A replacement of APB Opinion No. 20 and FASB Statement No. 3.” In order to enhance financial reporting consistency between periods, SFAS No. 154 modifies the requirements for the accounting and reporting of the direct effects of changes in accounting principles. Under APB Opinion No. 20, the cumulative effect of voluntary changes in accounting principle

was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB Opinion No. 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively applied in the earliest period possible to the balance sheet accounts and a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change is required to be disclosed. The statement also provides that changes in accounting for depreciation, depletion or amortization should be treated as changes in accounting estimate inseparable from a change in accounting principle and that disclosure of the preferability of the change is required. SFAS No. 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005.

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” SFAS No. 123(R) revises SFAS No. 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at 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. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS No. 123(R) will be effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, we will not adopt this SFAS until the first quarter of 2006. We plan to use the modified prospective application method as detailed in SFAS No. 123(R). At this time, management does not believe that the adoption of SFAS No. 123(R) will materially impact our operating results, nor will there be any impact on our future cash flows. See “Stock-Based Compensation” below for further information.

In October 2005, the FASB issued FSP FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as defined in FASB Statement No. 123(R).” This FSP provides guidance on the definition and practical application of “grant date” as described in SFAS No. 123(R). The grant date is described as the date that the employee and employer have met a mutual understanding of the key terms and conditions of an award. The other elements of the definition of grant date are: 1) the award must be authorized, 2) the employer must be obligated to transfer assets or distribute equity instruments so long as the employee has provided the necessary service and 3) the employee is affected by changes in the company’s stock price. To determine the grant date, we are allowed to use the date the award is approved in accordance with our corporate governance requirements so long as the three elements described above are met. Furthermore, the recipient cannot negotiate the award’s terms and conditions with the employer and the key terms and conditions of the award are communicated to all recipients within a reasonably short time period from the approval date. We will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).

In November 2005, the FASB issued FSP FAS 123(R)-3 “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which provides a simpler, more practical transition election relating to the calculation of the “APIC pool.” The APIC pool is defined as the pool of excess tax benefits available to absorb tax deficiencies occurring after the adoption of SFAS No. 123(R). Under this FSP, companies can elect to perform simpler computations to derive the beginning balance of the APIC pool as well as the impact on the APIC pool of fully vested and outstanding awards as of the SFAS No. 123(R) adoption date. The beginning balance can be computed by taking the sum of all tax benefits incurred prior to the adoption of SFAS No. 123(R) from stock-based compensation plans less the tax effected (using a blended statutory rate) pro forma stock-based compensation cost. In addition, increases to the APIC pool for fully vested awards can be calculated by multiplying the tax rate times the tax benefit of the deduction. The calculation of any awards that are partially vested or granted after the SFAS No. 123(R) adoption date will not be affected by this FSP and will be calculated in accordance with SFAS No. 123(R) which requires that only the excess tax benefit or deficiency of the tax deduction over the tax effect of the compensation cost recognized should be considered for the APIC pool. Also under the FSP, all tax benefits recognized on fully vested awards and the excess tax benefits for partially vested and new awards will be reported on the Statement of Cash Flows as a component of financing activities. Companies will have up to one year after adopting SFAS No. 123(R) to decide to elect and disclose whether they plan to use the alternative method or the original method prescribed in SFAS No. 123(R) for the calculation of the APIC pool. We will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).

In February 2006, the FASB issued FSP FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event.” Within certain share-based payment plans, a company can be required to settle outstanding options upon the occurrence of certain events, such as a change in control or liquidity of a company or the death or disability of the shareholder. This FSP amends paragraphs 32 and A229 of SFAS No. 123(R) to incorporate a probability assessment by a company. Under SFAS No. 123(R), it is required that options and similar instruments be classified as liabilities if the entity can be required under any circumstances to settle the instrument in cash or other assets. Under the FSP, a cash settlement feature that can be exercised only upon the occurrence of a contingent event that is outside of the employee’s control does not meet the criteria for liability classification, and should remain to be classified in equity, unless it becomes probable that the contingent event will occur. The effective date for the guidance in this FSP is upon the initial adoption of SFAS No. 123(R). We will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).

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.

We reported net income for the year ended December 31, 2005 of $148.4 million, or $3.04 per share. During 2004, we reported net income of $88.4 million, or $1.81 per share. Operating income increased by $98.0 million compared to the prior year, from $160.7 million to $258.7 million. The increase in operating income from 2004 to 2005 was principally due to an increase in natural gas and oil production revenues partially offset by an increase in total operating expenses. Net income increased from 2004 to 2005 by $60.0 million due to an increase in operating income partially offset by an increase of $37.6 million in income tax expense.

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $6.74 per Mcf compared to $5.20 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments, which reduced these prices by $1.33 per Mcf in 2005 and $0.76 per Mcf in 2004. The following table excludes the unrealized gain from the change in derivative fair value of $1.1 million and $0.9 million for the years ended December 31, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Natural Gas Production Revenues line item in the Statement of Operations.


	Year Ended December 31,					Variance
	2005			2004		Amount			Percent
Natural Gas Production (Mmcf)
Gulf Coast		28,071			31,358		(3,287	)	(10	)%
West		23,224			21,866		1,358		6	%
East		21,435			19,442		1,993		10	%
Canada		1,149			167		982		588	%

Total Company		73,879			72,833		1,046		1	%

Natural Gas Production Sales Price ($/Mcf)
Gulf Coast	$	6.38		$	5.27	$	1.11		21	%
West	$	6.00		$	4.75	$	1.25		26	%
East	$	8.02		$	5.60	$	2.42		43	%
Canada	$	6.79		$	4.69	$	2.10		45	%
Total Company	$	6.74		$	5.20	$	1.54		30	%

Natural Gas Production Revenue (in thousands)
Gulf Coast	$	179,061		$	165,177	$	13,884		8	%
West		139,298			103,851		35,447		34	%
East		171,902			108,935		62,967		58	%
Canada		7,802			784		7,018		895	%

Total Company	$	498,063		$	378,747	$	119,316		32	%

Price Variance Impact on Natural Gas Production Revenue
(in thousands)
Gulf Coast	$	31,200
West		28,997
East		51,798
Canada		2,414

Total Company	$	114,409

Volume Variance Impact on Natural Gas Production Revenue (in thousands)
Gulf Coast	$	(17,317	)
West		6,448
East		11,170
Canada		4,606

Total Company	$	4,907

The increase in Natural Gas Production Revenue is due substantially to the increase in natural gas sales prices. In addition, the slight increase in production was due to the successful drilling programs in the East, West and Canada. Partially offsetting this was the decrease in the Gulf Coast production. The increase in the realized natural gas price combined with the increase in production resulted in a net revenue increase of $119.3 million.

The increased brokered natural gas margin of $2.2 million was driven by an increased sales price that outpaced the increase in purchase cost, offset in part by a decrease in volume.

Our average total company realized crude oil sales price for 2005, including the realized impact of derivative instruments, was $44.19 per Bbl compared to $31.55 per Bbl for 2004. These prices include the realized impact of derivative instruments, which reduced these prices by $9.93 per Bbl in 2005 and $8.98 per Bbl in 2004. The following table excludes the unrealized gain from the change in derivative fair value of $5.5 million and the unrealized loss from the change in derivative fair value of $2.9 million for the years ended December 31, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate Revenues line item in the Statement of Operations.

The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $13.9 million. The decrease in oil production is primarily the result of the decrease in the Gulf Coast region production due to the continued natural decline of the CL&F lease in south Louisiana, as well as the impact of hurricanes which included the shutting in and deferring of production at the Breton Sound offshore lease, one of our largest areas of offshore oil production.

The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:

We are exposed to market risk 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.

Other operating revenues decreased $3.6 million. This change was primarily a result of an increase in our payout liability associated with the reduction of our interest due to customary reversionary interest owned by others, which correspondingly decreased other operating revenues. In addition, our revenues from net profits interest declined over the prior year. This revenue variance also results, to a lesser extent, from changes in our wellhead gas imbalances over the previous year.

Total costs and expenses from operations increased $54.5 million for the year ended December 31, 2005 compared to the year ended December 31, 2004. The primary reasons for this fluctuation are as follows:

Exploration expense increased $13.7 million in 2005, primarily as a result of increased dry hole expenses partially offset by decreased spending on geological and geophysical expenses. During 2005, we spent $6.8 million less on geological and geophysical activities but incurred an additional $18.9 million in dry hole expense. In addition, we spent an additional $0.8 million on delay rentals. The increase in dry hole expense is mainly due to expenses incurred in the Gulf Coast and, to a smaller extent, in Canada and the West.

Direct Operations expense increased by $8.2 million. This is primarily the result of increased expenses for outside operated properties and workovers. In addition, there were increases over the prior year in maintenance charges, equipment expenses and employee related expenses.

Depreciation, Depletion and Amortization increased by $5.1 million in 2005. This is primarily due to an increase in offshore DD&A rates associated with the commencement of offshore production in late 2004 and increased production in the East and West regions.

Impairment of Oil and Gas Properties decreased by $3.5 million as we incurred no impairment expense in the current year. The costs incurred in the prior year related to a field in south Louisiana. Further analysis of this impairment is discussed in Note 2 of the Notes to the Consolidated Financial Statements.

General and Administrative expense increased by $2.9 million in 2005. This increase is primarily due to increased stock compensation expense relating to performance share awards, increased professional services fees and higher employee related expenses. Partially offsetting these increases was a decrease in miscellaneous expenses, primarily due to the reversal of the reserve attributable to litigation that was settled in the 2005 period.

Interest expense, net increased $0.1 million. Interest expense related to borrowings under our revolving credit facility was higher in the current year due to higher average borrowings. Average borrowings based on month end balances for the 2005 year were approximately $130 million compared to approximately $95 million in the prior year. In addition, the effective interest rate on the credit facility increased to 6.9% during 2005 from 4.2% during the prior year. Partially offsetting this was an increase in interest income on our short-term investments.

Income tax expense increased $37.6 million due to an increase in our pre-tax net income.

We reported net income for the year ended December 31, 2004 of $88.4 million, or $1.81 per share. During 2003, we reported net income of $21.1 million, or $0.44 per share. Operating income increased by $94.1 million compared to the prior year, from $66.6 million to $160.7 million. The increase in net income and operating income was principally due to decreased operating expenses from 2003 to 2004 related to the decrease in impairments of oil 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 income and net income were due to an increase in our realized natural gas and crude oil prices.

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $5.20 per Mcf compared to $4.51 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $0.76 per Mcf in 2004 and $0.68 per Mcf in 2003. 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 in 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.

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.

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 million for the years 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 in the Statement of Operations.

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.

The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:

Other operating revenues decreased $3.7 million. This change was primarily a result of decreases in natural gas transportation revenue and natural gas liquid revenue for the year ended December 31, 2004.

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:

Impairment of Oil and Gas Properties expense decreased $90.3 million. This decrease is substantially related to a pre-tax non-cash impairment charge of $87.9 million incurred in 2003 related to 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 determined that 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.

General and Administrative expense increased $9.6 million from 2003 to 2004. Stock compensation expense increased by $4.9 million as a result of performance share awards issued in 2004 and increased amortization of restricted stock grants for grants which occurred during the year. Compliance fees related to Sarbanes-Oxley increased expenses by $2.3 million, and there was a $1.2 million increase in employee related expenses.

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 increased $35.2 million due to an increase in our pre-tax net income.

Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to us of increases in prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please read the discussion below as well as Note 10 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.

Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. Under our revolving credit agreement, the aggregate level of commodity hedging must not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. At December 31, 2005, we had nine cash flow hedges open: eight natural gas price collar arrangements and one crude oil price collar arrangement. At December 31, 2005, a $20.7 million ($12.9 million net of tax) unrealized loss was recorded to Accumulated Other Comprehensive Income, along with a $22.4 million short-term derivative liability and a $1.7 million short-term derivative receivable, which is shown in Other Current Assets on the Balance Sheet. 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 change in fair value of all other derivatives is recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue, as appropriate.

Assuming no change in commodity prices, after December 31, 2005 we would expect to reclassify to the Statement of Operations, over the next 12 months, $12.9 million in after-tax charges associated with commodity hedges. This reclassification represents the net liability associated with open positions currently not reflected in earnings at December 31, 2005 related to anticipated 2006 production.

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 derivatives are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. During 2005, natural gas price swaps covered 20,557 Mmcf, or 28% of our gas production, fixing the sales price of this gas at an average of $5.14 per Mcf.

At December 31, 2005, we had no open natural gas price swap contracts covering 2006 production.

From time to time, we enter into natural gas and crude oil derivative arrangements that do not qualify for hedge accounting under SFAS No. 133. These financial instruments are recorded at fair value at the balance sheet date. At December 31, 2005, we did not have any of these types of arrangements.

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 2005, natural gas price collars covered 15,157 Mmcf of our gas production, or 21% of our gas production with a weighted average floor of $5.59 per Mcf and a weighted average ceiling of $8.61 per Mcf. During 2005, an oil price collar covered 365 Mbbl of our crude oil production, or 21% of our crude oil production with a weighted average floor of $40.00 per Mbbl and a weighted average ceiling of $50.50 per Mbbl.

At December 31, 2005, we had open natural gas price collar contracts covering our 2006 production as follows:

At December 31, 2005, we had one open crude oil price collar contract covering our 2006 production as follows:

We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged.

The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See “Forward-Looking Information” for further details.

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 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.

~~Report of Independent Registered Public Accounting Firm~~REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the ~~Stockholders and~~ Board of Directors and Stockholders of Cabot Oil & Gas Corporation:

We have completed integrated audits of Cabot Oil & Gas Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 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.

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 at December 31, ~~2003~~2005 and ~~2002,~~2004, and the results of their operations and their cash flows ~~and their comprehensive income~~ for each of the three years in the period ended December 31, ~~2003~~2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s ~~management; our~~management. Our responsibility is to express an opinion on these financial statements based on our 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes 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. We believe that our audits provide a reasonable basis for our opinion.

As discussed in ~~Notes 1 and 13~~Note 11 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” effective January 1, 2003.

~~As discussed~~Also, in ~~Note 12~~our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), 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, 2005, 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). 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.

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 ~~consolidated~~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 adopted Statement~~company are being made only in accordance with authorizations of ~~Financial Accounting Standards No. 133, “Accounting for Derivative Instruments~~management and ~~Hedging Activities,” as amended, effective January 1, 2001.~~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.

~~As discussed in Note 2~~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 ~~consolidated financial statements,~~risk that controls may become inadequate because of changes in conditions, or that the ~~Company has restated its consolidated balance sheets to correct~~degree of compliance with the ~~classification of its deferred tax assets and liabilities.~~policies or procedures may deteriorate.

The accompanying notes are an ~~intergral~~integral part of these consolidated financial statements.


	December 31,
	2003			2002			December 31,
	Restated			Restated			2005			2004
ASSETS
Current Assets
Cash and Cash Equivalents	$	724		$	1,602		$	10,626		$	10,026
Accounts Receivable		87,425			70,028			168,248			125,754
Inventories		18,241			15,252			24,616			24,049
Deferred Income Taxes		21,935			14,263			15,674			21,345
Other		15,006			5,280			11,148			13,505

Total Current Assets		143,331			106,425			230,312			194,679
Properties and Equipment, Net (Successful Efforts Method)		895,955			971,754			1,238,055			994,081
Deferred Income Taxes		8,920			15,755			19,587			14,855
Other Assets		6,850			7,013			7,416			7,341

	$	1,055,056		$	1,100,947		$	1,495,370		$	1,210,956

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	84,943		$	72,619		$	140,006		$	104,969
Current Portion of Long-Term Debt								20,000			20,000
Deferred Income Taxes								941			944
Derivative Contracts								22,478			38,368
Accrued Liabilities		71,584			48,914			35,159			32,608

Total Current Liabilities		156,527			121,533			218,584			196,889
Long-Term Debt		270,000			365,000			320,000			250,000
Deferred Income Taxes		208,955			229,623			289,381			247,376
Other Liabilities		54,377			34,134			67,194			61,029
Commitments and Contingencies (Note 9)
Commitments and Contingencies (Note 7)
Stockholders’ Equity
Common Stock:
Authorized — 80,000,000 Shares of $.10 Par Value Issued and Outstanding — 32,538,255 Shares and 32,133,118 Shares in 2003 and 2002, Respectively		3,254			3,213
Authorized — 80,000,000 Shares of $.10 Par Value Issued — 50,081,983 Shares and 49,680,915 Shares in 2005 and 2004, respectively								5,008			4,968
Additional Paid-in Capital		361,699			353,093			397,349			380,125
Retained Earnings		27,763			11,674			252,167			110,935
Accumulated Other Comprehensive Loss		(23,135	)		(12,939	)		(15,115	)		(20,351	)
Less Treasury Stock, at Cost:
302,600 Shares in 2003 and 2002		(4,384	)		(4,384	)
1,513,850 and 1,061,550 Shares in 2005 and 2004, respectively								(39,198	)		(20,015	)

Total Stockholders’ Equity		365,197			350,657			600,211			455,662

	$	1,055,056		$	1,100,947		$	1,495,370		$	1,210,956

The accompanying notes are an integral part of these condensed consolidated financial statements.

The accompanying notes are an integral part of these consolidated financial statements.

~~The accompanying notes are an intergral part of these consolidated financial statements.~~

The accompanying notes are an integral part of these consolidated financial statements.

~~The accompanying notes are an integral part of these consolidated financial statements.~~

Cabot Oil & Gas Corporation and its subsidiaries are engaged in the 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 exploration and exploitation, ~~almost~~ exclusively within the continental United ~~States.~~

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 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 have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s common stock.

In ~~June 2001,~~March 2005, the Financial Accounting Standards Board (FASB) issued FASB ~~approved~~Interpretation (FIN) No. 47, “Accounting for ~~issuance~~Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation ofA conditional asset retirement ~~cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that~~obligation is defined as an asset retirement ~~cost should~~activity in which the timing and/or method of settlement are dependent on future events that may be ~~capitalized as part~~outside the control of the ~~cost of the related long-lived asset and subsequently allocated to expense using~~Company. FIN No. 47 states that a systematic and rational method. The adoption of SFAS 143 resulted in (1) an increase of total liabilities, because more retirement obligations are required to be recognized, (2) an increase in the recognized cost of assets, because the retirement costs are added to the carrying amount of the long-lived assets, and (3) an increase in operating expense, because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of thecompany must record a liability when incurred for conditional asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. The Company adopted the statement on January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 has been reported as a cumulative effect of a change in accounting principle in January 2003.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” SFAS 148 amends SFAS 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition for a voluntary change toif the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the ~~method used on the reported results. The provisions~~obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of ~~SFAS 148 are~~these liabilities. FIN No. 47 is effective ~~for financial statements~~ for fiscal years ending after December 15, ~~2002.~~2005. The Company’s financial position, results of operations and cash flows were not impacted by this Interpretation, since all asset retirement obligations are currently recorded.

~~In January 2003,~~On April 4, 2005, the FASB issued ~~Financial Interpretation~~FASB Staff Position (FSP) FAS 19-1 “Accounting for Suspended Well Costs.” This staff position amends FASB Statement No. ~~46, “Consolidation~~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 ~~Variable Interest Entities – An Interpretation~~accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of ~~ARB No. 51” (FIN 46 or Interpretation). FIN 46~~reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made 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 salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the Staff Position requires the annual 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 for a period greater than one year after the completion of drilling and 3) an ~~interpretation~~aging of ~~Accounting Research Bulletin 51, “Consolidated Financial Statements,”~~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 ~~addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective~~the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. For the Company’s disclosures, refer to Note 2 of the ~~Interpretation is~~Notes to ~~provide guidance on~~ the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. At December 31, 2003 the Company did not have any entities that would qualify for consolidation in accordance with the provisions of FIN 46. Therefore, the adoption of FIN 46 did not have an impact on the Company’s consolidated financial statements.

In ~~April 2003~~May 2005, the FASB issued SFAS ~~149, “Amendment~~No. 154, “Accounting Changes and Error Corrections-A replacement of APB Opinion No. 20 and FASB Statement ~~133 on Derivative Instruments~~No. 3.” In order to enhance financial reporting consistency between periods, SFAS No. 154 modifies the requirements for the accounting and ~~Hedging Activities.” SFAS 149 amends~~reporting of the direct effects of changes in accounting principles. Under APB Opinion No. 20, the cumulative effect of voluntary changes in accounting principle was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB Opinion No. 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively applied in the earliest period possible to the balance sheet accounts and ~~clarifies~~a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change is required to be disclosed. The statement also provides that changes in accounting for ~~derivative instruments, including certain derivative instruments embedded~~depreciation, depletion or amortization should be treated as changes in ~~other contracts~~accounting estimate inseparable from a change in accounting principle and ~~hedging activities under~~that disclosure of the preferability of the change is required. SFAS ~~133. The amendments set forth in SFAS 149 require that contracts with comparable characteristics be accounted for similarly. SFAS 149~~No. 154 is ~~generally~~ effective for ~~contracts entered into or modified~~accounting changes made in fiscal years beginning after June 30, 2003 (with a few exceptions) and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively only. The adoption of SFAS 149 did not have an impact on the Company’s consolidated financial statements.

In ~~May 2003~~December 2004, the FASB issued SFAS ~~150,~~No. 123(R), “Share-Based Payment.” SFAS No. 123(R) revises SFAS No. 123, “Accounting for ~~Certain Financial Instruments~~Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at 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. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS No. 123(R) will be effective beginning with ~~Characteristics~~the first annual or interim reporting period of ~~both Liabilities and Equity.~~the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, the Company will not adopt this SFAS until the first quarter of 2006. The Company plans to use the modified prospective application method as detailed in SFAS No. 123(R). At this time, management does not believe that the adoption of SFAS No. 123(R) will materially impact the Company’s operating results, nor will there be any impact on future cash flows. See “Stock-Based Compensation” below for further information.

In October 2005, the FASB issued FSP FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as defined in FASB Statement No. 123(R).” This ~~Statement establishes standards for how~~FSP provides guidance on the definition and practical application of “grant date” as described in SFAS No. 123(R). The grant date is described as the date that the employee and employer have met a mutual understanding of the key terms and conditions of an ~~issuer classifies~~award. The other elements of the definition of grant date are: 1) the award must be authorized, 2) the employer must be obligated to transfer assets or distribute equity instruments so long as the employee has provided the necessary service and ~~measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that~~3) the employee is ~~within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. This Statement was developed in response to concerns expressed~~affected by ~~preparers, auditors, regulators, investors, and other users of financial statements about issuers´ classification~~changes in the ~~statement of financial position of certain financial instruments that have characteristics of both liabilities~~company’s stock price. To determine the grant date, the Company is allowed to use the date the award is approved in accordance with its corporate governance requirements so long as the three elements described above are met. Furthermore, the recipient cannot negotiate the award’s terms and ~~equity but that have been presented either entirely as equity or between~~conditions with the ~~liabilities section~~employer and the ~~equity section~~key terms and conditions of the ~~statement~~award are communicated to all recipients within a reasonably short time period from the approval date. The Company will adopt this FSP in conjunction with the adoption of ~~financial position. This Statement also addresses questions about~~SFAS No. 123(R).

In November 2005, the ~~classification~~FASB issued FSP FAS 123(R)-3 “Transition Election Related to Accounting for the Tax Effects of ~~certain financial instruments~~Share-Based Payment Awards,” which provides a simpler, more practical transition election relating to the calculation of the “APIC pool.” The APIC pool is defined as the pool of excess tax benefits available to absorb tax deficiencies occurring after the adoption of SFAS No. 123(R). Under this FSP, companies can elect to perform simpler computations to derive the beginning balance of the APIC pool as well as the impact on the APIC pool of fully vested and outstanding awards as of the SFAS No. 123(R) adoption date. The beginning balance can be computed by taking the sum of all tax benefits incurred prior to the adoption of SFAS No. 123(R) from stock-based compensation plans less the tax effected (using a blended statutory rate) pro forma stock-based compensation cost. In addition, increases to the APIC pool for fully vested awards can be calculated by multiplying the tax rate times the tax benefit of the deduction. The calculation of any awards that ~~embody obligations to issue equity shares.~~

Inare partially vested or granted after the SFAS No. 123(R) adoption date will not be affected by this FSP and will be calculated in accordance with SFAS ~~150, companies~~No. 123(R)

which requires that only the excess tax benefit or deficiency of the tax deduction over the tax effect of the compensation cost recognized should be considered for the APIC pool. Also under the FSP, all tax benefits recognized on fully vested awards and the excess tax benefits for partially vested and new awards will be reported on the Statement of Cash Flows as a component of financing activities. Companies will have up to one year after adopting SFAS No. 123(R) to decide to elect and disclose whether they plan to use the alternative method or the original method prescribed in SFAS No. 123(R) for the calculation of the APIC pool. The Company will adopt this FSP in conjunction with ~~consolidated entities that will terminate~~the adoption of SFAS No. 123(R).

In February 2006, the FASB issued FSP FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event.” Within certain share-based payment plans, a company can be required to settle outstanding options upon the occurrence of certain events, such as a change in control or liquidity of a company or the death or disability of the shareholder. This FSP amends paragraphs 32 and A229 of SFAS No. 123(R) to incorporate a probability assessment by a specified date, such as limited-life partnerships, will have to measure the liabilities for the other owners’ interests in those limited-life entities based on the fair values of the limited-life entities’ assets. Period-to-period changes in the liabilities are to be reported in the consolidated income statement as interest costs. As a result of SFAS 150, liability amounts and related interest costs may be significantly greater than the minority interests previously recognized. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this standard did not have an impact on the Company’s consolidated financial statements.

~~Management has been made aware of an issue regarding the application of provisions of SFAS 141, Business Combinations and~~company. Under SFAS No. 142, Goodwill and Other Intangible Assets ( SFAS 142 ) to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, Cabot and other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities ( SFAS 69 ). Also under consideration is whether SFAS 142 requires registrants to provide the additional disclosures prescribed by SFAS 142 for intangible assets for costs associated with mineral rights.

If123(R), it is ~~ultimately determined~~required that ~~SFAS 142 requires the Company to reclassify costs associated with mineral~~

~~rights from property~~options and equipment to intangible assets, management currently believes that its results of operations and financial condition would not be affected, since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. In addition, costs associated with mineral rights would continue to be characterized as oil and gas property costs in the Company’s required disclosures under SFAS 69.

At December 31, 2003, the Company had net undeveloped leaseholds of approximately $63.0 million that would be classified on its balance sheet as intangible undeveloped leaseholds, and developed leaseholds of approximately $318.4 million (net of accumulated depletion) that wouldsimilar instruments be classified as ~~intangible developed leaseholds~~liabilities if the ~~Company applied~~entity can be required under any circumstances to settle the ~~interpretation currently being discussed.~~

~~On December 23, 2003,~~instrument in cash or other assets. Under the ~~FASB issued SFAS 132, “Employers’ Disclosures about Pensions~~FSP, a cash settlement feature that can be exercised only upon the occurrence of a contingent event that is outside of the employee’s control does not meet the criteria for liability classification, and ~~Other Postretirement Benefits,” an amendment~~should remain to be classified in equity, unless it becomes probable that the contingent event will occur. The effective date for the guidance in this FSP is upon the initial adoption of SFAS ~~87, 88, and 106, and a revision~~No. 123(R). The Company will adopt this FSP in conjunction with the adoption of SFAS ~~132. This statement revises employers’ disclosures about pension plans~~No. 123(R).

Inventories are comprised of natural gas and ~~other postretirement benefit plans. It does not change~~oil in storage, tubular goods and well equipment and pipeline imbalances. All inventory balances are carried at the ~~measurement~~lower of cost or ~~recognition of those plans required by SFAS 87, “Employers’ Accounting for Pensions,” SFAS 88, “Employers’ Accounting for~~

~~Settlements~~market. Natural gas and ~~Curtailments of Defined Benefit Pension Plans~~oil in storage is valued at average cost. Tubular goods and for Termination Benefits,” and SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” The new rules require additional disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other postretirement benefit plans. The required information should be provided separately for pension plans and for other postretirement benefit plans. The new disclosures are effective for 2003 calendar year financial statements.

Natural gas gathering and pipeline operations normally include ~~exchange~~imbalance arrangements with ~~customers and suppliers.~~the pipeline. The volumes of natural gas due to or from the Company under ~~exchange agreements~~imbalance arrangements are recorded at ~~average~~actual selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net value of ~~exchanged~~the natural gas imbalance is included in ~~inventories~~inventory in the consolidated balance sheet.

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, 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.

In the absence 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. Its costs can, however, continue to be capitalized if a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility.

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. ~~During 2002, the Company recorded total impairments of $2.7 million.~~ In 2003, the Company recorded impairments related to the loss of a reversionary interest in its Kurten field and a field in the East region. These impairments totaled $93.8 million.

~~In 2002,~~ During 2004, the Company recorded total 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.$3.5 million. During ~~2001,~~2005, the Company recorded a total impairment of $6.9 million primarily related to three Gulf Coast fields for which capitalized cost exceeded the future undiscounted cash flows. Additionally, one natural gas processing plant in the Rocky Mountains was written down to fair market value.did not record any impairments.

~~Capitalized~~Development costs of proved oil and gas properties, ~~after considering~~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 ~~reserves.~~and proved reserves, respectively. The costs of unproved oil and gas properties are generally combined and ~~amortized~~impaired 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 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 amortized over 12 to 25 years, gathering and compression equipment is amortized over 10 years and storage equipment and facilities are amortized over 10 to 16 years. Certain other assets are ~~also~~ depreciated on a straight-line ~~basis.~~

~~Prior~~basis over 3 to ~~the adoption of SFAS 143~~10 years. Buildings are depreciated on ~~January 1, 2003, future estimated plug and abandonment costs were accrued~~a straight-line basis over the productive life of certain oil and gas properties when the residual value of well equipment was not sufficient to cover the plug and abandonment liability. The accrued liability for plug and abandonment costs was included in accumulated depreciation, depletion and amortization. As a component of accumulated depreciation, depletion and amortization, future plug and abandonment costs were $17.1 million at December 31, 2002 and $14.4 million at December 31, 2001. The total estimated liability to plug and abandon all wells was $53.0 million at December 31, 2002 and $50.8 million at December 31, 2001, excluding the residual value of well equipment. See Note 13, “Adoption of SFAS 143, Accounting for Asset Retirement Obligations”, for additional information.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.

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 ~~other liabilities~~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 ~~4 for a listing~~3 of the ~~Company’s liabilities~~Notes to the Consolidated Financial Statements for the ~~current year ended.~~

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. The Company realized ~~$9.7~~$11.4 million, ~~$5.7~~$9.2 million, and ~~$2.9~~$9.7 million of brokered natural gas margin in 2005, 2004, and 2003, ~~2002, and 2001,~~ respectively.

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 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.

This account ~~includes~~may include credit balances from outstanding checks in zero balance cash accounts. ~~The~~These credit balances are referred to as book overdrafts, as a component of Accounts Payable on the Balance Sheet. There were no credit balances from outstanding checks in zero balance cash accounts included in accounts payable at December 31, 2005 and 2004 as sufficient cash was ~~$2.7~~available for offset.

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 Sheet, was $5.6 million and $5.3 million at December 31, ~~2003, which is reflected as an increase in short-term borrowings in financing activities in the Consolidated Statement of Cash Flows. There was no reclassification necessary at December 31, 2002.~~

From time to time, the Company enters into derivative contracts, such as natural gas and crude oil price swaps or costless price collars, as a hedging strategy to manage commodity price risk associated with its inventories, production or other contractual commitments. ~~These~~All hedge transactions are ~~executed for purposes other than trading.~~subject to the Company’s risk management policy which does not permit trading activities. Gains or losses on these hedging activities are generally recognized over the period that ~~the inventory,~~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 be recognized currently in the results of operations.

~~A derivative instrument qualifies as a hedge if all of the following tests are met:~~

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 ~~correlation~~the hedge is no longer ~~exists,~~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 ~~12,~~10 of the Notes to the Consolidated Financial ~~Instruments,~~Statements for further discussion.

On January 1, 2001, the Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities”. SFAS 133 requires all derivatives to be recognized in the statement of financial position as either assets or liabilities and measured at fair value. In addition, all hedging relationships must be designated, reassessed and documented according to the provisions of SFAS 133. SFAS 138 amended portions of SFAS 133 and was adopted with SFAS 133.

All hedge transactions are subject to the Company’s risk management policy which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on a quarterly basis going forward, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

The Company accounts for stock-based compensation in accordance with the intrinsic value based method ~~recommended~~prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” Under the intrinsic value based method, the Company records no compensation ~~cost~~expense for stock options granted when the exercise price for options granted is equal to the ~~excess, if any,~~fair value of the ~~quoted market price~~Company’s common stock on the date of the ~~stock at grant date over the amount an employee must pay to acquire the stock.~~

SFAS No. 123, “Accounting for Stock-Based Compensation”, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure”, outlines a fair value based method of accounting for stock options or similar equity instruments.

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 to stock-based employee compensation. The Earnings per Share amounts for prior periods have been retroactively adjusted to reflect the 3-for-2 split of the Company’s common stock effective March 31, 2005.

~~The assumptions used in the fair value method calculation as well as additional stock based compensation information are disclosed in the following table.~~

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. As of January 1, 2006, the Company will adopt SFAS No. 123(R), as discussed above in the “Recently Issued Accounting Pronouncements” section.

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 is expected to reduce the Company’s compensation expense related to these options by approximately $0.2 million for 2006.

The assumptions used in the fair value method calculation as well as additional stock based compensation information are disclosed in the following table.

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. At December 31, ~~2003,~~2005, and ~~2002,~~2004, the cash and cash equivalents are primarily concentrated in ~~one~~two financial ~~institution.~~institutions. The Company periodically assesses the financial condition of these institutions and believes that any possible credit risk is minimal.

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.

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 ~~Company’s~~ most significant ~~financial~~ estimates ~~are based on the remaining~~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 ~~reserves (see Supplemental Oil~~properties, natural gas, natural gas liquids and ~~Gas Information).~~crude oil revenues and expenses, as well as estimates of expenses related to legal, environmental and other contingencies, depreciation, depletion and amortization, pension and postretirement obligations and deferred income taxes. Actual results could differ from those estimates.

In August 2004 we determined that deferred tax assets and liabilities associated with current and non-current assets and liabilities that had historically been classified in long-term deferred income taxes should instead be classified as current and non-current deferred tax assets and liabilities based on the classification of the related asset and liability for financial reporting purposes. Accordingly, we have revised our consolidated balance sheet to reflect this change in classification. Such revisions had no impact on our Consolidated Statement of Operations, Consolidated Statement of Cash Flows, Consolidated Statement of Stockholders’ Equity or Consolidated Statement of Comprehensive Income.

~~The significant effects of the revisions on our consolidated balance sheets from the amounts previously reported are summarized in the following tables (in thousands of dollars):~~


	December 31,						December 31,
	2003			2002
	(In Thousands)
*(In thousands)*							2005			2004
Unproved Oil and Gas Properties	$	86,918		$	76,959		$	107,787		$	94,795
Proved Oil and Gas Properties		1,469,751			1,459,240			1,970,407			1,646,841
Gathering and Pipeline Systems		146,909			137,137			178,876			160,951
Land, Building and Improvements		4,758			4,884			4,892			4,860
Other		28,658			29,457			33,077			31,261

		1,736,994			1,707,677			2,295,039			1,938,708
Accumulated Depreciation, Depletion and Amortization		(841,039	)		(735,923	)		(1,056,984	)		(944,627	)

	$	895,955		$	971,754		$	1,238,055		$	994,081

As of January 1, 2005, the Company adopted FSP FAS 19-1, “Accounting for Suspended Well Costs.” Upon adoption of the FSP, the Company evaluated all existing capitalized exploratory well costs under the provisions of the FSP. For further details on the provisions of this FSP, see Note 1 of the Notes to the Consolidated Financial Statements. The following table reflects the net changes in capitalized exploratory well costs during 2005, 2004 and 2003.

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:

At December 31, 2005 and 2003, the Company had no wells that had completed drilling and a determination of whether proved reserves existed could not be made.

At December 31, 2004, the Company had 3 wells that had completed drilling and a determination of whether proved reserves existed could not be made. One well was in the Rocky Mountains area and reached total depth in November 2004. It could not be completed due to the Bureau of Land Management stipulation which prohibited activity until the summer of 2005. Two wells in Canada completed drilling in October and December 2004. These wells were awaiting completion or sidetracking which was anticipated to commence by May 2005. Additional operations were performed on each of these wells, and all were determined to be unsuccessful. In 2005, $8.0 million was charged to expense for these wells, which was made up of $3.1 million for the Rocky Mountains area well and $4.9 million for the two wells in Canada.

During 2005, the Company did not record any impairments. During 2004, the Company recorded an impairment of $3.5 million. The impairment was recorded on a two-well field in south Louisiana and was due to production performance issues related to water encroachment. This impairment charge was recorded due to the capitalized cost of the field exceeding the future undiscounted cash flows. This charge is reflected in the operating results of the Company and was measured based on discounted cash flows utilizing a discount rate appropriate for risks associated with the related field.

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. 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 No. 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 impairment charge in 2003 of $87.9 million ($54.4 million after-tax). This impairment charge is reflected in the 2003 Statement of Operations as an operating expense but did not impact our cash flows.

During 2003 the Company divested of certain non-strategic assets. ~~These~~The primary assets ~~include~~sold included 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.

Prior to the adoption of SFAS 143 on January 1, 2003, future estimated plug and abandonment costs were accrued over the productive life of certain oil and gas properties when the residual value of well equipment was not sufficient to cover the plug and abandonment liability. The accrued liability for plug and abandonment costs was included in Accumulated Depreciation, Depletion and Amortization. Total future plug and abandonment costs of $17.1 million and $1.1 million, recorded at December 31, 2002, have been reclassified from Accumulated Depreciation, Depletion and Amortization and Other Accrued Liabilities, respectively, to Other Long-Term Liabilities due to the adoption of SFAS 143. These reclassifications were made to conform to the current period presentation. See Note 13 for additional discussion regarding the adoption of SFAS 143.


	December 31,						December 31,
	2003			2002
	(In Thousands)
*(In thousands)*							2005			2004
Accounts Receivable
Trade Accounts	$	79,439		$	65,796		$	147,016		$	105,378
Joint Interest Accounts		13,312			6,601			14,319			13,554
Current Income Tax Receivable		—			2,479			12,239			10,796
Other Accounts		81			619			315			1,312

		92,832			75,495			173,889			131,040
Allowance for Doubtful Accounts		(5,407	)		(5,467	)		(5,641	)		(5,286	)

	$	87,425		$	70,028		$	168,248		$	125,754

Inventories
Natural Gas and Oil in Storage							$	18,279		$	17,631
Tubular Goods and Well Equipment								7,161			6,387
Pipeline Imbalances								(824	)		31

							$	24,616		$	24,049

Other Current Assets
Commodity Hedging Contracts - SFAS 133	$	1,152		$	634
Derivative Contracts							$	1,736		$	2,906
Drilling Advances		6,443			558			2,169			6,180
Prepaid Balances		4,325			2,131			6,939			4,173
Other Accounts		3,086			1,957			304			246

	$	15,006		$	5,280		$	11,148		$	13,505

Accounts Payable
Trade Accounts	$	11,872		$	12,358		$	18,227		$	12,808
Natural Gas Purchases		5,751			6,058			12,208			8,669
Royalty and Other Owners		28,001			20,254			49,312			35,369
Capital Costs		21,964			13,900			37,489			26,203
Taxes Other Than Income		3,280			3,076			10,329			5,634
Drilling Advances		5,721			7,254			5,760			7,102
Wellhead Gas Imbalances		2,085			2,817			2,175			1,991
Other Accounts		6,269			6,902			4,506			7,193

	$	84,943		$	72,619		$	140,006		$	104,969

Accrued Liabilities
Employee Benefits	$	9,105		$	8,751		$	9,020		$	10,123
Taxes Other Than Income		13,359			9,887			16,188			14,191
Interest Payable		6,368			7,076			6,818			6,569
Commodity Hedging Contracts - SFAS 133		36,582			20,680
Deferred Income Taxes (Restated)		1,826			602
Other Accounts		4,344			1,918			3,133			1,725

	$	71,584		$	48,914		$	35,159		$	32,608

Other Liabilities
Postretirement Benefits Other Than Pension	$	2,132		$	1,843		$	6,517		$	4,717
Accrued Pension Cost		6,232			8,486			5,904			5,089
Commodity Hedging Contracts - FAS 133		3,051			—
Rabbi Trust Deferred Compensation Plan								4,883			4,199
Accrued Plugging and Abandonment Liability		36,848			18,151			42,991			40,375
Taxes Other Than Income and Other		6,114			5,654
Other Accounts								6,899			6,649

	$	54,377		$	34,134		$	67,194		$	61,029

~~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.~~

In May 1990, the Company issued an aggregate principal amount of $80 million of its 12-year 10.18% Notes (10.18% Notes) to a group of nine institutional investors in a private placement offering. The 10.18% Notes required five annual $16 million principal payments each May starting in 1998. The Company paid the outstanding principal balance of $32 million, together with accrued interest and a $0.9 million prepayment penalty (which was recorded as a component of interest expense) in May 2001.

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 starting in November 2005, and the Company made its first $20 million payment during 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.

To partially fund the cash portion of the acquisition of Cody Company in August 2001, the Company issued $170 million of Notes to a group of seven institutional investors in a private placement transaction in July 2001. 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 be~~is 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:

The Notes were issued under the same Note Purchase Agreement as the 7.19% Notes.

~~The~~On December 10, 2004, the Company ~~has a $250 million~~amended its Revolving Credit Agreement ~~(Credit Facility) that utilizes~~(credit facility) with a group of nine banks. The credit facility allows for borrowings of $250 million, of which $90 million was outstanding at December 31, 2005. The facility can be expanded up to $350 million, either with the existing banks or new banks. This credit facility is unsecured. The term of the ~~Credit Facility~~credit facility expires in ~~October 2006.~~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 ~~three~~six months to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or pay down ~~one-third~~one-sixth of the excess during each of the ~~three~~six months.

Interest rates under the ~~Credit Facility~~credit facility are based on Euro-Dollars (LIBOR) or Base Rate (Prime) indications, plus a margin. These associated margins ~~are subject to~~ increase if the total indebtedness is ~~either~~50% or greater, greater than ~~60%~~75% or ~~80%~~greater than 90% of the Company’s debt limit of ~~$520~~$530 million, which can be expanded up to $630 million, as shown below.

The Company’s effective interest rates for the ~~Credit Facility~~credit facility in the years ended December 31, 2005, 2004, and 2003 ~~2002,~~were 6.9%, 4.2% and ~~2001 were~~ 1.9%, ~~3.4%, and 7.6%,~~ respectively. As of December 31, 2005, the weighted average interest rate on the Company’s credit facility was 7.25%. As of December 31, 2004, the Company had no borrowings outstanding on its credit facility. The ~~Credit Facility~~credit facility provides for a commitment fee on the unused available balance at an annual rate of ~~three-eighths~~one-quarter of 1%. The ~~Credit Facility~~credit facility also contains various customary restrictions, which include the following:

The Company was in compliance with all covenants contained in its various debt agreements at December 31, ~~2003~~2005 and ~~2002.~~

The Company has a 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 fixed income investments and equity securities. 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, ~~2003.~~

The Company has a 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 ~~are~~is comprised of the following:


*(In thousands)*	2003			2002			2001			2005			2004			2003
Qualified
Current Year Service Cost	$	1,481		$	1,056		$	914		$	2,485		$	1,619		$	1,481
Interest Accrued on Pension Obligation		1,515			1,362			1,198
Interest Cost											1,896			1,697			1,515
Expected Return on Plan Assets		(999	)		(991	)		(1,064	)		(1,507	)		(1,474	)		(999	)
Net Amortization and Deferral		88			88			88
Recognized Loss (Gain)		415			21			(28	)
Amortization of Prior Service Cost											99			88			88
Recognized Net Actuarial Loss											921			383			415

Net Periodic Pension Cost	$	2,500		$	1,536		$	1,108		$	3,894		$	2,313		$	2,500


*(In thousands)*										2005			2004			2003
Non-Qualified
Current Year Service Cost										$	(682	)	$	395		$	280
Interest Cost											85			381			163
Amortization of Prior Service Cost											77			77			77
Recognized Net Actuarial (Gain) / Loss											(22	)		428			187

Net Periodic Pension (Income) / Cost										$	(542	)	$	1,281		$	707

The following table illustrates the funded status of the Company’s pension plans at December 31:

The change in the combined projected benefit obligation of the Company’s qualified and non-qualified pension plans during the last three years is explained as follows:

The change in the ~~combined~~qualified plan assets at fair value of the Company’s ~~qualified and non-qualified~~ pension ~~plans~~plan during the last three years is explained as follows:


*(In thousands)*	2003			2002			2001			2005			2004			2003
Beginning of Year	$	10,279		$	9,909		$	11,801		$	18,092		$	18,683		$	10,279
Actual Return on Plan Assets		2,446			(1,280	)		(1,527	)		1,544			957			2,446
Employer Contribution		6,735			4,080			584			5,000			2,000			6,735
Benefits Paid		(613	)		(2,237	)		(695	)		(611	)		(3,371	)		(613	)
Expenses Paid		(164	)		(193	)		(254	)		(260	)		(177	)		(164	)

End of Year	$	18,683		$	10,279		$	9,909		$	23,765		$	18,092		$	18,683

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)*	2003			2002			2001			2005			2004			2003
Funded Status(1)	$	14,864		$	15,762		$	9,985		$	17,446		$	17,974		$	14,864
Unrecognized Gain (Loss)		(12,540	)		(9,745	)		(2,413	)
Unrecognized Prior Service Cost		(735	)		(899	)		(1,064	)
Unrecognized Net Actuarial Loss											(15,397	)		(14,220	)		(12,540	)
Unrecognized Net Prior Service Cost											(514	)		(570	)		(735	)

Net Amount Recognized	$	1,589		$	5,118		$	6,508		$	1,535		$	3,184		$	1,589

Accrued Benefit Liability – Qualified Plan	$	2,664		$	7,857		$	6,423
Accrued Benefit Liability – Non-Qualified Plan		3,171			338			816
Accrued Benefit Liability - Qualified Plan										$	5,904		$	5,089		$	2,664
Accrued Benefit Liability - Non-Qualified Plan											1,204			3,579			3,171
Intangible Asset		(4,246	)		(3,077	)		(731	)		(454	)		(570	)		(735	)
Accumulated Other Comprehensive Income											(5,119	)		(4,914	)		(3,511	)

Net Amount Recognized	$	1,589		$	5,118		$	6,508		$	1,535		$	3,184		$	1,589

The amounts included in Other Comprehensive Income as a result of increases in the minimum liability of the Company’s pension plans are as follows as of December 31:

Assumptions used to determine projected ~~post-retirement~~pension benefit obligations ~~and~~are as follows:

The long-term expected rate of return on plan assets used in ~~2003~~2005, 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.

At December 31, 2005 and 2004, the non-qualified pension plan did not have plan assets. The plan assets of the Company’s qualified ~~and non-qualified~~ pension ~~plans~~plan at December 31, ~~2003~~2005 and ~~2002,~~2004, by asset category are as follows:


	2003				2002				2005					2004
*(In thousands)*	Amount		Percent		Amount		Percent		Amount			Percent		Amount		Percent
Equity securities	$	11,722	63	%	$	7,059	69	%	$	19,556		82	%	$	13,934	77	%
Debt securities		3,349	18	%		3,012	29	%		840		4	%		3,226	18	%
Other⁽¹⁾		3,612	19	%		208	2	%		3,369		14	%		932	5	%

Total	$	18,683	100	%	$	10,279	100	%	$	23,765	��	100	%	$	18,092	100	%

The Company’s investment strategy for benefit plan assets is to invest in funds to maximize athe return over the long-term, subject to an appropriate level of ~~risk, and to achieve a minimum five percent annual real rate of return on the total portfolio.~~risk. Additionally, the objective is for each class of ~~the equity portion of the pension plan assets is~~investments to ~~have a rate of return that exceeds the Standard & Poors 500 index by a minimum of two percent annually~~outperform its representative benchmark over the ~~long-term. To achieve these objectives~~long term. The Company generally targets a portfolio of assets that are ~~invested with~~within a range of ~~60 percent~~approximately 60% to ~~80 percent~~80% for equity securities and ~~20 percent~~approximately 20% to ~~40 percent~~40% for fixed ~~income.~~income securities.

The funding levels of the pension plans are in compliance with standards set by applicable law or regulation. In ~~2004~~2005 the Company did not have any required minimum funding obligations; however, it chose to fund $5 million into the plan. In 2006 the Company does not have any required minimum funding ~~obligations.~~obligations for the qualified pension plan. The Company will fund less than $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 ~~2004.~~2006.

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:

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. Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 245 retirees and their dependants at the end of 2005 and 251 retirees and their dependants at the end of 2004. The measurement date used to measure postretirement benefits other than pensions is December 31, 2005.

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, 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. The remaining unamortized balance is $3.9 million which will be amortized over the next six years.

Postretirement benefit costs recognized during the last three years are as follows:

The funded status of the Company’s postretirement benefit obligation at December 31, 2005, 2004 and 2003 is comprised of the following:

The change in the accumulated postretirement benefit obligation during the last three years is presented as follows:

Assumptions used to determine projected postretirement benefit obligations and postretirement costs are as follows:

The health care cost trend rate used to measure the expected cost from 2000 to 2003 for medical benefits to retirees was 8%. Provisions of the plan existing at that time would have prevented significant future increases in employer cost after 2000. During the years ended December 31, 2005 and 2004, the plan was amended in several areas effective January 1, 2006. As of January 1, 2006, coverage provided to participants age 65 and older will be under a fully-insured arrangement which replaces the former self-funded plan. Benefits under this new arrangement are expected to be comparable to benefits under the self-funded plan. The Company subsidy will be limited to 60% of the expected annual fully-insured premium. For all participants of any age, the Company subsidy for all retiree medical and prescription drug benefits, beginning January 1, 2006, is 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 purchased individual life insurance policies on a fully insured basis for all retirees retiring before January 1, 2006. Effective January 1, 2006, postretirement life insurance benefits will not be provided to new retirees.

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:

The Company expects to contribute approximately $0.6 million to the postretirement benefit plan in 2006.

The following estimated benefit payments under the Company’s postretirement plans, which reflect expected future service, as appropriate, are expected to be paid as follows:

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduces 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 the Company has amended the postretirement benefit plan to exclude prescription drug benefits to participants age 65 and older effective January 1, 2006, management believes this FSP will not have an impact on operating results, financial position or cash flows of the Company.

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 $1.6 million, $1.4 million ~~$1.3 million,~~ and ~~$1.0~~$1.4 million in ~~2003, 2002,~~2005, 2004, and ~~2001,~~2003, respectively. The ~~plan contribution rose in 2003, 2002 and 2001 due to an increase in~~Company matches employee contributions dollar-for-dollar on the ~~Company’s matching program. Effective July 1, 2001, the Company increased its dollar-for-dollar matching limit from 4% to~~first 6% of an employee’s pretax earnings. The Company’s ~~Common Stock~~common stock is an investment option within the SIP.

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~~If the employee’s base salary and bonus deferrals cause the employee to not receive the full 6% company match to the Savings Investment Plan, the Company will make a contribution ~~and those assets are invested in instruments selected by~~annually into the ~~employee.~~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. At December 31, ~~2003,~~2005, the balance in the Deferred Compensation Plan’s rabbi trust was ~~$3.6~~$4.9 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 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. Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 244 retirees at the end of 2003 and 246 retirees at the end of 2002. The measurement date used to measure postretirement benefits other than pensions is December 31, 2003.

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduces 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 FASB Staff Position 106-1, 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. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require the Company to change previously reported information. Currently, management is considering the impact of this Act on the Company’s plan and the possible economic consequences. However, management does not believe the accounting treatment will have a material impact on the consolidated financial statements of the Company.

When the Company adopted SFAS 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, over a period of 20 years.

~~Postretirement benefit costs recognized during the last three years are as follows:~~

The health care cost trend rate used to measure the expected cost in 2000 for medical benefits to retirees was 8%. Provisions of the plan should prevent significant future increases in employer cost after 2000.

A one-percentage-point increase or decrease in health care cost trend rates for future periods would not have a material impact on the accumulated net postretirement benefit obligation or the total postretirement benefit cost recognized. Company costs are substantially capped at 2000 levels and the retirees assume the majority of any future increases in costs.

~~The funded status of the Company’s postretirement benefit obligation at December 31, 2003, and 2002 is comprised of the following:~~

~~The change in the accumulated postretirement benefit obligation during the last three years is presented as follows:~~

Total income taxes were different than the amounts computed by applying the statutory federal income tax rate as follows:


	Year Ended December 31,									Year Ended December 31,
*(In thousands)*	2003			2002			2001			2005			2004			2003
Statutory Federal Income Tax Rate		35	%		35	%		35	%		35	%		35	%		35	%
Computed “Expected” Federal Income Tax	$	15,065		$	8,322		$	26,092		$	82,682		$	48,518		$	15,065
State Income Tax, Net of Federal Income Tax Benefit		1,334			737			2,758			7,030			4,353			1,334
Other, Net		(1,336	)⁽¹⁾		(1,385	)⁽²⁾		(1,385	)⁽³⁾		(1,923	)⁽¹⁾		(2,625	)⁽²⁾		(1,336	)⁽³⁾

Total Income Tax Expense	$	15,063		$	7,674		$	27,465		$	87,789		$	50,246		$	15,063

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:

As of December 31, ~~2003,~~2005, the Company had a net operating loss carryforward of ~~$14.2~~$50.3 million for state income tax reporting purposes, the majority of which will expire between ~~2010~~2013 and ~~2018~~2025 and none available for regular federal income tax purposes. ~~The Company does not have any alternative minimum~~It is expected that these deferred tax ~~credit carryforwards available at December 31, 2003~~benefits will be utilized prior to ~~offset regular income taxes in future years.~~

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 the East. The remaining terms on these agreements range from 2 to 22 years and require the Company to pay transportation demand charges regardless of the amount of pipeline capacity utilized by the Company.

Future obligations under firm gas transportation agreements in effect at December 31, 2005 are as follows:

The Company also has three drilling rigs in the Gulf Coast under contract that are not yet delivered and two existing rigs in the Gulf Coast under contract through 2008. As of December 31, 2005, the Company is obligated over the next 4 years to pay $104.3 million as follows:

Subsequent to December 31, 2005, the Company entered into an agreement for one additional drilling rig in the Gulf Coast. The total commitment over the next four years is $27.4 million, of which $0.8 million, $9.1 million, $9.1 million and $8.4 million will be paid out during the years 2006, 2007, 2008 and 2009, respectively.

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 ~~six~~four more years. Most of the Company’s leases expire within five years and may be renewed. Rent expense under such arrangements totaled ~~$8.5~~$9.1 million, ~~$8.8~~$8.7 million, and ~~$7.7~~$8.5 million for the years ended December 31, 2005, 2004, and 2003, ~~2002, and 2001,~~ respectively.

Future minimum rental commitments under non-cancelable leases in effect at December 31, ~~2003~~2005 are as follows:

The Company is a defendant in various ~~lawsuits and is involved~~legal proceedings arising in ~~other gas contract issues.~~the normal course of our business. All known liabilities are ~~fully~~ accrued based on management’s best estimate of the potential loss. ~~In management’s opinion, final judgments or settlements, if any, which may~~While the outcome and impact of such legal proceedings on the Company cannot be ~~awarded in connection~~predicted with ~~any one or more~~certainty, management believes that the resolution of these ~~suits and claims would~~proceedings through settlement or adverse judgment will not have a ~~significant impact~~material adverse effect on the ~~results of operations,~~Company’s consolidated financial position or cash ~~flows of any period.~~

flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

In June 2000, the Company was sued by two overriding royalty owners in Wyoming state court for unspecified damages. The plaintiffs requested class certification under the Wyoming Rules of Civil Procedure and alleged that the Company improperly deducted costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claimed that the Company 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 was recently able to settle the case and the State District Court Judge recently entered his order approving the settlement. The settlement was for a total of $2.25 million. 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.~~court, as reported in previous filings. The plaintiffs ~~in the federal case have~~ made ~~the same general~~ claims pertaining to deductions from their overriding royalty asand claims concerning penalties for improper reporting. As a result of several decisions by the ~~plaintiffs in~~Court favorable to the ~~Wyoming state court case but have not asked for class certification. That case is on hold awaiting a Wyoming Supreme Court decision on two certified questions.~~

Although management believes that a number of the Company’s defenses are supported by Wyoming case law, two letter decisions handed down by state district court judges in other cases do not support certain of the defenses. In one of the casesCompany, the case ~~has been~~was settled soin September 2005 with no ~~order will be entered. In the other case a generic order has been entered adopting the~~

~~letter decision by reference. It is not known what effect, if any, the decision, will have on the pending case. In addition, in 2000 a district court judge’s decision supported the defenses of~~payment from the Company and ~~that decision was recently orally confirmed~~a dismissal with prejudice of all claims by ~~another state district court judge. Accordingly, there is a split of authority concerning~~plaintiffs. The settlement included provisions for reporting and payment going forward. Management has reversed the ~~interpretation of the reporting penalty provisions of the Wyoming Royalty Payment Act,~~reserve it had recorded regarding this case, which ~~will need to be resolved by the Wyoming Supreme Court.~~

As noted above, the judge agreed to certify two questions of state law for decision by the Wyoming State Supreme Court. The Wyoming State Supreme Court has agreed to decide both questions, and these decisions should dispose of important issues in the pending federal case. The federal judge refused, however, to certify a question relating to the issue of the proper calculation of damages for failure to provide certain information required by statutehad an immaterial impact on ~~overriding royalty owner check stubs that had been decided adversely to~~ the Company’s position in the state district court letter decision. After the federal judge’s refusal to certify this issue, the plaintiffs reduced the damages they were claiming. Based upon the plaintiffs expert witness report filed in March 2003, the plaintiffs are now claiming $21 million in total damages which can be broken down into $15.7 million for alleged violations of the check stub reporting statute and the remainder for all other damages. In the opinion of our outside counsel, Brown, Drew & Massey, LLP the likelihood of the plaintiffs recovering the stated damages for violation of the check stub reporting statute is remote.

The Company is vigorously defending the case. The Company has a reserve that management believes is adequate to provide for the potential liability based on its estimate of the probable outcome of this case. Should circumstances change, the potential impact may materially affect quarterly or annual results of operations and cash flows. However, management does not believe it would materially impact ourconsolidated financial ~~position.~~

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 allege that the Company failed to pay royalty based upon the wholesale market value of the gas, ~~produced,~~ that ~~the Company has~~it had taken improper deductions from the royalty and ~~has~~ 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 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.~~proceedings.

~~The Company had removed the lawsuit to federal court; however, in February 2003, we received an order remanding the lawsuit back to state court.~~ Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. ~~A hearing~~The Court entered an order on June 1, 2005 granting the ~~plaintiffs’~~ motion for class ~~certification was held on October 20, 2003, and proposed findings of fact and conclusions of law were submitted~~certification. The parties have negotiated a modification to the ~~court~~order which will result in the dismissal of the claims related to the gas sales contract settlement in connection with the Columbia Gas Transmission bankruptcy proceedings and that will limit the claims to those arising on and after December ~~5, 2003.~~17, 1991. The ~~trial is currently scheduled for March 29, 2004. Based on the current status of discovery,~~Court has postponed the trial date ~~is likely~~from April 17, 2006, in light of a case pending before the West Virginia Supreme Court of Appeals which may decide issues of law that may apply to ~~be continued at~~the issue of deductibility of post-production expenses. The Company intends to challenge the class certification order by filing a ~~later date.~~Petition for Writ of Prohibition with the West Virginia Supreme Court of Appeals.

~~The investigation into this claim continues and it is in the discovery phase.~~ The Company is vigorously defending the case. ~~The Company~~A reserve has ~~reserves it~~been established that management believes ~~are~~is adequate ~~to provide for these potential liabilities~~ based on its estimate of the probable outcome of this matter. Should circumstances change, the potential impact may materially affect quarterly or annual results of operations and cash flows. However, management does not believe it would materially impact the Company’s financial position.

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. ~~The plaintiffs~~Plaintiffs filed their Second Supplemental Original Petition on November 12, 2004 and their Third Supplemental Original Petition on February 22, 2005 (which added Wynn-Crosby 1996, Ltd. and Dominion Oklahoma Texas Exploration & Production, Inc.). 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, a subsidiary of 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.~~ 1998.

The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in ~~the surface and~~ 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 trial date of May 19, 2003 was~~

~~cancelled~~Plaintiffs claim that they acquired title to the property by adverse possession. Plaintiffs also assert the discovery rule and a ~~new trial date has not been set. The~~claim of fraudulent concealment to avoid the affirmative defense of limitations. In August 2005, the case was abated until late February 2006, during which time the parties are allowed to amend pleadings or add additional parties to the litigation. Due to the abatement of the case, 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 ~~$13 million. The~~$15.7 million, and that the carrying value of this property is approximately ~~$35~~$33.6 million. Co-defendants Shell Oil Company and Shell Western E&P have filed a motion for summary judgment seeking dismissal of plaintiffs’ causes of action on multiple grounds. The Company was in the process of joining in that motion, when the 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 held in December 2003. The Court has permitted plaintiffs additional time to gather more information, and it is anticipated that the court will hold a second hearing on the motion. The Company has joined in the motion.

Although the investigation into this claim ~~has just begun,~~continues, 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 determine whether the carrying value of the property is recoverable. Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential ~~outcome.~~

loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.

In April 2004, the Company’s wholly owned subsidiary, Cody Energy, LLC, filed suit in state court 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 under the terms of the Joint Operating Agreement. Some of the co-working interest owners elected not to participate. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.

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 $10.2 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, however, could be significantly impacted in the reporting periods in which such matters are resolved.


	Year Ended December 31,						Year Ended December 31,
*(In thousands)*	2003		2002		2001		2005		2004		2003
Interest	$	18,298	$	25,112	$	16,295	$	17,366	$	16,415	$	18,298
Income Taxes	$	19,267	$	266	$	14,395		47,142		29,861		19,267

~~For~~The Company recorded benefits of $3.7 million, $2.6 million and $1.0 million for the ~~year~~years ended December 31, 2005, 2004 and 2003, ~~the Company recorded a benefit of $2.7 million~~respectively, for a tax ~~deduction~~deductions taken due to employee stock option ~~exercises.~~

On ~~May 3, 2001,~~April 29, 2004, the ~~Second Amended~~2004 Incentive Plan was approved by the shareholders. Under the 2004 Incentive Plan, incentive and ~~Restated~~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 to the automatic award of an option to purchase 15,000 shares of common stock on the date the non-employee directors first join the board of directors. A total of 2,550,000 shares of common 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 ~~approved by~~subsumed into the ~~shareholders.~~2004 Incentive Plan (342,597 shares post-split). Under ~~these two plans (Incentive Plans), incentive and non-statutory stock options, stock appreciation rights (SARs) and~~the 2004 Incentive Plan, no more than 900,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 1,500,000 shares may be issued pursuant to incentive stock options. Awards outstanding under the Prior Plans will remain outstanding in accordance with their original terms and conditions.

During 2005, the Board of Directors granted a series of 110,200 performance share awards to ~~key employees and officers of~~ the ~~Company, and non-statutory stock options may be granted to non-employee directors~~executives of the Company. ~~A maximum~~These awards are earned based on the comparative performance of ~~4,200,000~~the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three year vesting period ending on

April 30, 2008. Depending on the Company’s performance, employees may earn up 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 2005, the Company granted 19,600 restricted stock units to the non-employee Directors of ~~Common Stock may~~the Company. These units immediately vest and will be ~~issued under~~paid out whenever the ~~Incentive Plans. There are no shares available for award under any previous equity plan. All~~Director ceases to be a Director of the Company. For all restricted stock ~~options awarded under~~units, the ~~Incentive Plans have a maximum term~~Company recognized compensation expense equal to the market value of ~~five years from~~ the Company’s common stock on the grant date of ~~grant, vesting over time. The options are issued at market value on~~ the ~~date of grant. No SARs have been granted under the Incentive Plans.~~

Information regarding stock options under the Company’s 2004 Incentive Plan and the Prior Plans is summarized below:

For each of the three most recent years, the price range for outstanding options was ~~$17.44~~$11.63 to ~~$27.30~~$23.32 per share. The following tables provide more information about the options by exercise price and year.

Options with exercise prices between ~~$17.44~~$15.01 and ~~$20.00~~$23.32 per share:

The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the ~~Common Stock~~common 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.

In August 1998, the Board of Directors authorized the Company to repurchase up to two million shares of outstanding ~~Common Stock~~common stock at market prices. As a result of the 3-for-2 split of the Company’s common stock in March 2005, this figure has been adjusted to three million shares. The timing and amount of these stock purchases are determined at the discretion of management. The Company may use the repurchased shares to fund stock compensation programs presently in existence, or for other corporate purposes. ~~As of~~During the year ended December 31, ~~1998,~~2005, the Company ~~had~~ repurchased ~~302,600 shares, or 15% of the total authorized number of~~452,300 shares for a total cost of approximately ~~$4.4~~$19.2 million. ~~No additional~~The repurchased shares ~~have been repurchased. The~~are held as treasury stock. Since the authorization date, the Company has repurchased 1,513,850 shares, or 50% of the total shares authorized for repurchase, for a total cost of approximately $39.2 million. In 2005, the stock repurchase plan was funded from ~~increased borrowings on the revolving credit facility.~~cash flow from operations. No treasury shares have been delivered or sold by the Company subsequent to the repurchase.

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-hundredth~~a 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 Stock~~common 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 Stock~~common 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 Stock~~common 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, ~~2003~~2005 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.

The 3-for-2 split of the Company’s common stock was consummated 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. As a result of the stock split, 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 two-thirds of one one-hundredth of a share of preferred stock at a purchase price of approximately $36.67 per two-thirds of one one-hundredth of a share. The redemption price of each right is now two-thirds of a cent. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s common stock.

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 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 the Company’s financial position, results of operations or cash flows.

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~~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 Facility~~credit facility approximates fair value because this instrument bears interest at rates based on current market rates.

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, ~~2003,~~2005, the Company had 32nine cash flow hedges open: 15eight natural gas price collar arrangements and ~~17 natural gas price swap arrangements. Additionally, the Company had four~~one crude oil ~~financial instruments and one natural gas financial instrument open at December 31, 2003, that did not qualify for hedge accounting under SFAS 133.~~collar arrangement. At December 31, ~~2003,~~2005, a ~~$33.9~~$20.7 million ($~~21.0~~12.9 million net of tax) unrealized loss was recorded to Accumulated Other Comprehensive Income, along with a ~~$39.6~~$22.4 million short-term derivative liability and a ~~$1.2~~$1.7 million short-term derivative ~~receivable.~~receivable, which is shown in Other Current Assets on the Balance Sheet. The change in ~~derivative~~the fair value ~~for~~of derivatives designated as hedges that is effective is initially recorded to Accumulated Other Comprehensive Income. The ineffective portion, if any, of the ~~current~~change in the fair value of derivatives designated as hedges, and ~~prior periods have been included~~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.

~~The following table summarizes the realized and unrealized impact of derivative activity reflected in the respective line item in Operating Revenues.~~

Assuming no change in commodity prices, after December 31, ~~2003~~2005 the Company would expect to reclassify to ~~earnings,~~the Statement of Operations, over the next 12 months, ~~$20.3~~$12.9 million in after-tax ~~expenditures~~charges associated with commodity ~~derivatives.~~hedges. This reclassification represents the net liability associated with open positions currently not reflected in earnings at December 31, ~~2003~~2005 related to anticipated ~~2004~~2006 production.

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 ~~our~~its production. These derivatives are not held for trading purposes. Under these price swaps, the Company receives a fixed price on a notional quantity of natural gas and 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 the Company’s Revolving Credit Agreement, the aggregate level of commodity hedging must not exceed 80% of the anticipated future equivalent production during the period covered by the hedges.~~ During ~~2003,~~2005, natural gas price swaps covered ~~34,806~~20,557 Mmcf, or ~~48%~~28% of ~~our~~the Company’s gas production, fixing the sales price of this gas at an average of ~~$4.49~~$5.14 per Mcf.

At December 31, ~~2003,~~2005, the Company had no open natural gas price swap contracts covering ~~our 2004 and 2005 production as follows:~~

From time to time, the Company enters into natural gas and crude oil derivative arrangements that do not qualify for hedge accounting under SFAS No. 133. These financial instruments are recorded at fair value at the balance sheet date. At December 31, ~~2003,~~2005, the Company ~~had four open crude oil swap arrangements and one natural gas swap arrangement with an unrealized net loss~~did not have any of ~~$2.6 million and $0.8 million, respectively, recognized in Operating Revenues.~~

~~Throughout 2002 and 2003,~~From time to time, the Company ~~believed that the pricing environment provided a strategic opportunity to significantly reduce the price risk on a portion of our production through the use of~~enters into natural gas and crude oil ~~collars.~~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

During ~~2003,~~2005, natural gas price collars covered ~~16,136~~15,157 Mmcf ~~or 22%~~ of the Company’s gas production, or 21% of gas production with a weighted average floor of ~~$4.46~~$5.59 per Mcf and a weighted average ceiling of ~~$5.41~~$8.61 per Mcf. ~~Additionally, during 2003,~~During 2005, an oil price collar covered 365 Mbbl of the ~~Company had~~Company’s crude oil ~~price collars which covered 362 Mbbls,~~production, or ~~25%~~21% of ~~the Company’s~~crude oil production with a weighted average floor of ~~$24.75~~$40.00 per ~~bbl~~Mbbl and a weighted average ceiling of ~~$28.86~~$50.50 per ~~bbl. These crude oil contracts expired in June 2003.~~Mbbl.

At December 31, ~~2003,~~2005, the Company had open natural gas price collar contracts covering ~~our 2004 and 2005~~its 2006 production as follows:

At December 31, ~~2003,~~2005, the Company had noone open crude oil price collar ~~arrangements to cover future production.~~contract covering its 2006 production as follows:

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.

The Company adopted SFAS 133 on January 1, 2001. Under SFAS 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 period, these instruments are marked-to-market. The gain or loss on the change in fair value is recorded as Other Comprehensive Income, a component of equity, to the extent that the derivative instrument is an effective hedge. Under SFAS 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. Any portion of the gains or losses that are considered ineffective under the SFAS 133 test are recorded immediately as a component of operating revenue on the statement of operations.

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 each of 2005, 2004 and 2003, approximately 11% of the Company’s total sales were made to one ~~customer. In 2002, approximately 14% of the Company’s total sales were made to one customer. In 2002, this~~ customer operated certain properties in which the Company has 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 the Company would deal directly if the customer either ceased to exist or stopped buying its portion of the production. In 2001 the Company had no sales to any customer that exceeded 10% of its total gross revenues.

~~13.~~11. Adoption of SFAS 143, ““Accounting for Asset Retirement ~~Obligations”~~Obligations”

Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that 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 No. 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 will also be recorded for meter stations, pipelines, processing plants and compressors. At December 31, ~~2003~~2005 there are 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~~was no impact on the Company’s cash flows as a result of adopting SFAS No. 143.

Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement liabilities, settled liabilities, and revisions of estimated cash flows. 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 ~~year-ended~~years ended December 31, 2005, 2004 and 2003 was $1.4 million, $1.7 million and $2.1 ~~million.~~

The following ~~unaudited pro forma information has been prepared to give effect to~~table reflects the ~~adoption~~changes of ~~SFAS 143 as if it had been adopted on January 1, 2002 and January 1, 2001.~~the asset retirement obligations during the current period.

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 Eastern and Rocky Mountains properties. Due to the repurchase of these tax credit wells in December 2002 there was no monetization revenue realized in 2003. Revenue from these monetized credits was $2.0 million in 2002 and 2001. 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 August 2001, the Company acquired the stock of Cody Company, the parent of Cody Energy LLC (Cody acquisition) for $231.2 million consisting of $181.3 million of cash and 1,999,993 shares of common stock valued at $49.9 million. Substantially all of the proved reserves of Cody Company are located in the onshore Gulf Coast region. The acquisition was accounted for using the purchase method of accounting. As such, the Company reflected the assets and liabilities acquired at fair value in the Company’s balance sheet effective August 1, 2001 and the results of operations of Cody Company beginning August 1, 2001. The Company recorded a purchase price of approximately $315.6 million, which was allocated to specific assets and liabilities based on certain estimates of fair value resulting in approximately $302.4

million allocated to property and $13.2 million allocated to working capital items. The remaining $78.0 million of the recorded purchase price reflected a non-cash item pertaining to the deferred income taxes attributable to the differences between the tax basis and the fair value of the acquired oil and gas properties, and acquisition related fees and costs of $6.4 million.

The following unaudited pro forma condensed income statement information for the year ended December 31, 2001 has been prepared to give effect to the Cody acquisition as if it had occurred on January 1, 2001

As part of the Cody acquisition, the Company acquired an interest in certain oil and gas properties in the Kurten field, as general partner of a partnership and as an operator. Prior to the liquidation of the partnership and the divestiture of the Company’s interest in the field, it had an interest of approximately 25%, including a one percent interest in the partnership. The liquidation and divestiture was effective July 31 and November 1, respectively, of 2003. The divestiture yielded proceeds of $7.6 million and resulted in a pre-tax gain of $1.8 million. Under the partnership agreement, the Company had the right to a reversionary working interest that would have brought its ultimate interest to 50% upon the limited partner reaching payout. Under the partnership agreement, the limited partner had the option to trigger a liquidation of the partnership. 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, the Company 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, the limited partners decision and the Company’s decision to proceed with the liquidation, it performed an impairment review which resulted in an after-tax charge of approximately $54.4 million. This impairment charge is reflected in the 2003 Statement of Operations as an operating expense but did not impact the Company’s cash flows.

Basic earnings per common share (EPS) is computed by dividing net income (the numerator) by the weighted 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 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 average shares outstanding for the year ended December 31, ~~2003, 2002~~2005, 2004 and ~~2001:~~2003:


	December 31,			December 31,
	2003	2002	2001	2005	2004	2003
Shares - basic	32,049,664	31,736,975	30,275,906	48,856,491	48,732,504	48,074,496
Dilution effect of stock options and awards at end of period	240,621	338,972	408,361	868,904	606,297	360,932

Shares - diluted	32,290,285	32,075,947	30,684,267	49,725,395	49,338,801	48,435,428

Stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect	965,777	1,174,507	913,310	—	—	1,448,666

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, ~~2003, 2002,~~2005, 2004, and ~~2001~~2003 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 ~~9, 2004,~~3, 2006, 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, ~~2003,~~2005, 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)*	2003		2002		2001		2005		2004		2003
Proved Reserves
Beginning of Year	1,060,959		1,036,004		959,222		1,134,081		1,069,484		1,060,959
Revisions of Prior Estimates	(6,122	)	14,405		(44,266	)	(1,543	)	(7,850	)	(6,122	)
Extensions, Discoveries and Other Additions	105,497		64,945		99,911		185,884		140,986		105,497
Production	(71,906	)	(73,670	)	(69,162	)	(73,879	)	(72,833	)	(71,906	)
Purchases of Reserves in Place	1,590		26,262		91,290		17,567		5,384		1,590
Sales of Reserves in Place	(20,534	)	(6,987	)	(991	)	(14	)	(1,090	)	(20,534	)

End of Year	1,069,484		1,060,959		1,036,004		1,262,096		1,134,081		1,069,484

Proved Developed Reserves	812,280		819,412		804,646		944,897		857,834		812,280

Percentage of Reserves Developed	76.0	%	77.2	%	77.7	%	74.9	%	75.6	%	76.0	%

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.

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,						Year Ended December 31,
*(In thousands)*	2003		2002		2001		2005		2004		2003
Property Acquisition Costs, Proved⁽¹⁾	$	1,524	$	8,799	$	245,079	$	73,127	$	3,953	$	1,524
Property Acquisition Costs, Unproved⁽¹⁾		14,056		4,869		21,116		22,126		18,250		14,056
Exploration and Extension Well Costs⁽²⁾⁽¹⁾		83,147		52,012		91,261		102,957		85,415		83,147
Development Costs		77,006		55,165		90,246		208,124		136,311		77,006

Total Costs	$	175,733	$	120,845	$	447,702	$	406,334	$	243,929	$	175,733

The results of operations for the Company’s oil and gas producing activities were as follows:


	Year Ended December 31,						Year Ended December 31,
*(In thousands)*	2003		2002		2001		2005		2004		2003
Operating Revenues	$	404,503	$	280,379	$	339,064	$	581,849	$	439,988	$	404,503
Costs and Expenses
Production		77,315		63,823		58,382		103,477		84,015		77,315
Other Operating		20,090		21,731		22,656		30,120		27,787		20,090
Exploration⁽¹⁾		58,119		40,167		71,165		61,840		48,130		58,119
Depreciation, Depletion and Amortization		195,659		102,086		89,286		119,122		114,906		195,659

Total Costs and Expenses		351,183		227,807		241,489		314,559		274,838		351,183

Income Before Income Taxes		53,320		52,572		97,575		267,290		165,150		53,320
Provision for Income Taxes		18,662		18,400		34,151		100,353		60,361		18,662

Results of Operations	$	34,658	$	34,172	$	63,424	$	166,937	$	104,789	$	34,658

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:

Under the Standardized Measure, future cash inflows were estimated by applying ~~year-end~~year end oil and gas prices ~~adjusted for fixed and determinable escalations~~ to the estimated future production of ~~year-end~~year end proved reserves.

The average prices related to proved reserves at December 31, ~~2003, 2002,~~2005, 2004, and ~~2001~~2003 for natural gas ($ per Mcf) were ~~$5.96, $4.41,~~$9.53, $6.26 and ~~$2.65,~~$5.96, respectively, and for oil ($ per Bbl) were ~~$30.94, $30.39,~~$58.48, $41.24 and ~~$18.56,~~$30.94, respectively. Future cash inflows were reduced by estimated future development and production costs based on ~~year-end~~year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying ~~year-end~~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.


	Year Ended December 31,									Year Ended December 31,
*(In thousands)*	*2003⁽¹⁾***			*2002⁽¹⁾***			*2001⁽¹⁾*			2005			2004			2003
Future Cash Inflows	$	6,742,214		$	5,236,349		$	3,107,668		$	12,700,390		$	7,561,728		$	6,742,214
Future Production Costs		(1,390,398	)		(1,137,615	)		(823,988	)		(2,271,917	)		(1,577,787	)		(1,390,398	)
Future Development Costs		(310,923	)		(284,165	)		(266,833	)		(536,333	)		(396,431	)		(310,923	)
Future Income Tax Expenses											(3,588,877	)		(2,009,644	)		(1,800,519	)

Future Net Cash Flows Before Income Taxes		5,040,893			3,814,569			2,016,847
Future Net Cash Flows											6,303,263			3,577,866			3,240,374
10% Annual Discount for Estimated Timing of Cash Flows		(2,844,855	)		(2,098,669	)		(1,065,747	)		(3,652,030	)		(1,997,509	)		(1,760,966	)

Standardized Measure of Discounted Future Net Cash Flows Before Income Taxes		2,196,038			1,715,900			951,100
Future Income Tax Expenses, Net of 10% Annual Discount⁽²⁾		(716,630	)		(460,547	)		(185,074	)
Standardized Measure of Discounted Future Net Cash Flows⁽¹⁾										$	2,651,233		$	1,580,357		$	1,479,408

Standardized Measure of Discounted Future Net Cash Flows	$	1,479,408		$	1,255,353		$	766,026

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves


	Year Ended December 31,									Year Ended December 31,
*(In thousands)*	2003			2002			2001			2005			2004			2003
Beginning of Year	$	1,255,353		$	766,026		$	2,409,832		$	1,580,357		$	1,479,408		$	1,255,353
Discoveries and Extensions, Net of Related Future Costs		235,079			112,269			100,084			494,773			321,026			235,079
Net Changes in Prices and Production Costs⁽¹⁾		475,026			703,874			(2,545,349	)		1,278,303			(17,976	)		475,026
Accretion of Discount		171,590			95,110			353,625			235,843			219,604			171,590
Revisions of Previous Quantity Estimates, Timing and Other		(35,691	)		51,944			(358,134	)		(49,550	)		(46,115	)		(35,691	)
Development Costs Incurred		27,529			20,516			26,158			61,802			32,940			27,529
Sales and Transfers, Net of Production Costs		(330,800	)		(216,555	)		(280,682	)		(471,638	)		(357,939	)		(330,800	)
Net Purchases (Sales) of Reserves in Place		(62,596	)		(2,357	)		119,149			91,180			10,853			(62,596	)
Net Change in Income Taxes		(256,082	)		(275,474	)		941,343			(569,837	)		(61,444	)		(256,082	)

End of Year	$	1,479,408		$	1,255,353		$	766,026		$	2,651,233		$	1,580,357		$	1,479,408


*(In thousands, except per share amounts)*	First			Second		Third		Fourth		Total		First		Second		Third		Fourth		Total
2003
2005
Operating Revenues	$	135,916		$	126,756	$	125,471	$	121,248	$	509,391	$	144,074	$	151,884	$	161,757	$	225,082	$	682,797
Impairment of Long-Lived Assets		87,926			—		5,870		—		93,796
Impairment of Oil and Gas Properties (1)													—		—		—		—		—
Operating Income		(46,691	)		34,850		43,630		34,798		66,587		38,044		61,722		59,023		99,942		258,731
Net Income (Loss)⁽¹⁾		(39,223	)		17,904		23,220		19,231		21,132
Net Income													20,762		35,422		33,756		58,505		148,445
Basic Earnings per Share⁽¹⁾⁽²⁾	$	(1.23	)	$	0.56	$	0.73	$	0.60	$	0.66		0.43		0.72		0.69		1.20		3.04
Diluted Earnings per Share⁽¹⁾⁽²⁾	$	(1.23	)	$	0.55	$	0.73	$	0.60	$	0.65		0.42		0.71		0.68		1.18		2.99

2002
2004
Operating Revenues	$	75,073		$	89,584	$	85,549	$	103,550	$	353,756	$	136,604	$	119,742	$	119,423	$	154,639	$	530,408
Impairment of Long-Lived Assets		1,063			—		—		1,657		2,720
Operating Income (Loss)		4,996			9,850		15,111		19,131		49,088
Net Income (Loss)		(798	)		2,121		6,125		8,655		16,103
Impairment of Oil and Gas Properties (1)													—		—		3,458		—		3,458
Operating Income													36,090		36,439		34,278		53,846		160,653
Net Income													19,011		19,318		17,822		32,227		88,378
Basic Earnings per Share(2)	$	(0.03	)	$	0.07	$	0.19	$	0.27	$	0.51		0.39		0.40		0.37		0.66		1.81
Diluted Earnings per Share(2)	$	(0.03	)	$	0.07	$	0.19	$	0.27	$	0.50		0.39		0.39		0.36		0.65		1.79

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Changes in Internal Control over Financial Reporting

As of the end of December 31, ~~2003,~~2005, 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 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 issuer in the reports that it files or submits under the Exchange Act.

In August 2004 we determined that deferred tax assets and liabilities associated with current and non-current assets and liabilities that had historically been classified in long-term deferred income taxes should instead be classified as current and non-current deferred tax assets and liabilities based on the classification of the related asset and liability for financial reporting purposes. We identified this deficiency and we brought it to the attention of our audit committee and auditors promptly. Accordingly, in this Form 10-K/A we revised our consolidated balance sheets at December 31, 2003 and 2002 to reflect the reclassification of deferred income taxes. We believe we have addressed this deficiency as we have implemented internal controls surrounding the calculation and review of deferred income tax classification to enhance our ability to comply with all appropriate tax and related accounting issues.

There ~~have been~~were no significant changes in the Company’s internal ~~controls, other than those related~~control over financial reporting that occurred during the fourth quarter that has materially affected, or is reasonably likely to ~~deferred income taxes,~~materially effect, the Company’s 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 ~~in other factors that could significantly affect internal controls subsequent~~detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the ~~date~~risk that controls may become inadequate because of changes in conditions, or that the ~~Company carried out its evaluation.~~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, 2005. 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, 2005, the Company’s internal control over financial reporting is effective based on those criteria.

~~- 42 -~~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, 2005 as stated in their report entitled “Report of Independent Registered Public Accounting Firm” which appears herein.

The information under the captions “Election of Directors”, “Audit Committee” and “Code of Business Conduct” in the Company’s definitive Proxy Statement in connection with the 2006 annual stockholders’ meeting are incorporated by reference. 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 in response to this item.

The information under the caption “Executive Compensation” in the Company’s definitive Proxy Statement in connection with the 2006 annual stockholders’ meeting is incorporated by reference.

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” in the Company’s definitive Proxy Statement in connection with the 2006 annual stockholders’ meeting are incorporated by reference.

The information under the caption “Fees Billed by Independent Public Accountants for Services in 2005 and 2004” in the Company’s definitive Proxy Statement in connection with the 2006 annual stockholders’ meeting is incorporated by reference.

ITEM 15. EXHIBITS AND FINANCIAL ~~STATEMENTS,~~STATEMENT SCHEDULES ~~AND REPORTS ON FORM 8-K~~

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.


~~10.6~~ Exhibit Number	~~Form of Stock Subscription Agreement between the Company and certain executive officers and directors of the Company (Registration Statement No. 33-32553).~~ Description

~~10.7~~	~~Transaction Agreement between Cabot Corporation and the Company dated February 1, 1991 (Registration Statement No. 33-37455).~~

~~10.8~~	~~Tax Sharing Agreement between Cabot Corporation and the Company dated February 1, 1991 (Registration Statement No. 33-37455).~~

~~10.9~~	Amendment Agreement (amending the Transaction Agreement and the Tax Sharing Agreement) dated March 25, 1991 (incorporated by reference from Cabot Corporation’s Schedule 13E-4, Am. No. 6, File No. 5-30636).

~~10.10~~*10.4	Savings Investment Plan & Trust Agreement of the Company (Form 10-K for 1991).

	(a)	First Amendment to the Savings Investment Plan dated May 21, 1993 (Form S-8 dated November 1, 1993).

	(b)	Second Amendment to the Savings Investment Plan dated May 21, 1993 (Form S-8 dated November 1, 1993).

	(c)	First through Fifth Amendments to the Trust Agreement (Form 10-K for 1995).

	(d)	Third through Fifth Amendments to the Savings Investment Plan (Form 10-K for 1996).

~~10.11~~*10.5	Supplemental Executive Retirement Agreements of the Company (Form 10-K for 1991).

~~10.12~~	~~Settlement Agreement and Mutual Release (Tax Issues) between Cabot Corporation and the Company dated July 7, 1992 (Form 10-Q for the quarter ended June 30, 1992).~~

~~10.13~~	~~Agreement of Merger dated February 25, 1994, among Washington Energy Company, Washington Energy Resources Company, the Company and COG Acquisition Company (Form 10-K for 1993).~~

~~10.14~~*10.6	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).

~~10.15~~*10.7	Second Amended and Restated 1994 Long-Term Incentive Plan of the Company (Form 10-K for 2001).

~~10.16~~*10.8	Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form 10-K for 2001).

~~10.17~~	~~Employment Agreement between the Company and Ray R. Seegmiller dated September 25, 1995 (Form 10-K for 1995).~~

~~10.18~~*10.9	Form of Indemnity Agreement between the Company and Certain Officers (Form 10-K for 1997).

~~10.19~~*10.10	Deferred Compensation Plan of the Company as Amended September 1, 2001 (Form 10-K for 2001).

~~10.20~~10.11	Trust Agreement dated September 2000 between Harris Trust and Savings Bank and the Company (Form 10-K for 2001).

~~10.21~~10.12	Lease Agreement between the Company and DNA COG, Ltd. dated April 24, 1998 (Form 10-K for 1998).

~~10.22~~10.13	Credit Agreement dated as of December 17, 1998, between the Company and the banks named therein (Form 10-K for 1998).

~~10.23~~	~~Letter Agreement with Puget Sound Energy Company dated September 21, 1999 (Form 10-K for 1999).~~

~~10.24~~	~~Agreement and Plan of Merger, dated June 20, 2001, among Cabot Oil & Gas Corporation, COG Colorado Corporation, Cody Company and the shareholders of Cody Company (Form 8-K for June 28, 2001).~~

	(a) Amendment to Agreement and Plan of Merger dated as of July 10, 2001 to the Agreement and plan of Merger, dated June 20, 2001, among Cabot Oil & Gas Corporation, COG Colorado Corporation, Cody Company and the shareholders of Cody Company (Form 8-K for August 30, 2001).

	~~(b) Closing Agreement dated August 16, 2001 (Form 8-K for August 30, 2001).~~

~~10.25~~*10.14	Employment Agreement between the Company and Dan O. Dinges dated August 29, 2001 (Form 10-K for 2001).


Exhibit Number		Description
31.2		302 Certification – Vice President and Chief Financial ~~Officer~~Officer.

32.1		906 ~~Certification~~Certification.

99.1		Miller and Lents, Ltd. Review Letter.

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 ~~9th~~6th of ~~August 2004.~~March 2006.


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.


	As of December 31, 2003
Balance Sheet Line Item	Previously Reported		As Restated		Increase
Deferred Income Taxes - Current Assets	$	—	$	21,935	$	21,935
*Total Current Assets*	$	121,396	$	143,331	$	21,935

Deferred Income Taxes - Non-Current Assets	$	—	$	8,920	$	8,920
*Total Assets*	$	1,024,201	$	1,055,056	$	30,855

Deferred Income Taxes - Current Liabilities⁽¹⁾	$	—	$	1,826	$	1,826
*Total Current Liabilities*	$	154,701	$	156,527	$	1,826

Deferred Income Taxes - Non-Current Liabilities	$	179,926	$	208,955	$	29,029
*Total Liabilities and Stockholders’ Equity*	$	1,024,201	$	1,055,056	$	30,855


	As of December 31, 2002
Balance Sheet Line Item	Previously Reported		As Restated		Increase
Deferred Income Taxes - Current Assets	$	—	$	14,263	$	14,263
*Total Current Assets*	$	92,162	$	106,425	$	14,263

Deferred Income Taxes - Non-Current Assets	$	—	$	15,755	$	15,755
*Total Assets*	$	1,070,929	$	1,100,947	$	30,018

Deferred Income Taxes - Current Liabilities⁽¹⁾	$	—	$	602	$	602
*Total Current Liabilities*	$	120,931	$	121,533	$	602

Deferred Income Taxes - Non-Current Liabilities	$	200,207	$	229,623	$	29,416
*Total Liabilities and Stockholders’ Equity*	$	1,070,929	$	1,100,947	$	30,018


~~PART II~~		PAGE
PART I

ITEM 61	~~Selected Historical Financial Data~~Business	53
ITEM 1A	Risk Factors	18
ITEM 1B	Unresolved Staff Comments	23
ITEM 2	Properties	23
ITEM 3	Legal Proceedings	24
ITEM 4	Submission of Matters to a Vote of Security Holders	25
	Executive Officers of the Registrant	26

PART II

ITEM 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
ITEM 6	Selected Financial Data	28
ITEM 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
ITEM 7A	Quantitative and Qualitative Disclosures about Market Risk	50
ITEM 8	Financial Statements and Supplementary Data	653
ITEM 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	93
ITEM 9A	Controls and Procedures	4294
ITEM 9B	Other Information	94

PART IVIII

ITEM 10	Directors and Executive Officers of the Registrant	94
ITEM 11	Executive Compensation	95
ITEM 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	95
ITEM 13	Certain Relationships and Related Transactions	95
ITEM 14	Principal Accounting Fees and Services	95

PART IV

ITEM 15	Exhibits and Financial ~~Statements,~~Statement Schedules ~~and Reports on Form 8-K~~	4395


	Natural Gas (Mmcf)			Liquids⁽¹⁾(Mbbl)			Total⁽²⁾ (Mmcfe)
	Developed	Undeveloped	Total	Developed	Undeveloped	Total	Developed	Undeveloped	Total
East	445,964	188,976	634,940	403	—	403	448,379	188,976	637,355
Rocky Mountains	179,730	49,629	229,359	1,631	344	1,975	189,514	51,696	241,210
Mid-Continent	163,815	21,563	185,378	913	41	954	169,295	21,811	191,106
Gulf Coast	136,417	56,344	192,761	6,077	1,943	8,020	172,882	67,999	240,881
Canada	18,971	687	19,658	103	8	111	19,591	731	20,322

Total	944,897	317,199	1,262,096	9,127	2,336	11,463	999,661	331,213	1,330,874


	Developed	Undeveloped	Total
East	735,233	251,451	986,684
West	277,246	422,015	699,261
Gulf Coast	92,380	219,403	311,783
Canada	2,190	23,762	25,952

Total	1,107,049	916,631	2,023,680


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


			West
	East		Rocky Mountains		Mid- Continent		Total		Gulf Coast		Canada		Total
Proved Reserves at Year End (Bcfe)
Developed	448.4		189.5		169.3		358.8		172.9		19.6		999.7
Undeveloped	189.0		51.7		21.8		73.5		68.0		0.7		331.2

Total	637.4		241.2		191.1		432.3		240.9		20.3		1,330.9

Average Daily Production (Mmcfe per day)	59.2		37.3		29.1		66.4		102.1		3.4		231.1
Reserve Life Index (in years)⁽¹⁾	29.5		17.7		18.0		17.8		6.5		16.2		15.8

Gross Wells	2,745		576		680		1,256		788		20		4,809
Net Wells⁽²⁾	2,550.2		252.4		471.8		724.2		515.7		3.9		3,794.0
Percent Wells Operated (Gross)	96.8	%	51.2	%	76.9	%	65.1	%	73.9	%	40.0	%	84.5	%


	Natural Gas *(Mmcf)*		Oil & Liquids *(Mbbl)*		Total *(Mmcfe)⁽¹⁾*
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

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

Proved Developed Reserves
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
December 31, 2005	944,897		9,127		999,661


	2006	2007	2008
East	12,407	55,451	43,732
West	69,180	67,322	152,744
Gulf Coast	13,168	65,559	89,485
Canada	3,118	14,155	224

Total	97,873	202,487	286,185


	Natural Gas		Oil		Total⁽¹⁾
	Gross	Net	Gross	Net	Gross	Net
East	2,720	2,538.2	25	12.0	2,745	2,550.2
West	1,201	690.5	55	33.7	1,256	724.2
Gulf Coast	622	375.0	166	140.7	788	515.7
Canada	20	3.9	0	0.0	20	3.9

Total	4,563	3,607.6	246	186.4	4,809	3,794.0


	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


Name	Age	Position	Officer Since
Dan O. Dinges	52	Chairman, President and Chief Executive Officer	2001
Michael B. Walen	57	Senior Vice President, Exploration and Production	1998
Scott C. Schroeder	43	Vice President and Chief Financial Officer	1997
J. Scott Arnold	52	Vice President, Land and Associate General Counsel	1998
Robert G. Drake	58	Vice President, Information Services and Operational Accounting	1998
Abraham D. Garza	59	Vice President, Human Resources	1998
Jeffrey W. Hutton	50	Vice President, Marketing	1995
Thomas S. Liberatore	49	Vice President, Regional Manager, East Region	2003
Lisa A. Machesney	50	Vice President, Managing Counsel and Corporate Secretary	1995
Henry C. Smyth	59	Vice President, Controller and Treasurer	1998


	High		Low		Cash Dividends
2005
First Quarter	$	38.04	$	27.78	$	0.027
Second Quarter		38.13		28.29		0.040
Third Quarter		50.81		36.05		0.040
Fourth Quarter		51.54		40.48		0.040

2004
First Quarter	$	21.93	$	19.17	$	0.027
Second Quarter		28.20		20.09		0.027
Third Quarter		30.05		25.87		0.027
Fourth Quarter		32.25		27.27		0.027


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
October 2005	—	$	—	—	1,918,750
November 2005	207,400	$	43.10	207,400	1,711,350
December 2005	225,200	$	42.95	225,200	1,486,150

Total	432,600	$	43.02


*(in $ per Mcf)*	Natural Gas Prices by Month - 2005
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	6.21	$	6.29	$	6.30	$	7.33	$	6.77	$	6.13	$	6.98	$	7.65	$	10.97	$	13.93	$	13.85	$	11.21
2005	$	5.78	$	5.84	$	5.52	$	6.28	$	6.19	$	5.55	$	6.05	$	6.58	$	7.76	$	8.94	$	8.53	$	7.78

*(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 Bbl)*	Crude Oil Prices by Month - 2005
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	46.85	$	48.05	$	54.63	$	53.22	$	49.87	$	56.42	$	59.03	$	64.99	$	65.55	$	62.27	$	58.34	$	59.45
2005	$	38.18	$	40.57	$	47.30	$	44.95	$	41.88	$	44.58	$	46.24	$	46.62	$	45.05	$	45.92	$	45.59	$	43.70

*(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 millions)*	2005		2004		2003
Capital Expenditures
Drilling and Facilities	$	249.3	$	174.0	$	102.0
Leasehold Acquisitions		22.1		18.3		14.1
Pipeline and Gathering		17.9		13.5		10.6
Other		1.4		1.6		1.8

		290.7		207.4		128.5

Proved Property Acquisitions		73.1		4.0		1.5
Exploration Expense		61.8		48.1		58.2

Total	$	425.6	$	259.5	$	188.2


			Payments Due by Year
					2007		2009		2011 &
*(In thousands)*	Total		2006		to 2008		to 2010		Beyond
Long-Term Debt⁽¹⁾	$	340,000	$	20,000	$	40,000	$	110,000	$	170,000
Interest on Long-Term Debt⁽²⁾		132,960		24,632		44,950		32,673		30,705
Firm Gas Transportation Agreements⁽³⁾		93,766		11,661		19,839		6,762		55,504
Drilling Rig Commitments⁽³⁾		104,315		26,055		68,585		9,675		—
Operating Leases		17,746		4,876		9,174		3,696		—

Total Contractual Cash Obligations	$	688,787	$	87,224	$	182,548	$	162,806	$	256,209


	Year-Ended December 31,
*(In thousands)*	2005			2004			2003
Cash Flows Provided by Operating Activities	$	364,560		$	273,022		$	241,638
Cash Flows Used by Investing Activities		(412,150	)		(255,357	)		(151,856	)
Cash Flows Provided / (Used) by Financing Activities		48,190			(8,363	)		(90,660	)

Net Increase / (Decrease) in Cash and Cash Equivalents	$	600		$	9,302		$	(878	)


	Natural Gas Price Collars
Contract Period	Volume in Mmcf	Weighted Average Ceiling / Floor		Net Unrealized Loss *(In thousands)*
As of December 31, 2005
First Quarter 2006	6,702	$	12.74 / $8.25
Second Quarter 2006	6,776		12.74 / 8.25
Third Quarter 2006	6,850		12.74 / 8.25
Fourth Quarter 2006	6,851		12.74 / 8.25

Full Year 2006	27,179	$	12.74 / $8.25	$	(20,425	)


	Crude Oil Price Collar
Contract Period	Volume in Mbbl		Weighted Average Ceiling / Floor		Net Unrealized Loss *(In thousands)*
As of December 31, 2005
First Quarter 2006	90		$	76.00 / $50.00
Second Quarter 2006	91			76.00 / 50.00
Third Quarter 2006	92			76.00 / 50.00
Fourth Quarter 2006	92			76.00 / 50.00

Full Year 2006	365		$	76.00 / $50.00	$	(317	)
		��


		Page
Report of Independent Registered Public Accounting Firm		754

Consolidated Statement of Operations for the Years Ended December 31, ~~2003, 2002~~2005, 2004 and ~~2001~~2003		856

Consolidated Balance Sheet at December 31, ~~2003~~2005 and ~~2002~~2004		957

Consolidated Statement of Cash Flows for the Years Ended December 31, ~~2003, 2002~~2005, 2004 and ~~2001~~2003		1058

Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, ~~2003, 2002~~2005, 2004 and ~~2001~~2003		1159

Consolidated Statement of Comprehensive Income for the Years Ended December 31, ~~2003, 2002~~2005, 2004 and ~~2001~~2003		1260

Notes to the Consolidated Financial Statements		1361

Supplemental Oil and Gas Information (Unaudited)		3889

Quarterly Financial Information (Unaudited)		4293


	Common Shares	Stock Par		Treaury Shares	Treasury Stock			Paid-In Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
Balance at December 31, 2002	48,200	$	4,820	454	$	(4,384	)	$	351,486	$	(12,939	)	$	11,674		$	350,657

Net Income														21,132			21,132
Exercise of Stock Options	517		52						7,716								7,768
Cash Dividends at $0.16 per Share														(5,043	)		(5,043	)
Other Comprehensive Loss											(10,196	)					(10,196	)
Stock Grant Vesting	90		9						870								879

Balance at December 31, 2003	48,807	$	4,881	454	$	(4,384	)	$	360,072	$	(23,135	)	$	27,763		$	365,197

Net Income														88,378			88,378
Exercise of Stock Options	794		79						15,034								15,113
Purchase of Treasury Stock				608		(15,631	)										(15,631	)
Performance Share Awards									2,394								2,394
Stock Grant Vesting	80		8						2,625								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	49,681	$	4,968	1,062	$	(20,015	)	$	380,125	$	(20,351	)	$	110,935		$	455,662

Net Income														148,445			148,445
Exercise of Stock Options	300		30						8,217								8,247
Purchase of Treasury Stock				452		(19,183	)										(19,183	)
Performance Share Awards									4,147								4,147
Stock Grant Vesting	101		10						4,860								4,870
Cash Dividends at $0.16 per Share														(7,213	)		(7,213	)
Other Comprehensive Income											5,236						5,236

Balance at December 31, 2005	50,082	$	5,008	1,514	$	(39,198	)	$	397,349	$	(15,115	)	$	252,167		$	600,211


	Year Ended December 31,
(*In thousands)*	2003			2002			2001
Net Income Available to Common Stockholders	$	21,132		$	16,103		$	47,084

Other Comprehensive (Loss) Income
Cumulative Effect of Change in Accounting Principle on January 1, 2001		—			—			(4,269	)
Reclassification Adjustment for Settled Contracts		47,926			6,230			(32,749	)
Changes in Fair Value of Hedge Positions		(63,014	)		(26,361	)		38,380
Adjustment to Recognize Minimum Pension Liability		(1,333	)		(2,177	)		—
Foreign Currency Translation Adjustment		(5	)		—			—
Deferred Income Tax		6,230			8,534			(527	)

Total Other Comprehensive (Loss) Income		(10,196	)		(13,774	)		835

Comprehensive Income	$	10,936		$	2,329		$	47,919


	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	%


	Debt Percentage
	Lower than 60%		60% - 80%		Higher than 80%
Euro-Dollar margin	1.250	%	1.500	%	1.750	%
Base Rate margin	0.250	%	0.500	%	0.750	%


	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	%


*(In thousands)*	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total of service and interest cost	$	12	$	(13	)
Effect on postretirement benefit obligation		131		(147	)


*(In thousands)*
2004	$	4,650
2005		4,275
2006		3,791
2007		3,538
2008		2,481
Thereafter		606

	$	19,341


	Natural Gas Price Swaps
Contract Period	Volume in Mmcf	Weighted Average Contract Price		Unrealized Loss (In Thousands)
As of December 31, 2003
*Natural Gas Price Swaps on Production in:*
First Quarter 2004	8,017	$	5.17
Second Quarter 2004	7,148		4.99
Third Quarter 2004	7,226		4.99
Fourth Quarter 2004	7,226		4.99

Full Year 2004	29,617	$	5.04	$	24,610

First Quarter 2005	2,510	$	5.13
Second Quarter 2005	2,537		5.13
Third Quarter 2005	2,565		5.13
Fourth Quarter 2005	2,565		5.13

Full Year 2005	10,177	$	5.13	$	2,284


*(In thousands)*
Carrying amount of asset retirement obligations at December 31, 2004	$	40,375
Liabilities added during the current period		1,364
Liabilities settled during the current period		(110	)
Current period accretion expense		1,419
Revisions to estimated cash flows		(57	)

Carrying amount of asset retirement obligations at December 31, 2005	$	42,991


*(In Thousands)*	2001
Revenues	$	505,528
Net Income	$	54,513
Per share - Basic	$	1.75
Per share - Diluted	$	1.73


	Liquids
	December 31,
*(Thousands of barrels)*	2003		2002		2001
Proved Reserves
Beginning of Year	18,393		19,684		9,914
Revisions of Prior Estimates	307		1,871		254
Extensions, Discoveries and Other Additions	1,723		851		2,257
Production	(2,846	)	(2,909	)	(1,996	)
Purchases of Reserves in Place	—		261		9,255
Sales of Reserves in Place	(5,474	)	(1,365	)	—

End of Year	12,103		18,393		19,684

Proved Developed Reserves	9,405		13,267		15,328

Percentage of Reserves Developed	77.7	%	72.1	%	77.9	%


Exhibit Number	Description

3.1	Certificate of Incorporation of the Company (Registration Statement No. 33-32553).

3.2	Amended and Restated Bylaws of the Company amended September 6, 2001 (Form 10-K for 2001).

3.3	Certificate of Amendment of Certificate of Incorporation (Form 8-K for July 2, 2002).

3.4	Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock (Form 8-K for July 2, 2002).

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).

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 ~~therein.~~therein (Form 10-K for 1995).

	(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).

~~4.7~~4.6	Note Purchase Agreement dated November 14, 1997, among the Company and the purchasers named therein (Form 10-K for 1997).

~~4.8~~4.7	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).

~~4.9~~4.8	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).

~~10.1~~	~~Supplemental Executive Retirement~~(a)	Amendment No. 1 to Credit Agreement ~~between the Company and Charles P. Siess, Jr.~~dated December 10, 2004 (Form 10-K for ~~1995)~~2004).

~~10.2~~*10.1	Form of Change in Control Agreement between the Company and Certain Officers (Form 10-K for 2001).

~~10.3~~	~~Letter Agreement dated January 11, 1990, between Morgan Guaranty Trust Company of New York and the Company (Registration Statement No. 33-32553).~~

~~10.4~~*10.2	Form of Annual Target Cash Incentive Plan of the Company (Registration Statement No. 33-32553).


~~Exhibit~~ ~~Number~~	~~Description~~
~~10.5~~*10.3	Form of Incentive Stock Option Plan of the Company (Registration Statement No. 33-32553).

	(a)	First Amendment to the Incentive Stock Option Plan (Post-Effective Amendment No. 1 to S-8 dated April 26, 1993).


*10.15	2004 Incentive Plan (Form 10-Q for the quarter ended June 30, 2004).

*10.16	2004 Performance Award Agreement (Form 10-Q for the quarter ended June 30, 2004).

*10.17	2004 Annual Target Cash Incentive Plan Measurement Criteria for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005).

*10.18	Form of Restricted Stock Awards Terms and Conditions for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005).

*10.19	2005 Form of Non-Employee Director Restricted Stock Unit Award Agreement (Form 8-K for May 24, 2005).

*10.20	Savings Investment Plan of the Company, as amended and restated effective January 1, 2001 (Form 10-K for 2005).

~~Exhibit~~ ~~Number~~	~~Description~~ (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).

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).

21.1	Subsidiaries of Cabot Oil & Gas Corporation.

23.1	Consent of PricewaterhouseCoopers ~~LLP~~LLP.

23.2	Consent of Miller and Lents, Ltd.

~~23.3~~	~~Consent of Brown, Drew & Massey, LLP~~

~~28.1~~	~~Miller and Lents, Ltd. Review Letter~~

31.1	302 Certification – Chairman, President and Chief Executive ~~Officer~~Officer.


Signature		Title	Date

/s/ Dan O. Dinges Dan O. Dinges		Chairman, President and Chief Executive Officer (Principal Executive Officer)	~~August 9, 2004~~
	March6, 2006

/s/ Scott C. Schroeder Scott C. Schroeder		Vice President and Chief Financial Officer (Principal Financial Officer)	~~August 9, 2004~~
	March6, 2006

/s/ Henry C. Smyth Henry C. Smyth		Vice President, Controller and Treasurer (Principal Accounting Officer)	~~August 9, 2004~~
	March6, 2006

/s/ Robert F. Bailey Robert F. Bailey		Director	~~August 9, 2004~~
	March6, 2006

/s/ John G. L. Cabot John G. L. Cabot		Director	~~August 9, 2004~~March6, 2006

/s/ David M. Carmichael David M. Carmichael		Director	March6, 2006

/s/ James G. Floyd James G. Floyd		Director	~~August 9, 2004~~March6, 2006

/s/ Robert L. Keiser Robert L. Keiser		Director	March6, 2006

/s/ Robert Kelley Robert Kelley		Director	~~August 9, 2004~~
	March6, 2006

/s/ C. Wayne Nance C. Wayne Nance		Director	~~August 9, 2004~~
	March6, 2006

/s/ P. Dexter Peacock P. Dexter Peacock		Director	~~August 9, 2004~~
	March6, 2006

/s/ William P. Vititoe William P. Vititoe		Director	~~August 9, 2004~~
	March6, 2006