UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

 


FORM 10-K

 


ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 20042005

Commission file number 1-10447

 


CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

 


 

Delaware 04-3072771

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

1200 Enclave Parkway, Houston, Texas 77077

(Address of principal executive offices including ZIP code)

(281) 589-4600

(Registrant’s telephone number)number, including area code)

 


Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class


 

Name of each exchange on which registered


Common Stock, par value $.10 per share New York Stock Exchange
Rights to Purchase Preferred Stock New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

 


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

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

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

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

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):

Large accelerated filer  x    Accelerated filer  ¨

    Non-accelerated filer  ¨

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

No  x

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, 2004)2005), as of the last business day of registrant’s most recently completed second fiscal quarter was approximately $1.4$1.7 billion.

As of January 31, 2005,2006, there were 32,414,76048,610,408 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held April 28, 2005May 4, 2006 are incorporated by reference into Part III of this report.

 



TABLE OF CONTENTS

 

      PAGE

PART I

    

ITEM 1

  

Business

  3

ITEM 1A

Risk Factors18

ITEM 1B

Unresolved Staff Comments23

ITEM 2

  

Properties

  18
23

ITEM 3

  

Legal Proceedings

  19
24

ITEM 4

  

Submission of Matters to a Vote of Security Holders

  2125

Executive Officers of the Registrant

  2226

PART II

    

ITEM 5

  

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

  23
27

ITEM 6

  

Selected Historical Financial Data

  24
28

ITEM 7

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

  25
29

ITEM 7A

  

Quantitative and Qualitative Disclosures about Market Risk

  45
50

ITEM 8

  

Financial Statements and Supplementary Data

  49
53

ITEM 9

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  89
93

ITEM 9A

  

Controls and Procedures

  90
94

ITEM 9B

  

Other Information

  9094

PART III

    

ITEM 10

  

Directors and Executive Officers of the Registrant

  90
94

ITEM 11

  

Executive Compensation

  91
95

ITEM 12

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

  91
95

ITEM 13

  

Certain Relationships and Related Transactions

  91
95

ITEM 14

  

Principal Accounting Fees and Services

  9195

PART IV

    

ITEM 15

  Exhibits and Financial Statement Schedules  9195

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.

- 2 -


PART I

ITEM 1. BUSINESS

OVERVIEW

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 WestWestern 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 East region,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 West region,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 is comprisedfocused 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 Rocky Mountainshurricanes which included the shutting in and Mid-Continentdeferring of production at the Breton Sound offshore lease, one of our largest areas the Gulf Coast region and Canada.

of offshore oil production.

In 2004,2005, 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. ThisIn the current year, this flexibility should provideallowed 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. At December 31, 2004, our debt to total capital ratio was 37%, down from 43% at the end of 2003. Natural gas production increased to 72.8 Bcf in 2004 from 71.9 Bcf in 2003. This growth was directly related to our 2003 drilling program which focused on natural gas projects. On an equivalent basis, our production level in 2004 was down slightly from 2003. We produced 84.8 Bcfe, or 232.3 Mmcfe per day, this year, as compared to 89.0 Bcfe, or 243.8 Mmcfe per day, in 2003. The growth in natural gas production was offset by the loss of production associated with the late 2003 sale of non-strategic properties and natural decline in oil production in south Louisiana. Our 2004 realized natural gas price was $5.20 per Mcf, compared to a 2003 price of $4.51. Our realized crude oil price was $31.55 per Bbl, compared to a 2003 price of $29.55. Our average hedged prices on natural gas and crude oil for 2005 anticipated production are expected to be higher than comparable prices realized from hedging in 2004. To lock in prices above historical levels for a

A portion of our production as a result of the strong commodity prices, we layered inwas covered by oil and gas hedge instruments throughout 20042005 to cover production in 20042005 and 2005.2006. At December 31, 2004, 44%2005, 33% and 25%26% of our natural gas and crude oil anticipated production, respectively, are hedged for 20052006 through the use of derivatives that qualify for hedge accounting. Including our range swaps, which do not qualify for hedge accounting, 75%As of our crude oil production is hedged for 2005. NoDecember 31, 2005, no derivatives are in place for 2006.2007. Our decision to hedge 20052006 production fits with our risk management strategy and allows the Companyus to lock in the benefit of high commodity prices on a portion of our anticipated production.

Net income of $88.4 million or $2.72 per share exceeded last year by $67.2 million or $2.06 per share. The year over year net income increase was achieved due to higher Our average hedged prices on natural gas revenues from higher commodity prices. Operating Revenues increased by $21.0 million or 4% due to strong commodity prices. Natural gas production revenues increased by $57.1 million over the prior year; this increase was partially offset by a decrease inand crude oil and condensate revenues of $21.0 million and a decreasefor 2006 anticipated production are expected to be higher than comparable prices realized in brokered natural gas revenues of $11.4 million. In addition, operating expenses decreased between 2004 and 2003 as a result of the 2003 non-cash pre-tax impairment charge of $93.8 million. Also contributing to the decrease were lower brokered natural gas cost and lower exploration expense. Net income in 2003 was also reduced by a $6.8 million cumulative effect of accounting change related to SFAS 143.

2005.

For the year ended December 31, 2004,2005, we drilled 256316 gross wells with a success rate of 95% compared to 173256 gross wells with a success rate of 89%95% for the comparable period of 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 compared to $188.2 millionof total capital and exploration spending in 2003.2004. We concentratedremain focused on our 2004strategies of balancing our capital spending program on projects balancinginvestments between acceptable risk and strongest economics, along with the strongest economics.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 MountainMountains areas. In 2004, weWe have continued that practice, to a lesser extent as we increased ourand the allocation of capital expendituresamong regions in the East2005 was similar in responsepercentage to the success ofallocation in 2004, with the 2003 drilling program. The main recipient of these dollars was Canada where we commenced our drilling program with a $16.2 million investment.Gulf Coast region being allocated an additional 12% in capital over the previous year. In 2005,2006, we plan to spend approximately $280$396 million which includes a layer of investment for new projects or property acquisitions that may arise during 2005.

Our proved reserves totaled approximately 1,202 Bcfe at December 31, 2004, of which 94% was natural gas. This reserve level was up slightly from 1,142 Bcfe at December 31, 2003 on the strength of results from our drilling program and the lack of reserve sales 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.

- 3 -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, 2004.2005.

 

   West

    West 
  East

 Rocky
Mountains


 

Mid-

Continent


 Total

 Gulf
Coast


 Canada

 Total

   East Rocky
Mountains
 Mid-
Continent
 Total Gulf
Coast
 Canada Total 

Proved Reserves at Year End (Bcfe)

           

Developed

  398.9  187.4  167.6  355.0  149.4  6.4  909.7   448.4  189.5  169.3  358.8  172.9  19.6  999.7 

Undeveloped

  151.6  50.2  21.7  71.9  67.7  1.5  292.7   189.0  51.7  21.8  73.5  68.0  0.7  331.2 
  

 

 

 

 

 

 

                      

Total

  550.5  237.6  189.3  426.9  217.1  7.9  1,202.4   637.4  241.2  191.1  432.3  240.9  20.3  1,330.9 

Average Daily Production (Mmcfe per day)

  53.6  35.9  26.5  62.4  115.3  1.0  232.3   59.2  37.3  29.1  66.4  102.1  3.4  231.1 

Reserve Life Index (in years)(1)

  28.1  18.1  19.5  18.7  5.1  N/A  14.1   29.5  17.7  18.0  17.8  6.5  16.2  15.8 

Gross Wells

  2,584  533  650  1,183  751  14  4,532   2,745  576  680  1,256  788  20  4,809 

Net Wells(2)

  2,393.3  242.6  452.9  695.5  495.4  1.5  3,585.7   2,550.2  252.4  471.8  724.2  515.7  3.9  3,794.0 

Percent Wells Operated (Gross)

  96.6% 52.9% 78.2% 66.8% 74.3% 21.4% 84.9%  96.8% 51.2% 76.9% 65.1% 73.9% 40.0% 84.5%

(1)Reserve Life Index is equal to year-end reserves divided by annual production. Canada is not calculated since initial production commenced in mid-2004. Canada has also been excluded from the Total for purposes of the reserve life index calculation.
(2)The term “net” as used in “net acreage” or “net production” throughout this document refers to amounts that include only acreage or production that is owned by Cabot Oil & Gasus and produced to itsour interest, less royalties and production due others. “Net wells” represents our working interest share of each well.

EAST REGION

Our East activities are concentrated primarily in West Virginia, and to a lesser extent in New York.Virginia. In this region, our assets include a large undeveloped acreage position, a high concentration of wells, natural gas gathering and pipeline systems, and storage capacity. Capital and exploration expenditures were $99.0 million, or 23% of our total 2005 capital spending, and $75.2 million, for 2004, or 29% of our total 2004 capital spending, and $40.6 million for 2003.spending. For 2005,2006, we have budgeted $75.3$116.1 million for capital and exploration expenditures in the region.

At December 31, 2004,2005, we had 2,5842,745 wells (2,393.3(2,550.2 net), of which 2,4972,657 wells are operated by us. There are multiple producing intervals that include the Big Lime, Weir, Berea and Devonian Shale and Oriskany formations at depths primarily ranging from 1,000 to 9,500 feet. Average net daily production in 20042005 was 53.659.2 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, 2004,2005, we had 550.5637.4 Bcfe of proved reserves (substantially all natural gas) in the East region, constituting 46%48% of our total proved reserves. This region is managed from our office in Charleston, West Virginia.

In 2004,2005, we drilled 171185 wells (167.5(179.8 net) in the East region, of which 166182 wells (163(176.8 net) were development and extension wells. In 2005,2006, we plan to drill approximately 200239 wells.

In 2004,2005, we produced and marketed approximately 8070 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 2004.2005. 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.

- 4 -


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. Cabot Oil & Gas Marketing, our subsidiary, purchases gas from local third-party producers and other suppliers to aggregate larger volumes of gas for resale.

Approximately 65% 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.

WEST REGION

Our activities in the West region are managed by a regional office in Denver.Denver, Colorado. At December 31, 2004,2005, we had 426.9432.3 Bcfe of proved reserves (96% natural gas) in the West region, constituting 36%32% of our total proved reserves.

Rocky Mountains

OurActivities in the Rocky Mountains activities are concentrated in the Green River, Wind RiverWashakie and Big Horn Basins in Wyoming and Paradox Basin in Colorado. At December 31, 2004,2005, we had 237.6241.2 Bcfe of proved reserves (95% natural gas) in the Rocky MountainMountains area, 20%or 18% of our total proved reserves. Capital and exploration expenditures in the Rocky Mountains were $41.5$45.4 million for 2004,2005, or 16%11% of our total capital and exploration expenditures, and $22.3$41.5 million for 2003. Spending for 2004 included $30.5 million for drilling activity and $7.5 million of dry hole expense and geophysical and geological procedures.2004. For 2005,2006, we have budgeted $33.6$57.8 million for capital and exploration expenditures in the area.

We had 533576 wells (242.6(252.4 net) in the Rocky Mountains area as of December 31, 2004,2005, of which 282295 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 20042005 was 35.937.3 Mmcfe.

In 2004,2005, we drilled 2949 wells (14.3(16.1 net) in the Rocky Mountains, of which 2645 wells (13.0(13.3 net) were development wells. In 2005,2006, we plan to drill 3042 wells.

Mid-Continent

Our Mid-Continent activities are concentrated in the Anadarko Basin in southwest Kansas, Oklahoma and the panhandle of Texas. Capital and exploration expenditures were $12.1$23.7 million for 2004,2005, or 5%6% of our total 20042005 capital and exploration expenditures, and $11.2$12.1 million for 2003.2004. For 2005,2006, we have budgeted $8.5$33.1 million for capital and exploration expenditures in the area.

As of December 31, 2004,2005, we had 650680 wells (452.9(471.8 net) in the Mid-Continent area, of which 508523 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 20042005 was 26.529.1 Mmcfe. At December 31, 2004,2005, we had 189.3191.1 Bcfe of proved reserves (97% natural gas) in the Mid-Continent area, 16%or 14% of our total proved reserves.

In 2004,2005, we drilled 2134 wells (18.9(21.5 net) in the Mid-Continent, all of which were development and extension wells. In 2005,2006, we plan to drill 1142 wells.

- 5 -


Our principal markets for West region natural gas are in the northwest and midwest United States. We sell natural gas to power generators, natural gas processors, local distribution companies, industrial customers and marketing companies. Currently, approximately 75% of our natural gas production in the West region is sold primarily under contracts with a term of one to three years at index-based prices. Another 23% of the natural gas production is sold under short-term arrangements at index-based prices and the remaining 2% is sold under certain fixed-price contracts. The West region properties are connected to the majority of the midwest and northwest interstate and intrastate pipelines, affording us access to multiple markets.

In 2004,2005, we produced and marketed approximately 450 barrels of crude oil/condensate per day in the West region at market responsive prices.

GULF COAST REGION

Our 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 $112.6$233.5 million for 2004,2005, or 43%55% of our total capital and exploration expenditures, and $111.6$112.6 million for 2003.2004. During 2005, we spent $72.1 million on proved property acquisitions. For 2005,2006, we have budgeted $105.0$154.4 million of our total budget for capital and exploration expenditures in the region. Our 20052006 Gulf Coast drilling program will continue to emphasize impact exploration opportunities both on and offshore, augmented by development activity in our focus areas of east Texas, north Louisiana and south Texas and throughout coastal Louisiana.

Texas.

In 2004,2005, we drilled 3139 wells (17.6(26.2 net) in the Gulf Coast region, of which 2023 wells (12.4(17.4 net) were development wells. In 20052006, we plan to drill 4255 wells. We had 751788 wells (495.4(515.7 net) in the Gulf Coast region as of December 31, 2004,2005, of which 558582 wells are operated by us. Average daily production in 20042005 was 115.3102.1 Mmcfe, compared to 124.1115.3 Mmcfe in 2003.2004. 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, 2004,2005, we had 217.1240.9 Bcfe of proved reserves (78%(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 40%50% of our natural gas sales volumes in the Gulf Coast region are sold at index-based prices under contracts with terms of one to three years. The remaining 60%50% of our sales volumes are sold at index-based prices under short-term agreements. The Gulf Coast properties are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets.

In 2004,2005, we produced and marketed approximately 5,0004,100 barrels of crude oil/condensate per day in the Gulf Coast region at market responsive prices.

- 6 -


CANADA REGION

Our activities in the Canada region are managed by a regional office in Calgary, Alberta. Our Canadian exploration, development and producing activities are concentrated in the Provinces of Alberta and British Columbia. At December 31, 2004,2005, we had 7.920.3 Bcfe of proved reserves (91%(97% natural gas) in the Canada region, constituting less than 1%2% of our total proved reserves.

Capital and exploration expenditures in Canada were $16.2$22.9 million for 2004,2005, or 6%5% of our total capital and exploration expenditures, and $0.8$16.2 million for 2003.2004. For 2005,2006, we have budgeted $16.0$30.7 million for capital and exploration expenditures in the area.

We had 1420 wells (1.5(3.9 net) in the Canada region as of December 31, 2004,2005, of which 38 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 20042005 was 1.03.4 Mmcfe.

In 2004,2005, we drilled 49 wells (1.5(3.5 net) in Canada, of which 35 wells (1.1(1.7 net) were development and extension wells. In 2005,2006, we plan to drill 1013 wells.

In 2004,2005, we produced and marketed approximately 1050 barrels of crude oil/condensate per day in the Canada region at market responsive prices.

RISK MANAGEMENT

From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. While there are many different types of derivatives available, in 20042005 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“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Commodity Price SwapsOperations” and Options“Quantitative and Qualitative Disclosures about Market Risk” for further discussion concerning our use of derivatives.

- 7 -


RESERVES

Current Reserves

The following table presents our estimated proved reserves at December 31, 2004.2005.

 

  Natural Gas (Mmcf)

  Liquids(1) (Mbbl)

  Total(2) (Mmcfe)

  Natural Gas (Mmcf)  Liquids(1)(Mbbl)  Total(2) (Mmcfe)
  Developed

  Undeveloped

  Total

  Developed

  Undeveloped

  Total

  Developed

  Undeveloped

  Total

  Developed  Undeveloped  Total  Developed  Undeveloped  Total  Developed  Undeveloped  Total

East

  396,521  151,184  547,705  401  53  454  398,927  151,500  550,427  445,964  188,976  634,940  403  —    403  448,379  188,976  637,355

Rocky Mountains

  177,454  47,911  225,365  1,657  384  2,041  187,395  50,216  237,611  179,730  49,629  229,359  1,631  344  1,975  189,514  51,696  241,210

Mid-Continent

  162,625  21,491  184,116  831  39  870  167,609  21,728  189,337  163,815  21,563  185,378  913  41  954  169,295  21,811  191,106

Gulf Coast

  115,528  54,216  169,744  5,648  2,240  7,888  149,417  67,653  217,070  136,417  56,344  192,761  6,077  1,943  8,020  172,882  67,999  240,881

Canada

  5,706  1,445  7,151  115  16  131  6,399  1,539  7,938  18,971  687  19,658  103  8  111  19,591  731  20,322
  
  
  
  
  
  
  
  
  
                           

Total

  857,834  276,247  1,134,081  8,652  2,732  11,384  909,747  292,636  1,202,383  944,897  317,199  1,262,096  9,127  2,336  11,463  999,661  331,213  1,330,874
  
  
  
  
  
  
  
  
  
                           

(1)(1)Liquids include crude oil, condensate and natural gas liquids (Ngl).
(2)(2)Natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.

The proved reserve estimates presented here were prepared by our petroleum engineering staff and reviewed by Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents concluded the following: In their judgment 1) we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues, 2) 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 2004.2005. If we had considered the impact of our hedging activities in our proved reserves, there would not have been any significant effect.

There are a number of uncertaintiesFor additional information about the risks inherent in estimating quantitiesour estimates of proved reserves, includingsee “Risk Factors—Reserve estimates depend on many factors beyondassumptions that may prove to be inaccurate. Any material inaccuracies in our control such as commodity pricing. Therefore, the reserve information in this Form 10-K represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates are often different fromor underlying assumptions could cause the quantities and net present value of crude oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Exceptour reserves to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.

- 8 -be overstated” in Item 1A.


Historical Reserves

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

 

  Natural Gas
(Mmcf)


 Oil & Liquids
(Mbbl)


 Total
(Mmcfe)(1)


 

December 31, 2001

  1,036,004  19,684  1,154,109 
  

 

 

Revision of Prior Estimates

  14,405  1,871  25,631 

Extensions, Discoveries and Other Additions

  64,945  851  70,053 

Production

  (73,670) (2,909) (91,126)

Purchases of Reserves in Place

  26,262  261  27,828 

Sales of Reserves in Place

  (6,987) (1,365) (15,179)
  

 

 

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

December 31, 2002

  1,060,959  18,393  1,171,316   1,060,959  18,393  1,171,316 
  

 

 

          

Revision of Prior Estimates

  (6,122) 307  (4,278)  (6,122) 307  (4,278)

Extensions, Discoveries and Other Additions

  105,497  1,723  115,835   105,497  1,723  115,835 

Production

  (71,906) (2,846) (88,976)  (71,906) (2,846) (88,976)

Purchases of Reserves in Place

  1,590  —    1,591   1,590  —    1,591 

Sales of Reserves in Place

  (20,534) (5,474) (53,380)  (20,534) (5,474) (53,380)
  

 

 

          

December 31, 2003

  1,069,484  12,103  1,142,108   1,069,484  12,103  1,142,108 
  

 

 

          

Revision of Prior Estimates

  (7,850) 185  (6,739)  (7,850) 185  (6,739)

Extensions, Discoveries and Other Additions

  140,986  1,074  147,426   140,986  1,074  147,426 

Production

  (72,833) (2,002) (84,847)  (72,833) (2,002) (84,847)

Purchases of Reserves in Place

  5,384  24  5,525   5,384  24  5,525 

Sales of Reserves in Place

  (1,090) —    (1,090)  (1,090) —    (1,090)
  

 

 

          

December 31, 2004

  1,134,081  11,384  1,202,383   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, 2001

  804,646  15,328  896,612 

December 31, 2002

  819,412  13,267  899,016   819,412  13,267  899,016 

December 31, 2003

  812,280  9,405  868,712   812,280  9,405  868,712 

December 31, 2004

  857,834  8,652  909,747   857,834  8,652  909,747 

December 31, 2005

  944,897  9,127  999,661 

(1)Includes natural gas and natural gas equivalents determined by using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.

- 9 -


Volumes and Prices;Prices: Production Costs

The following table presents regional historical information about our net wellhead sales volume for natural gas and crude oil (including condensate and natural gas liquids), produced natural gas and crude oil realized sales prices, and production costs per equivalent.

 

  Year Ended December 31,

  Year Ended December 31,
  2004

  2003

  2002

  2005  2004  2003

Net Wellhead Sales Volume

               

Natural Gas (Bcf)

               

Gulf Coast

   31.3   30.0   30.4   28.1   31.3   30.0

West

   21.9   23.8   25.3   23.2   21.9   23.8

East

   19.4   18.6   18.0   21.4   19.4   18.6

Canada

   0.2   —     —     1.2   0.2   —  

Crude/Condensate/Ngl (Mbbl)

               

Gulf Coast

   1,809   2,625   2,655   1,530   1,809   2,625

West

   163   193   221   172   163   193

East

   27   27   33   27   27   27

Canada

   3   —     —     18   3   —  

Produced Natural Gas Sales Price ($/Mcf)(1)

               

Gulf Coast

  $5.27  $4.78  $3.34  $6.38  $5.27  $4.78

West

   4.75   3.67   2.39   6.00   4.75   3.67

East

   5.60   5.15   3.38   8.02   5.60   5.15

Canada

   4.69   —     —     6.79   4.69   —  

Weighted Average

   5.20   4.51   3.02   6.74   5.20   4.51

Crude/Condensate Sales Price ($/Bbl)(1)

  $31.55  $29.55  $23.79  $44.19  $31.55  $29.55

Production Costs ($/Mcfe)(2)

  $0.99  $0.87  $0.70  $1.23  $0.99  $0.87

(1)(1)Represents the average realized sales price (net of hedge activity) for all production volumes (includingand royalty volumes)volumes sold by Cabot Oil & Gas during the periods shown, net of related costs (principally purchased gas royalty, transportation and storage).
(2)(2)Production costs include direct lifting costs (labor, repairs and maintenance, materials and supplies), and the costs of administration of production offices, insurance and property and severance taxes, but is exclusive of depreciation and depletion applicable to capitalized lease acquisition, exploration.exploration and development expenditures.

- 10 -

   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
                  


Leasehold Acreage

   Developed

  Undeveloped

  Total

   Gross

  Net

  Gross

  Net

  Gross

  Net

State

                  

Arkansas

  1,981  425  0  0  1,981  425

Colorado

  16,389  14,089  170,704  91,115  187,093  105,204

Kansas

  29,067  27,745  0  0  29,067  27,745

Louisiana

  49,541  39,784  47,366  45,235  96,907  85,019

Montana

  397  210  32,828  25,648  33,225  25,858

New York

  2,956  1,105  11,326  6,405  14,282  7,510

North Dakota

  0  0  870  96  870  96

Ohio

  6,259  2,422  1,613  428  7,872  2,850

Oklahoma

  167,679  117,118  13,698  9,059  181,377  126,177

Pennsylvania

  111,953  63,752  3,449  2,312  115,402  66,064

Texas

  107,754  74,051  66,149  48,130  173,903  122,181

Utah

  1,740  529  164,404  86,370  166,144  86,899

Virginia

  22,195  20,072  5,766  4,196  27,961  24,268

West Virginia

  576,944  544,737  162,033  146,605  738,977  691,342

Wyoming

  142,816  72,340  370,869  226,132  513,685  298,472

Federal Offshore

  10,933  2,218  120,244  88,673  131,177  90,891
   
  
  
  
  
  

Total

  1,248,604  980,597  1,171,319  780,404  2,419,923  1,761,001
   
  
  
  
  
  

Mineral Fee Acreage

   Developed

  Undeveloped

  Total

   Gross

  Net

  Gross

  Net

  Gross

  Net

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

  327  177  754  327  1,081  504

Virginia

  17,817  17,817  100  34  17,917  17,851

West Virginia

  97,455  79,093  51,447  49,593  148,902  128,686
   
  
  
  
  
  

Total

  133,491  111,994  64,637  52,334  198,128  164,328
   
  
  
  
  
  

Aggregate Total

  1,382,095  1,092,591  1,235,956  832,738  2,618,051  1,925,329
   
  
  
  
  
  
Canada Leasehold Acreage                  
   Developed

  Undeveloped

  Total

   Gross

  Net

  Gross

  Net

  Gross

  Net

Province

                  

Alberta

  2,560  621  4,489  1,407  7,049  2,028

British Columbia

  0  0  7,778  3,889  7,778  3,889
   
  
  
  
  
  

Total

  2,560  621  12,267  5,296  14,827  5,917
   
  
  
  
  
  

- 11 -


Total Net Acreage by Region of Operation

 

   Developed

  Undeveloped

  Total

Gulf Coast

  89,741  181,911  271,652

West

  273,328  439,399  712,727

East

  729,522  211,428  940,950

Canada

  621  5,296  5,917
   
  
  

Total

  1,093,212  838,034  1,931,246
   
  
  

   Developed  Undeveloped  Total

East

  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
         

Total Net Undeveloped Acreage Expiration by Region of Operation

The following table presents our net undeveloped acreage expiring over the next three years by operating region as of December 31, 2004.2005. The figures below assume no future successful development or renewal of undeveloped acreage.

 

  2005

  2006

  2007

  2006  2007  2008

East

  12,407  55,451  43,732

West

  69,180  67,322  152,744

Gulf Coast

  6,257  11,328  48,513  13,168  65,559  89,485

West

  75,595  42,591  34,395

East

  9,345  15,491  64,756

Canada

  3,118  14,155  224
  
  
  
         

Total

  91,197  69,410  147,664  97,873  202,487  286,185
  
  
  
         

- 12 -


Well Summary

The following table presents our ownership at December 31, 2004,2005, in productive natural gas and oil wells in the Gulf CoastEast region (consisting primarily of various fields located in LouisianaWest Virginia, Virginia and Texas)Ohio), in the West region (consisting of various fields located in Oklahoma, Kansas, Colorado and Wyoming), in the EastGulf Coast region (consisting primarily of various fields located in West Virginia, VirginiaLouisiana and Ohio)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.

 

  Natural Gas

  Oil

  Total(1)

  Natural Gas  Oil  Total(1)
  Gross

  Net

  Gross

  Net

  Gross

  Net

  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

  584  353.7  167  141.7  751  495.4  622  375.0  166  140.7  788  515.7

West

  1,127  663.1  56  32.4  1,183  695.5

East

  2,559  2,381.2  25  12.1  2,584  2,393.3

Canada

  14  1.5  0  0  14  1.5  20  3.9  0  0.0  20  3.9
  
  
  
  
  
  
                  

Total

  4,284  3,399.5  248  186.2  4,532  3,585.7  4,563  3,607.6  246  186.4  4,809  3,794.0
  
  
  
  
  
  
                  

(1)(1)Total does not include service wells of 74 (64.573 (65.3 net).

Drilling Activity

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

 

   Year Ended December 31, 2004

   Gulf Coast  West  East  Canada  Total
   Gross

  Net

  Gross

  Net

  Gross

  Net

  Gross

  Net

  Gross

  Net

Development Wells

                              

Successful

  16  9.5  45  30.8  164  161.0  2  0.6  227  201.9

Dry

  4  2.9  1  0.6  1  1.0  0  0.0  6  4.5

Extension Wells

                              

Successful

  0  0.0  0  0.0  1  1.0  1  0.5  2  1.5

Dry

  0  0.0  1  0.5  0  0.0  0  0.0  1  0.5

Exploratory Wells

                              

Successful

  7  2.9  3  1.3  4  4.0  1  0.4  15  8.6

Dry

  4  2.3  0  0.0  1  0.5  0  0.0  5  2.8
   
  
  
  
  
  
  
  
  
  

Total

  31  17.6  50  33.2  171  167.5  4  1.5  256  219.8
   
  
  
  
  
  
  
  
  
  

Wells Acquired(1)

  0  0.0  2  1.9  25  25.0  0  0.0  27  26.9

Wells in Progress at End of Year

  2  1.0  12  6.4  0  0.0  2  0.6  16  8.0

(1)Includes the acquisition of net interest in wells in which we already held an ownership interest.

   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

- 13 -


Competition

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 believe that our competitive position in the East region is enhanced by the lack of significant competition from major oil and gas companies. We also actively compete against other companies with substantially larger financial and other resources, particularly in the West and Gulf Coast regions and Canada.

OTHER BUSINESS MATTERS

Major Customer

In each of 2005, 2004 and 2003, approximately 11% of our total sales were made to one customer. In 2003 and 2002, approximately 11% and 14%, respectively, of our total sales were made to one customer. In 2002, this customer operated certain properties in which we have interests in the Gulf Coast and purchased all of the production from these wells. This customer would resell the natural gas and oil to third parties with whom we would deal directly if the customer either ceased to exist or stopped buying our portion of the production.

Seasonality

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

Regulation of Oil and Natural Gas Exploration and Production

Exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field, and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. We do not believe, however, we are affected differently by these regulations than others in the industry.

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Natural Gas Marketing, Gathering and Transportation

Federal legislation and regulatory controls have historically affected the price of the natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938 (NGA), the FERC regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC has granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of gas for resale without further FERC approvals. As a result, all of our produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the provisions of the Energy Policy Act of 2005, the NGA has been amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas, 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.

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Federal Regulation of Petroleum

Our sales of oil and natural gas liquids are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations have generally been approved on judicial review. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The first such review was completedsecond of these required reviews commenced in December 2000,July 2005, where the FERC concluded thatproposed to continue use of the rate index reasonably reflected actual pipeline costs. Upon judicial review, the pipeline transportation rates established under the index were increased slightly. The next review is scheduled in July 2005. 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 relatively new federal regulations, or of the periodic reviewreviews by the FERC of the pipeline index, or the ongoing reviewfinal outcome of the application of the FERC’s new policy on income tax allowance.

allowances.

Environmental Regulations

General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Government regulations can increase the cost of planning, designing, installing and operating oil and gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. 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.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, permitspermit 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.

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

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

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

Oil Pollution Act. The 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.

Employees

As of December 31, 2004,2005, Cabot Oil & Gas had 346354 active employees. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. The Company and its employees are not represented by a collective bargaining agreement.

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Website Access to Company Reports

We make available free of charge through our website,www.cabotog.com, our annual 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.

Corporate Governance Matters

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.

ITEM 1A. RISK FACTORS

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

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

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

the level of consumer product demand;

weather conditions;

political conditions in natural gas and oil producing regions, including the Middle East;

the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

the price of foreign imports;

actions of governmental authorities;

pipeline capacity constraints;

inventory storage levels;

domestic and foreign governmental regulations;

the price, availability and acceptance of alternative fuels; and

overall economic conditions.

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. If natural gas prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.

Drilling natural gas and oil wells is a high-risk activity.

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

unexpected drilling conditions, pressure or irregularities in formations;

equipment failures or accidents;

adverse weather conditions;

compliance with governmental requirements; and

shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.

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

the results of exploration efforts and the acquisition, review and analysis of the seismic data;

the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;

the approval of the prospects by other participants after additional data has been compiled;

economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews;

our financial resources and results; and

the availability of leases and permits on reasonable terms for the prospects.

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:

the quality and quantity of available data;

the interpretation of that data;

the accuracy of various mandated economic assumptions; and

the judgment of the persons preparing the estimate.

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

estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and crude oil prices. Please see Items 7that are ultimately recovered, and 7A. such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.

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

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

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

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.

Our business involves a variety of operating risks, including including:

blowouts, cratering explosions and fires, explosions;

mechanical problems, problems;

uncontrolled flows of oil, natural gas, oil or well fluids, fluids;

fires;

formations with abnormal pressures, pressures;

pollution and other environmental risks,risks; and

natural disasters. We

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

Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. Any of these events could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. 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 any of these eventsan event not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The costs

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

Other companies operate some of these insurance policies are somewhat dependent on our historical claims experience and also the areasproperties in which we choosehave an interest. We have limited ability to operate. Duringinfluence or control the past few years,operation or future development of these non-operated properties or the amount of capital expenditures that we have invested a higher percentageare 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 dollarsor 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 the Gulf Coast, where insurance rates are significantly higher thanworld financial markets and could lead to increased volatility in other regions such as the East. At December 31, 2004, we owned or operated approximately 3,300 miles ofprices for natural gas gathering and transmission pipeline systems throughoutoil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. As partThe U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our normal maintenance program,operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.

Our ability to sell our natural gas and oil production could be materially harmed if we have identified certain segments of our pipelines that we believe may require repair, replacement or additional maintenance,fail to obtain adequate services such as transportation and we schedule this maintenance as appropriate.

processing.

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

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

Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours, 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:

a counterparty is unable to satisfy its obligations;

production is less than expected; or

there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

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

The loss of key personnel could adversely affect our ability to operate.

Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to extensive federal, state and local laws and regulations, including tax laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.

Provisions of Delaware law and our bylaws and charter could discourage change in control transactions and prevent stockholders from receiving a premium on their investment.

Our bylaws provide for a classified board of directors with staggered terms, and our charter authorizes our board of directors to set the terms of preferred stock. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Our bylaws prohibit stockholder action by written consent and limit stockholder proposals at meetings of stockholders. We also have adopted a stockholder rights plan. Because of our stockholder rights plan and these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent board of directors.

The personal liability of our directors for monetary damages for breach of their fiduciary duty of care is limited by the Delaware General Corporation Law and by our certificate of incorporation.

The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors’ duty of care to equitable remedies such as injunction or rescission. Our certificate of incorporation limits the liability of our directors to the fullest extent permitted by Delaware law. Specifically, our directors will not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liability

for any breach of their duty of loyalty to the company or our stockholders;

for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and

for any transaction from which the director derived an improper personal benefit.

This limitation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our stockholders.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

See Item 1. Business.

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ITEM 3. LEGAL PROCEEDINGS

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

Wyoming Royalty Litigation

In June 2000,January 2002, we were sued by two13 overriding royalty owners in Wyoming statefederal district court, for unspecified damages.as reported in previous filings. The plaintiffs requested class certification and alleged that we had improperly deducted costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claimed that we had failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. At a mediation held in April 2003, the plaintiffs in this case claimed total damages of $9.5 million plus attorney fees. We settled the case for a total of $2.25 million and the State District Court Judge entered his order approving the settlement in the fourth quarter of 2003. The class included all private fee royalty and overriding royalty owners of the Company in the State of Wyoming except those in the suit discussed below and one owner who opted out of the settlement. It also includes provisions for the method of valuation of gas for royalty payment purposes going forward and for reporting of royalty payments, which should prevent further litigation of these issues by the class members.

In January 2002, 13 overriding royalty owners sued us in Wyoming federal district court. The plaintiffs in the federal case have made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court case but have not askedand claims concerning penalties for class certification.

The federal district court judge certified two questionsimproper reporting. As a result of state law for decisionseveral decisions by the Wyoming State Supreme Court which recently answered both questions.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 Wyoming Supreme Court ruled that certain deductions taken by us fromsettlement included provisions for reporting and payment going forward. In the plaintiffs were not proper and thatthird quarter of 2005, management reversed the statutes of limitations advanced by us are discovery statutes and accordingly do not begin to run until the plaintiffs knew, orreserve we had reason to know, of the violation. We believe we have properly reported to the plaintiffs and, that if werecorded regarding this case, which did not the plaintiffs knew or should have known the reporting was improper and the nature of the deductions, thus triggering the statutes of limitations. We still intend to raise defenses to the alleged failure to report claims. There is also a dispute as to how the interest should be calculated.

The federal judge refused to certify a question relating to the issue of the proper calculation of damages for failure to provide certain information required by statutematerial impact on overriding royalty owner check stubs that had been decided adversely to our position in a state district court letter decision in a separate case. After the federal judge’s refusal to certify this issue, the plaintiffs reduced the damages they were claiming. Based upon recent communication from the plaintiffs, they are now claiming $26.2 million in total damages which consists of $20.3 million for alleged violations of the check stub reporting statute and $5.9 million for all other damages.

In the opinion of our outside counsel, Brown, Drew & Massey, LLP, the likelihood of the plaintiffs recovering $20.3 million for the check stub reporting statute is remote. However, a reserve that management believes is adequate to provide for the check stub reporting statute and all other damages has been established based on management’s estimate at this time of the probable outcome of this case.

consolidated financial statements.

West Virginia Royalty Litigation

In December 2001, we were sued by two royalty owners in West Virginia state court for an unspecified amount of damages. The plaintiffs have requested class certification under the West Virginia Rules of Civil Procedure and allege that we failed to pay royalty based upon the wholesale market value of the gas, produced, that itwe had taken improper deductions from the royalty and failed to properly inform royalty owners of the plaintiffs and other similarly situated persons of deductions taken from the royalty.deductions. The plaintiffs have also claimed that they are entitled to a 1/8th 1/8th royalty share of the gas sales contract settlement that we reached with Columbia Gas Transmission Corporation in the 1995 Columbia Gas Transmission Corporation bankruptcy proceeding.proceedings.

- 19 -


Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. A hearingThe Court entered an order on June 1, 2005 granting the plaintiffs’ motion for class certification was heldcertification. 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 October 20, 2003, and proposed findingsafter December 17, 1991. The Court has postponed the trial date from April 17, 2006, in light of fact and conclusionsa case pending before the West Virginia Supreme Court of Appeals which may decide issues of law were submittedthat may apply to the court on December 5, 2003. A status conference was held with the court and the court advised it intendsissue of deductibility of post-production expenses. We intend to issue a ruling onchallenge the class certification motion. The court was expected to ruleorder by December 2004, and we are still awaitingfiling a decision. Discovery is proceeding onPetition for Writ of Prohibition with the claims pending the ruling on the class certification motion. Discovery is to be completed by April 1, 2005, and the trial is currently scheduled for August 15, 2005. If a class is certified it is expected this trial date will be continued to a later date.West Virginia Supreme Court of Appeals.

The investigation into this claim continues and it is in the discovery phase. We are vigorously defending the case. We have established a reserve that management believes is adequate based on itstheir estimate at this time of the probable outcome of this case.

Texas Title Litigation

On January 6, 2003, we were served with Plaintiffs’ Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs filed their FirstSecond Supplemental Original Petition on March 17,November 12, 2004 and their SecondThird Supplemental Original Petition on November 12, 2004. The significant change in the second Supplemental Petition is that plaintiffs appear to limit their claim to the mineral estate, rather than making claims to both the surfaceFebruary 22, 2005 (which added Wynn-Crosby 1996, Ltd. and mineral estate. The plaintiffsDominion 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, weour subsidiary, acquired certain leases and wells from Wynn-Crosby 1996, Ltd. in 1997 and 1998 and we subsequently acquired a 320 acre lease from Hector and Gloria Lopez in 2001. 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. The original trial date of May 19, 2003 was cancelledPlaintiffs 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. Weclaim 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 its predecessor, Cody Energy, LLC acquired title and since we acquired its lease is approximately $14.9 million. The$15.7 million, and that the carrying value of this property is approximately $34$33.6 million. Co-defendants Shell Oil Company and Shell Western E&P filed a motion for summary judgment seeking dismissal of plaintiffs’ causes of action on multiple grounds. The original plaintiffs’ attorneys asked permission from the Court to withdraw from the representation. The Court granted that request, and new attorneys for some, but not all of the plaintiffs have recently entered the case. The motion for summary judgment was reset and a hearing was held in December of 2003. We joined in the motion. After a second hearing, the Court denied the motion for summary judgment. The defendants have moved to add parties whose title interests are being challenged by the plaintiffs, and who are therefore necessary to the case, or in the alternative, abate the proceeding until the plaintiffs join all parties whose interests may be affected by plaintiffs’ claims.

Although the investigation into this claim is in its early stages,continues, we intend to vigorously defend the case. Should we receive an adverse ruling in this case, an impairment review would be assessed to ensuredetermine 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, there has been nowe have not established a reserve established for this matter.

- 20 -


Raymondville Area

In April 2004, our wholly owned subsidiary, Cody Energy, LLC, filed suit in state court in Willacy County, Texas against certain of ourits co-working interest owners in the Raymondville Area, located in Kenedy and Willacy Counties. In early 2003, Cody had proposed a new prospect to certainunder the terms of these co-working interest owners located within jointly owned oil and gas leases.the Joint Operating Agreement. Some of the co-working interest owners elected not to participate and some did not.participate. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.

In December 2003, certain of the co-workingThe working interest owners who elected not to participate in the initial well notified Cody that they believed that they had the right to participate in subsequent wells.wells drilled after the initial well. Cody contends that under the terms of the agreements between the parties, the co-workingworking interest owners that elected not to participate in the initial well in the prospect wereare required to assign their interest in the proposed prospect to those who elected to participate. Alternatively, Cody contends that such owners lost their right to participate in subsequent wells within a 1,200 foot radius of the initial well.

The defendants have filed a counter claim against usthe Company, and one of the defendants has filed a lien against Cody’s interest in the leases in the Raymondville Area. area.

Cody contends that this lien is improper and has sought damages for its filing. Cody is vigorously prosecuting this case which is in its early stage of discovery. No trial date has been set by the court.

Certainsigned 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 Partial Summary Judgment contending that they didReconsideration and Opposition to Proposed Order. The Court has not have adequate notice of the prospect proposal. Cody is contesting this Motion. In addition, in late December 2004, Cody filedyet made a Motion for Final Summary Judgment asking the court to find that, under the terms of the agreements, Cody and the participating working interest owners are entitled to an assignment of the interests of the co-working interest owners who elected not to participate in the prospect. No hearing date has been set by the court.

Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.

decision on these two motions.

Commitment and Contingency Reserves

We have established reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that we could incur approximately $11.1$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.position or cash flow. Operating results, and cash flow, however, could be significantly impacted in the reporting periods in which such matters are resolved.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders during the fourth quarter of 2004.

- 21 -2005.


EXECUTIVE OFFICERS OF THE REGISTRANT

The following table shows certain information about our executive officers as of February 18, 2005,17, 2006, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.

 

Name


  Age

  

Position


  Officer Since

Dan O. Dinges

  51  Chairman, President and Chief Executive Officer  2001

Michael B. Walen

  56  Senior Vice President, Exploration and Production  1998

Scott C. Schroeder

  42  Vice President and Chief Financial Officer  1997

J. Scott Arnold

  51  Vice President, Land and Associate General Counsel  1998

R. Scott Butler

  50  Vice President, Regional Manager, West Region  2001

Robert G. Drake

  57  Vice President, Information Services and Operational Accounting  1998

Abraham D. Garza

  58  Vice President, Human Resources  1998

Jeffrey W. Hutton

  49  Vice President, Marketing  1995

Thomas S. Liberatore

  48  Vice President, Regional Manager, East Region  2003

Lisa A. Machesney

  49  Vice President, Managing Counsel and Corporate Secretary  1995

Henry C. Smyth

  58  Vice President, Controller and Treasurer  1998

Name

  Age  Position  Officer Since

Dan O. Dinges

  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

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 BBAB.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 explorationVice President, Exploration and productionProduction 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.

- 22 -


PART II

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

The Common Stockcommon stock is listed and principally traded on the New York Stock Exchange under the ticker symbol “COG”.“COG.” The following table presents the high and low closing sales prices per share of the Common Stockcommon stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the Common Stockcommon stock are also shown. 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.

 

   High

  Low

  Cash
Dividends


2004

            

First Quarter

  $32.90  $28.76  $0.04

Second Quarter

   42.30   30.13   0.04

Third Quarter

   45.08   38.80   0.04

Fourth Quarter

   48.38   40.90   0.04

2003

            

First Quarter

  $29.46  $24.40  $0.04

Second Quarter

   27.96   24.45   0.04

Third Quarter

   30.46   26.65   0.04

Fourth Quarter

   30.26   25.35   0.04

   High  Low  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

As of January 31, 2005,2006, there were 693632 registered holders of the Common Stock.common stock. Shareholders include individuals, brokers, nominees, custodians, trustees, and institutions such as banks, insurance companies and pension funds. Many of these hold large blocks of stock on behalf of other individuals or firms.

On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split on the Company’s Common Stock in the form of a stock distribution. The stock dividend will be distributed on March 31, 2005 to shareholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company will pay cash based on the closing price of the Common stock on the record date.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

 

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    
         

Issuer Purchases of Equity Securities (1)

Period


  Total
Number of
Shares
Purchased


  Average
Price Paid
per Share


  Total Number
of Shares
Purchased as
Part of
Publicly
Announced
Plans or
Programs


  

Approximate
Number

of Shares that
May Yet Be
Purchased
Under the
Plans or
Programs


October 2004

  —     —    —    1,453,300

November 2004

  136,000  $42.64  136,000  1,317,300

December 2004

  25,000  $43.96  25,000  1,292,300
   
          

Total

  161,000  $42.84      
   
          

(1) On August 13, 1998, the Companywe announced that itsour Board of Directors authorized the repurchase of two million shares of the Company’sour 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 securities of the Company.

- 23 -our securities.


ITEM 6. SELECTED HISTORICAL FINANCIAL DATA

The following table summarizes our selected consolidated financial data for Cabot Oil & Gas for the periods indicated. This information should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the Consolidated Financial Statements and related Notes.

 

  Year Ended December 31,

  Year Ended December 31,

(In thousands, except per share amounts)


  2004

  2003

  2002

  2001

  2000

  2005  2004  2003  2002  2001

Statement of Operations Data

                         

Operating Revenues

  $530,408  $509,391  $353,756  $447,042  $368,651  $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   9,143   —     3,458   93,796   2,720   6,852

Income from Operations

   160,653   66,587   49,088   95,366   64,817   258,731   160,653   66,587   49,088   95,366

Net Income

   88,378   21,132   16,103   47,084   29,221   148,445   88,378   21,132   16,103   47,084

Basic Earnings per Share(3)

  $2.72  $0.66  $0.51  $1.56  $1.07  $3.04  $1.81  $0.44  $0.34  $1.04

Dividends per Common Share(2)

  $0.16  $0.16  $0.16  $0.16  $0.16  $0.147  $0.107  $0.107  $0.107  $0.107

Balance Sheet Data

                         

Properties and Equipment, Net

  $994,081  $895,955  $971,754  $981,338  $623,174  $1,238,055  $994,081  $895,955  $971,754  $981,338

Total Assets

   1,210,956   1,055,056   1,100,947   1,092,810   776,353   1,495,370   1,210,956   1,055,056   1,100,947   1,092,810

Current Maturities of Long-Term Debt

   20,000   —     —     —     16,000

Current Portion of Long-Term Debt

   20,000   20,000   —     —     —  

Long-Term Debt

   250,000   270,000   365,000   393,000   253,000   320,000   250,000   270,000   365,000   393,000

Stockholders’ Equity

   455,662   365,197   350,657   346,552   242,505   600,211   455,662   365,197   350,657   346,552

(1)For discussion of impairment of oil and gas properties, refer to Note 2.2 of the Notes to the Consolidated Financial Statements.

(2)All Earnings per Share and Dividends per Common Share figures have been retroactively adjusted for the 3-for-2 split of our common stock effective March 31, 2005.
(3)Year 2003 includes a cumulative effect of a change in accounting principle loss of $0.14 per share related to the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations.”

- 24 -


ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying notesNotes included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. Please read Forward-Looking Information on page 36.

“Forward-Looking Information” for further details.

We operate in one segment, natural gas and oil exploration and development.

exploitation, exclusively within the United States and Canada.

OVERVIEW

Cabot Oil & Gas isand its subsidiaries are a leading independent oil and gas company engaged in the exploration, development, acquisition, exploitation, production and exploitationmarketing of natural gas, and to a lesser extent, crude oil and natural gas liquids from its properties in North America. We also transport, store, gather and produce natural gas for resale. Our exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. Our program is designed to be disciplined and balanced with a focus on achieving strong financial returns.

At Cabot, there are three types of investment alternatives that constantly compete for available capital. These includecapital: drilling opportunities, acquisition opportunities and financial opportunities such as debt repayment or repurchase of common stock. 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 20032004 and 2004,2005, the futures market reported unprecedented natural gas and crude oil contract prices. Our realized natural gas and crude oil price net of the impact of derivative instruments, was $5.20$6.74 per Mcf and $31.55$44.19 per Bbl, respectively, in 2004. To ensure a certain rate2005. These realized prices include the realized impact of return for our program,derivative instruments. In an effort to manage commodity price risk, we entered into a series of crude oil and natural gas price collars and swaps. These financial instruments are an integral 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 the course of 20032004 and 2004.2005. “Index” represents the first of the month Henry Hub index price per Mmbtu. The “2003”“2004” and “2004”“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:

 

- 25 -


(in $ per Mcf)


  Natural Gas Prices by Month - 2004

   Jan

  Feb

  Mar

  Apr

  May

  Jun

  Jul

  Aug

  Sep

  Oct

  Nov

  Dec

Index

  $6.15  $5.77  $5.15  $5.37  $5.94  $6.68  $6.14  $6.04  $5.08  $5.79  $7.63  $7.78

2004

  $5.23  $5.23  $5.17  $4.88  $4.96  $5.23  $5.39  $5.21  $4.54  $5.29  $5.63  $5.55

(in $ per Mcf)


  Natural Gas Prices by Month - 2003

   Jan

  Feb

  Mar

  Apr

  May

  Jun

  Jul

  Aug

  Sep

  Oct

  Nov

  Dec

Index

  $4.96  $5.66  $9.11  $5.14  $5.12  $5.95  $5.30  $4.69  $4.93  $4.44  $4.45  $4.86

2003

  $4.33  $4.62  $4.71  $4.48  $4.44  $4.57  $4.65  $4.43  $4.53  $4.33  $4.34  $4.67

(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

Prices for crude oil have followed a similar path as the commodity price continued to maintain strength in 20032004 and rose further in 2004.2005. The tables below contain the NYMEX monthly average crude oil price (Index) and our realized per barrel (Bbl) crude oil prices by month for 20032004 and 2004.2005. The “2003”“2004” and “2004”“2005” price is the crude oil price per Bbl realized by us and includes the realized impact of our crude oil derivative arrangements:

 

(in $ per Bbl)


  Crude Oil Prices by Month - 2004

   Jan

  Feb

  Mar

  Apr

  May

  Jun

  Jul

  Aug

  Sep

  Oct

  Nov

  Dec

Index

  $34.23  $34.50  $36.72  $36.62  $40.28  $38.05  $40.81  $44.88  $45.94  $53.09  $48.48  $43.26

2004

  $30.62  $30.66  $31.62  $30.97  $30.80  $31.51  $31.43  $33.00  $31.61  $32.87  $33.15  $30.46

(in $ per Bbl)


  Crude Oil Prices by Month - 2003

   Jan

  Feb

  Mar

  Apr

  May

  Jun

  Jul

  Aug

  Sep

  Oct

  Nov

  Dec

Index

  $32.70  $35.73  $33.16  $28.14  $28.07  $30.52  $30.70  $31.60  $28.31  $30.35  $31.06  $32.14

2003

  $29.81  $31.47  $31.35  $29.65  $29.18  $28.95  $30.11  $28.82  $26.46  $27.17  $29.43  $32.93
(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

We reported earnings of $2.72$3.04 per share, or $148.4 million, for 2005. This is up from the $1.81 per share, or $88.4 million, for 2004. This is up from the $0.66 per share, or $21.1 million, reported in 2003.2004. The decline in impairments of oil and gas properties was the driving factor in this improvement. In 2003, there was an after-tax impairment of $54.4 million related to our Kurten field (seeLimited Partnership for discussion of the impairment). In addition, the stronger price environment contributedwas a primary contributor to the earnings increase.increase due to the increase in natural gas and oil revenues. Prices, including the realized impact of the hedge arrangements,derivative instruments, rose 15%30% for natural gas and 7%40% for oil.

We drilled 256316 gross wells with a success rate of 95% in 20042005 compared to 173256 gross wells with an 89%a 95% success rate in 2003.2004. Total capital and exploration expenditures increased $71.3by $166.1 million to $425.6 million, of which $73.1 million was for property acquisitions, in 2005 compared to $259.5 million in 2004 compared to $188.2 million for 2003.2004. We believe our operating cash flow in 20052006 will be sufficient to fund our capital and exploration budgeted spending of approximately $280$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 20052006 strategy will remain consistent with 2004 focusing2005. We will remain focused on a disciplined approach to investment that balances our drilling effortstrategies of balancing our capital investments between exploration opportunitieshigher risk projects with the potential for higher returns and the development program,lower risk projects with more stable returns, along with acquisition opportunitiesbalancing longer life investments with impact exploration opportunities. In the current year we have allocated our planned program for capital and a continued financial focus including stock buybackexploration expenditures among our various operating regions. We believe these strategies are appropriate in the current industry environment and debt repayment.

will continue to add shareholder value over the long term.

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read Forward-Looking Information on page 36.

- 26 -“Forward-Looking Information” for further details.


FINANCIAL CONDITION

Capital Resources and Liquidity

Our primary source of cash in 20042005 was from funds generated from operations. Proceedsoperations, as well as borrowings on our revolving credit facility and, to a lesser extent, proceeds from the saleexercise of common stock options under our stock option plans during 2004 roughly offset our repurchase of 405,100 treasury shares of Company stock at a weighted average purchase price of $38.58. The Company generatesplans. 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“Results of OperationsOperations” 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.

 

   Year-Ended December 31,

 
   2004

  2003

  2002

 

Cash Flows Provided by Operating Activities

  $273,022  $241,638  $164,182 

Cash Flows Used by Investing Activities

   (255,357)  (151,856)  (138,668)

Cash Flows Used by Financing Activities

   (8,363)  (90,660)  (27,364)
   


 


 


Net Increase (Decrease) in Cash and Cash Equivalents

  $9,302  $(878) $(1,850)
   


 


 


   Year-Ended December 31, 
(In thousands)  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)
             

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 driverscomponents 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, slightly, with a 5 percent5% reduction of equivalent production in 2004 compared to 2003. While we believe 2005 commodity production may exceed 2004 levels, we are unable to predict future commodity prices, and as a result cannot provide any assurance about future levelsSee “Results of net cash provided by operating activities.

Net cash provided by operating activities in 2003 increased $77.5 million over 2002. This increase is primarily due to higher commodity prices. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Average natural gas prices increased 49% over 2002, while crude oil prices increased 24% over the same period. Production volumes declined slightly with a 2% reduction of equivalent production in 2003 compared to 2002. See page 25Operations” for a discussion on commodity prices and Results of Operations for a review of the impact of prices and volumes on sales revenue.

- 27 -


Investing Activities. The primary driveruses of cash used by investing activities isare 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 budgetcapital expenditures may be periodically adjusted during any given year. Cash flows used in investing activities increased for the years ended December 31, 20042005 and 20032004 in the amounts of $156.8 million and $103.5 million, and $13.2 million.respectively. The increase from 20032004 to 20042005 is primarily due to an increase in drilling activity as a resultin 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 MountainMountains area of our West region. Our initial drilling activity in Canada also contributed to the increase. Cash flows used in investing activities increased from 2002 to 2003 due to an increase in capital spending and exploration expense in response to higher commodity prices and exploitation of acquired properties. This increase was partially offset by proceeds received from the sale of certain non-strategic assets.

Financing Activities. Cash flows usedprovided by financing activities were $8.4$48.2 million for the year ended December 31, 2004.2005, 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 waswere $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 cash flows used by financing activities in 2002 is primarily due to a net repayment on our revolving credit facility of $25.0 million.

Theprovides for an available credit line under our revolving credit facility, which wasof $250 million, at year end, butwhich can be expanded up to $350 million, either with the existing banks or new banks. The available credit line is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the bank’sbanks’ petroleum engineer) and other assets. At December 31, 2004, we had no outstanding balance on the credit facility. The revolving term of the credit facility ends in December 2009. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Management believes that we have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including potential acquisitions.

OurIn 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 securitiesour securities. The maximum number of shares that may yet be purchased under the Company.plan as of December 31, 2005 was 1,486,150. See “Issuer Purchases of Equity Securities” in Item 5 “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer RepurchasesPurchases of Equity Securities” for additional information.

- 28 -


Capitalization

Information about our capitalization is as follows:

 

  December 31,

   December 31, 
  2004

 2003

 
  (In millions) 
(In millions)  2005 2004 

Debt(1)

  $270.0  $270.0   $340.0  $270.0 

Stockholders’ Equity (2) (3)

   455.7   365.2 

Stockholders’ Equity

   600.2   455.7 
  


 


       

Total Capitalization

  $725.7  $635.2   $940.2  $725.7 
       
  


 


Debt to Capitalization(3)

   37%  43%   36%  37%

Cash and Cash Equivalents

  $10.0  $0.7   $10.6  $10.0 

(1)Includes $20.0 million of current portion of long termlong-term debt inat both December 31, 2005 and 2004.
(2)Includes common stock, net$90 million of treasury stock.
(3)Includes the impact of the Accumulated Other Comprehensive Lossborrowings under our revolving credit facility at December 31, 2004 and 2003 of $20.4 million and $23.1 million, respectively.2005. There were no borrowings under our revolving credit facility at December 31, 2004.

For the year ended December 31, 2004,2005, we paid dividends of $5.2$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.

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital and exploration activities, excluding majorsignificant oil and gas property acquisitions, with cash generated from operations and, when necessary, our revolving credit facility. We budget these capital expenditures based on our projected cash flows for the year.

The following table presents major components of our capital and exploration expenditures for the three years ended December 31, 2004.2005.

 

(In millions)


  2004

  2003

  2002

Capital Expenditures

            

Drilling and Facilities

  $174.0  $102.0  $67.0

Leasehold Acquisitions

   18.3   14.1   4.8

Pipeline and Gathering

   13.5   10.6   4.1

Other

   1.6   1.8   1.4
   

  

  

    207.4   128.5   77.3
   

  

  

Proved Property Acquisitions

   4.0   1.5   8.8

Exploration Expense

   48.1   58.2   40.2
   

  

  

Total

  $259.5  $188.2  $126.3
   

  

  

(In millions)  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
            

We plan to drill about 300391 gross wells in 20052006 compared with 256316 gross wells drilled in 2004.2005. This 20052006 drilling program includes approximately $280.0$396 million in total capital and exploration expenditures, updown from $259.5$425.6 million in 2004.2005. 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 20052006 management expects an increase in our depreciation, depletion and amortization rate due to production declinesnegative reserve revisions and higher capital costs. This change may result in an increase of depreciation, depletion and amortization of 5%10% to 10%15% greater than 20042005 levels. This increase will not have an impact on our cash flows.

- 29 -


Contractual Obligations

Our known material contractual obligations include long-term debt, interest on long-term debt, firm gas transportation agreements, drilling rig commitments and operating leases. We have no off-balance sheet debt or other similar unrecorded obligations, and we have not guaranteed the debt of any other party.

A summary of our known contractual obligations as of December 31, 20042005 are set forth in the following table:

 

     Payments Due by Year
     Payments Due by Year

        2007  2009  2011 &

(In thousands)


  Total

  2005

  

2006

to 2007


  

2008

to 2009


  

2010 &

Beyond


  Total  2006  to 2008  to 2010  Beyond

Long-Term Debt(1)

  $270,000  $20,000  $40,000  $40,000  $170,000  $340,000  $20,000  $40,000  $110,000  $170,000

Interest on Long-Term Debt(2)

   126,405   19,545   34,776   29,024   43,060   132,960   24,632   44,950   32,673   30,705

Firm Gas Transportation Agreements

   87,888   8,117   13,321   7,565   58,885

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

   17,000   4,889   8,882   2,847   382   17,746   4,876   9,174   3,696   —  
  

  

  

  

  

               

Total Contractual Cash Obligations

  $501,293  $52,551  $96,979  $79,436  $272,327  $688,787  $87,224  $182,548  $162,806  $256,209
  

  

  

  

  

               

(1)Including current portion.
(2)Interest payments have been calculated utilizing the fixed rate of our $270 million long-term debt outstanding at December 31, 2004. At December 31, 20042005, we had no$90 million of outstanding debt on our revolving credit facility. See Note 54 of the Notes to the Consolidated Financial Statements for details of long-term debt.
(2)Interest payments have been calculated utilizing the fixed rates of our $250 million long-term debt outstanding at December 31, 2005. Interest payments on the $90 million of outstanding borrowings on our revolving credit facility were calculated by assuming that the December 31, 2005 outstanding balance of $90 million will be outstanding through the 2009 maturity date and by assuming a constant interest rate of 7.25% which was the December 31, 2005 interest rate. Actual results will likely differ from these estimates and assumptions.
(3)For further information on our obligations under firm gas transportation agreements and drilling rig commitments, see Note 7 of the Notes to the Consolidated Financial Statements.

Amounts related to our asset retirement obligations are not included in the above table given the uncertainty regarding the actual timing of such expenditures. The total amount of asset retirement obligations at December 31, 20042005 is $40.4$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.

Potential Impact of Our Critical Accounting Policies

Readers of this document and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. The most significant policies are discussed below.

Oil and Gas Reserves

The process of estimating quantities of proved reserves is inherently uncertain, 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:

 

the quality and quantity of available data;

 

the interpretation of that data;

 

the accuracy of various mandated economic assumptions; and

 

the judgment of the persons preparing the estimate.

In 2004, 2003 and 2002,Since 1990, 100% of our reserves were subject to an external reviewhave been reviewed by Miller & Lents, Ltd., an independent oil and gas reservoir engineering consulting firm, who in their opinion determined the estimates presented to be reasonable in the aggregate. Additionally, in 2004, 2003 and 2002, we didWe have not havebeen required to record a significant reserve revision recorded.in the past three years. For more information regarding reserve estimation, including historical reserve revisions, refer to the Supplemental“Supplemental Oil and Gas Disclosure beginning on page 85.Information.”

- 30 -


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 $0.04$0.05 to $0.05$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 $0.02$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 SFASStatement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.. Due to the inherent imprecision of the reserve estimation process, risks associated with the operations of proved producing properties, and market sensitive commodity prices utilized in our impairment analysis, management cannot determine if an impairment is reasonably likely to occur in the future.

Carrying Value of Oil and Gas Properties

We evaluate the impairment of our oil and gas properties on a lease-by-lease basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted cash flows, based on our estimate of future crude oil and natural gas prices, operating costs and anticipated production from proved reserves are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. In 2002 there were no unusual or unexpected occurrences that caused significant revisions in estimated cash flows which were utilized in our impairment test. In 2003, we significantly revised the estimated cash flow utilized in our impairment review of the Kurten field due to a loss of a reversionary interest in the field. In December 2003, our remaining interest in the field was sold. For additional discussion on the Kurten field impairment see Note 2 of the Notes to the consolidated financial statements.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,above; however, a portion of the costs associated with such properties is subject to amortization based on past experience and average property lives. Average property lives are determined on a regional basis and based on the estimated life of unproved property leasehold rights. Historically, the average property lives in each of the regions have not significantly changed. However, if the average property life increases, the amount of the amortization charge in a given reporting period will decrease. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $2.3$2.7 million or decrease by approximately $1.9$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, sixseven and sixseven years, respectively. Average property lives in Canada are estimated to be fivesix 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.

- 31 -


Accounting for Derivative Instruments and Hedging Activities

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

Operations.

Long-Term Employee Benefit Costs

Our costs of long-term employee benefits, particularly pension and postretirement benefits, are incurred over long periods of time, and involve many uncertainties over those periods. The net periodic benefit cost attributable to current periods is based on several assumptions about such future uncertainties, and is sensitive to changes in those assumptions. It is management’s responsibility, often with the assistance of independent experts, to select assumptions that in its judgment represent best estimates of those uncertainties. It also is management’s responsibility to review those assumptions periodically to reflect changes in economic or other factors that affect those assumptions.

The current benefit service costs, as well as the existing liabilities, for pensions and other postretirement benefits are measured on a discounted present value basis. The discount rate is a current rate, related to the rate at which the liabilities could be settled. Our assumed discount rate is based on average rates of return published for a theoretical portfolio of high-quality fixed income securities. In order to select the discount rate, we use benchmarks such as the

Moody’s Aa Corporate Rate, which was 5.48% 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, 2004,2005, the assumed rate of increase was 10.0%9.0%. The net periodic cost of pension benefits included in expense also is affected by the expected long-term rate of return on plan assets assumption. The expected return on plan assets rate is normally changed less frequently than the assumed discount rate, and reflects long-term expectations, rather than current fluctuations in market conditions. The actual rate of return on plan assets may differ from the expected rate due to the volatility normally experienced in capital markets. Management’s goal is to manage the investments over the long term to achieve optimal returns with an acceptable level of risk and volatility.

We have established objectives regarding plan assets in the pension plan. 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.

Stock BasedStock-Based Compensation

Prior to the issuance of SFAS 123RNo. 123(R) “Share Based Payment”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. Currently,As of December 31, 2005, we account for stock-based compensation in accordance with the Intrinsic Value method. SFAS 123RNo. 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 thirdfirst quarter of 2005,2006, we will be required to expense all stock basedstock-based compensation. Further discussion of SFAS 123RNo. 123(R) and stock compensation is included in “Recently Issued Accounting Pronouncements”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 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 we believed to be in the best interest of our shareholders and employees, was made solely to reduce compensation expense and administrative burden associated with our adoption of SFAS No. 123(R).

The accelerated vesting of the options did not have an impact on page 35.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.

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OTHER ISSUES AND CONTINGENCIES

Corporate Income Tax. We generated tax credits for the production of certain qualified fuels, including natural gas produced from tight sands formations and Devonian Shale. The credit for natural gas from a tight sand formation (tight gas sands) amounted to $0.52 per Mmbtu for natural gas sold prior to 2003 from qualified wells drilled in 1991 and 1992. A number of wells drilled in the East region and Rocky Mountains during 1991 and 1992 qualified for the tight gas sands tax credit. The credit for natural gas produced from Devonian Shale was $1.09 per Mmbtu in 2002. In 1995 and 1996, we completed three transactions to monetize the value of these tax credits, resulting in revenues of $2.0 million in 2002. The tax credit wells were repurchased in December 2002 and no tax credits were generated in 2003 or 2004 as the credits expired in 2002. See Note 13 of the Notes to the Consolidated Financial Statements for further discussion.

We have benefited in the past and may benefit in the future from the alternative minimum tax (AMT) relief granted under the Comprehensive National Energy Policy Act of 1992 (the Act). The Act repealed provisions of the AMT requiring a taxpayer’s alternative minimum taxable income to be increased on account of certain intangible drilling costs (IDC) and percentage depletion deductions.deductions for corporations other than integrated oil companies. The repeal of these provisions generally applies to taxable years beginning after 1992. The repeal of the excess IDC preference can 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 ProductionExploration 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 Agreementrevolving credit agreement and the Notesour senior notes specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. At December 31, 2004,2005, we are in compliance in all material respects with all restrictive covenants on both the Revolving Credit Agreementrevolving credit agreement and the Notes.notes. In the unforeseen event that we fail to comply with these covenants, the 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 FASSFAS 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 after-tax impairment charge in the first quarter of 2003 of $54.4 million.$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.

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Operating Risks and Insurance Coverage.Our business involves a variety of operating risks. See “Risk Factors—We face a variety of hazards and risks including:

blowouts, cratering and explosions;

mechanical problems;

uncontrolled flows of oil, natural gas or well fluids;

fires;

formations with abnormal pressures;

pollution and other environmental risks; and

natural disasters.

The operation of our natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites,that could increase these risks. Any of these events could resultcause substantial financial losses” in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us.Item 1A. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The costs of these insurance policies are somewhat dependent on our historical claims experience and also the areas in which we choose to operate. During the past few years, we have invested a significant portion of our drilling dollars in the Gulf Coast, where insurance rates are significantly higher than in other regions such as the East.

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

The majority of our production is sold at market responsive prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. However, management may mitigate this price risk with the use of derivative financial instruments. Most recently, we have used financial instruments such as price 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.

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Recently Issued Accounting Pronouncements

In May 2004,March 2005, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP)Interpretation (FIN) No. FAS 106-2,47, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.for Conditional Asset Retirement Obligations.” This FSP provides guidanceInterpretation 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 accounting for the effectscontrol of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act)Company. FIN No. 47 states that a company must record a liability when incurred for employers that sponsor postretirement health care plans that provide prescription drug benefits. This FSP also requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Act (the subsidy). This FSP supersedes FSP 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” and is effective for the first interim period beginning after June 15, 2004. Our current accumulated projected benefit obligation and net periodic postretirement benefit cost does not reflect any amount associated with the subsidy. Furthermore, in 2004, we amended our postretirement benefit plan to exclude prescription drug benefits for participants age 65 and older effective January 1, 2006. The adoption of this FSP is not expected to impact our operating results, financial position or cash flows.

In November 2004, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 151, “Inventory Costs—an amendment of ARB No. 43, Chapter 4” in an effort to unite the United States accounting standards for inventories with International Accounting Standards leading to consistent application of certain accounting requirements. FAS 151 addresses accounting for abnormal amounts of freight, handling costs, idle facility expense and spoilage (wasted material) and requires that these costs be recognized as current period expenses. Previously, these costs had to be categorized as “so abnormal as to require treatment as current period charges.” In addition, allocation of fixed production overheads to the costs of conversion must be based on the normal capacity of the production facilities. FAS 151 will be effective for fiscal periods beginning after June 15, 2005. The adoption of this statement is not expected to impact our operating results, financial position or cash flows.

In December 2004, the FASB issued SFAS 153 “Exchanges of Nonmonetary Assets – an amendment of APB Opinion No. 29.” This statement requires that nonmonetary exchanges must be recorded at fair value and the appropriate gain or loss must be recognized so long as the fair value is determinable and the transaction has commercial substance. According to this statement, companies can no longer use the “similar productive assets” concept to account for nonmonetary exchanges at book value with no gain or loss being recognized. FAS 153 will be effective for fiscal periods beginning after June 15, 2005. The adoption of this statement may impact our operating results, financial position or cash flows in future periodsconditional asset retirement obligations if such a nonmonetary exchange occurs.

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” SFAS 123R revises SFAS 123, “Accounting for Stock-Based Compensation”, and focuses on accounting for share-based payments for services by employer to employee. The statement requires companies to expense the fair value of employee stock optionsthe 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 other equity-based compensation at the grant date. The statement does not require a certain typemore consistent recognition of valuation model and either a binomial or Black-Scholes model may be used. The provisions of SFAS 123R arethese liabilities. FIN No. 47 is effective for financial statements for fiscal periodsyears ending after JuneDecember 15, 2005. We are currently evaluating the methodOur financial position, results of adoptionoperations and the impact on our operating results. Our future cash flows willwere not be impacted by the adoption of this standard. See Footnote 1 “Stock Based Compensation” for further information.Interpretation, since we currently record all asset retirement obligations.

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In FebruaryOn April 4, 2005, the FASB released for public comment proposedissued FASB Staff Position (FSP) FAS 19-a19-1 “Accounting for Suspended Well Costs.” This proposed staff position would amendamends FASB Statement No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The proposed position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reservedreserves 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. Although this Staff PositionFor 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 finalpractical 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 hasa 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 been adopted by us, we have includedfeasible to retrospectively apply the additional disclosureschange in Note 2. Comments onprinciple, the reason that this proposed FSP are expected by March 7,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).

*    *    *

Forward-Looking Information

The statements regarding future financial and operating performance and results, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

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RESULTS OF OPERATIONS

2005 and 2004 Compared

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.

Natural Gas Production Revenues

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.

Brokered Natural Gas Revenue and Cost

   Year Ended
December 31,
  Variance 
    2005  2004  Amount  Percent 

Sales Price ($/Mcf)

  $9.14  $6.56  $2.58  39%

Volume Brokered (Mmcf)

   10,793   12,876   (2,083) (16)%
           

Brokered Natural Gas Revenues (in thousands)

  $98,605  $84,416   
           

Purchase Price ($/Mcf)

  $8.08  $5.84  $2.24  38%

Volume Brokered (Mmcf)

   10,793   12,876   (2,083) (16)%
           

Brokered Natural Gas Cost (in thousands)

  $87,183  $75,217   
           

Brokered Natural Gas Margin (in thousands)

  $11,422  $9,199  $2,223  24%
              

(in thousands)

      

Sales Price Variance Impact on Revenue

  $27,852     

Volume Variance Impact on Revenue

   (13,664)    
         
  $14,188     
         

(in thousands)

      

Purchase Price Variance Impact on Purchases

  $(24,130)    

Volume Variance Impact on Purchases

   12,165     
         
  $(11,965)    
         

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.

Crude Oil and Condensate Revenues

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.

    Year Ended
December 31,
  Variance 
    2005  2004  Amount  Percent 

Crude Oil Production (Mbbl)

      

Gulf Coast

   1,528   1,805   (277) (15)%

West

   166   159   7  4%

East

   27   27   —    —   

Canada

   18   4   14  350%
              

Total Company

   1,739   1,995   (256) (13)%
              

Crude Oil Sales Price ($/Bbl)

      

Gulf Coast

  $42.81  $30.67  $12.14  40%

West

  $55.37  $40.29  $15.08  37%

East

  $53.84  $38.28  $15.56  41%

Canada

  $43.39  $37.93  $5.46  14%

Total Company

  $44.19  $31.55  $12.64  40%

Crude Oil Revenue (in thousands)

      

Gulf Coast

  $65,427  $55,357  $10,070  18%

West

   9,155   6,404   2,751  43%

East

   1,463   1,049   414  39%

Canada

   791   129   662  513%
              

Total Company

  $76,836  $62,939  $13,897  22%
              

Price Variance Impact on Crude Oil Revenue (in thousands)

      

Gulf Coast

  $18,547     

West

   2,496     

East

   423     

Canada

   100     
         

Total Company

  $21,566     
         

Volume Variance Impact on Crude Oil Revenue (in thousands)

      

Gulf Coast

  $(8,492)    

West

   299     

East

   —       

Canada

   524     
         

Total Company

  $(7,669)    
         

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.

Impact of Derivative Instruments on Operating Revenues

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

    Year Ended December 31, 
    2005  2004 
    Realized  Unrealized  Realized  Unrealized 
   (In thousands) 

Operating Revenues - Increase/(Decrease) to Revenue

     

Cash Flow Hedges

     

Natural Gas Production

  $(98,223) $1,114  $(54,564) $137 

Crude Oil

   (2,430)  (6)  —     6 
                 

Total Cash Flow Hedges

   (100,653)  1,108   (54,564)  143 

Other Derivative Financial Instruments

     

Natural Gas Production

   —     —     (444)  777 

Crude Oil

   (14,842)  5,518   (17,908)  (2,923)
                 

Total Other Derivative Financial Instruments

   (14,842)  5,518   (18,352)  (2,146)
                 
  $(115,495) $6,626  $(72,916) $(2,003)
                 

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

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.

Operating Expenses

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.

Taxes Other Than Income increased by $13.3 million from 2004 compared to 2005, primarily due to increased production taxes as a result of increased commodity prices. Additionally, ad valorem and franchise taxes were higher compared to the prior year.

Brokered Natural Gas Cost increased by $12.0 million from 2004 to 2005. See the preceding table labeled “Brokered Natural Gas Revenue and Cost” for further analysis.

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.

Impairment of Unproved Properties increased $2.8 million over the prior year. This is due to increased amortization related to unproved property additions both offshore and onshore, including an increase in our Canadian additions.

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

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

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

2004 and 2003 Compared

We reported net income for the year ended December 31, 2004 of $88.4 million, or $2.72$1.81 per share. During 2003, we reported net income of $21.1 million, or $0.66$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.

Natural Gas Production Revenues

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 revenuesRevenues line item onin 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            
   


           

    Year Ended
December 31,
  Variance 
    2004  2003  Amount  Percent 

Natural Gas Production (Mmcf)

      

Gulf Coast

   31,358   29,550   1,808  6%

West

   21,866   23,776   (1,910) (8)%

East

   19,442   18,580   862  5%

Canada

   167   —     167  —   
              

Total Company

   72,833   71,906   927  1%
              

Natural Gas Production Sales Price ($/Mcf)

      

Gulf Coast

  $5.27  $4.78  $0.49  10%

West

  $4.75  $3.67  $1.08  29%

East

  $5.60  $5.15  $0.45  9%

Canada

  $4.69  $—    $4.69  —   

Total Company

  $5.20  $4.51  $0.69  15%

Natural Gas Production Revenue (in thousands)

      

Gulf Coast

  $165,177  $141,107  $24,070  17%

West

   103,851   87,245   16,606  19%

East

   108,935   95,672   13,263  14%

Canada

   784   —     784  —   
              

Total Company

  $378,747  $324,024  $54,723  17%
              

Price Variance Impact on Natural Gas Production Revenue (in thousands)

      

Gulf Coast

  $15,434     

West

   23,613     

East

   8,828     

Canada

   784     
         

Total Company

  $48,659     
         

Volume Variance Impact on Natural Gas Production Revenue (in thousands)

      

Gulf Coast

  $8,635     

West

   (7,009)    

East

   4,438     

Canada

   —       
         

Total Company

  $6,064     
         

The increase in natural gas production revenues was mainly a result of increased sales prices as well as the increase in overall production. Natural gas production was up slightly from the prior year and production revenues also increased from 2003. Natural gas production increased slightly in all regions except the West region, where the decline in production was due to lower capital spending in 2003 and continued natural decline. The increases in both sales price and production resulted in an increase in natural gas production revenues of $54.7 million.

- 37 -


Brokered Natural Gas Revenue and Cost

 

   

Year Ended

December 31,


  Variance

 
   2004

  2003

  Amount

  Percent

 

Sales Price ($/Mcf)

  $6.56  $5.16  $1.40  27%

Volume Brokered (Mmcf)

   12,876   18,557   (5,681) (31)%
   


 

        

Brokered Natural Gas Revenues (in thousands)

  $84,416  $95,754        
   


 

        

Purchase Price ($/Mcf)

  $5.84  $4.64  $1.20  26%

Volume Brokered (Mmcf)

   12,876   18,557   (5,681) (31)%
   


 

        

Brokered Natural Gas Cost (in thousands)

  $75,217  $86,104        
   


 

        

Brokered Natural Gas Margin (in thousands)

  $9,199  $9,650  $(451) (5)%
   


 

  


   

(in thousands)

                

Sales Price Variance Impact on Revenue

  $18,026            

Volume Variance Impact on Revenue

  $(29,363)           
   


           
   $(11,337)           
   


           

(in thousands)

                

Purchase Price Variance Impact on Purchases

  $(15,451)           

Volume Variance Impact on Purchases

  $26,338            
   


           
   $10,887            
   


           

    Year Ended
December 31,
  Variance 
    2004  2003  Amount  Percent 

Sales Price ($/Mcf)

  $6.56  $5.16  $1.40  27%

Volume Brokered (Mmcf)

   12,876   18,557   (5,681) (31)%
           

Brokered Natural Gas Revenues (in thousands)

  $84,416  $95,754   
           

Purchase Price ($/Mcf)

  $5.84  $4.64  $1.20  26%

Volume Brokered (Mmcf)

   12,876   18,557   (5,681) (31)%
           

Brokered Natural Gas Cost (in thousands)

  $75,217  $86,104   
           

Brokered Natural Gas Margin (in thousands)

  $9,199  $9,650  $(451) (5)%
              

(in thousands)

      

Sales Price Variance Impact on Revenue

  $18,026     

Volume Variance Impact on Revenue

   (29,363)    
         
  $(11,337)    
         

(in thousands)

      

Purchase Price Variance Impact on Purchases

  $(15,451)    

Volume Variance Impact on Purchases

   26,338     
         
  $10,887     
         

The decrease in brokered natural gas revenues of $11.3 million combined with the decline in brokered natural gas cost of $10.9 million resulted in a decrease to the brokered natural gas margin of $0.5 million.

- 38 -


Crude Oil and Condensate Revenues

Our average total company realized crude oil sales price, including the realized impact of derivative instruments, was $31.55 per Bbl compared to $29.55 per Bbl for 2003. These prices include the realized impact of derivative instruments, which reduced these prices by $8.98 per Bbl in 2004 and $1.41 per Bbl in 2003. The following table excludes the unrealized loss from the change in derivative fair value of $2.9 million and $1.9 million for the yearyears ended December 31, 2004 and 2003, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate revenuesRevenues line item onin the Statement of Operations.

 

   

Year Ended

December 31,


  Variance

 
   2004

  2003

  Amount

  Percent

 

Crude Oil Production (Mbbl)

                

Gulf Coast

   1,805   2,591   (786) (30%)

West

   159   188   (29) (15%)

East

   27   27   —    —   

Canada

   4   —     4  —   
   


 

  


   

Total Company

   1,995   2,806   (811) (29%)
   


 

  


   

Crude Oil Sales Price ($/Bbl)

                

Gulf Coast

  $30.67  $29.48  $1.19  4%

West

  $40.29  $30.11  $10.18  34%

East

  $38.28  $32.65  $5.63  17%

Canada

  $37.93  $—    $37.93  —   

Total Company

  $31.55  $29.55  $2.00  7%

Crude Oil Revenue (in thousands)

                

Gulf Coast

  $55,357  $76,375  $(21,018) (28%)

West

   6,404   5,675   729  13%

East

   1,049   870   179  21%

Canada

   129   —     129  —   
   


 

  


   

Total Company

  $62,939  $82,920  $(19,981) (24%)
   


 

 ��


   

Price Variance Impact on Crude Oil Revenue

                

(in thousands)

                

Gulf Coast

  $2,151            

West

   1,604            

East

   179            

Canada

   129            
   


           

Total Company

  $4,063            
   


           

Volume Variance Impact on Crude Oil Revenue

                

(in thousands)

                

Gulf Coast

  $(23,169)           

West

   (875)           

East

   —              

Canada

   —              
   


           

Total Company

  $(24,044)           
   


           

   Year Ended
December 31,
  Variance 
   2004  2003  Amount  Percent 

Crude Oil Production (Mbbl)

      

Gulf Coast

   1,805   2,591   (786) (30)%

West

   159   188   (29) (15)%

East

   27   27   —    —   

Canada

   4   —     4  —   
              

Total Company

   1,995   2,806   (811) (29%)
              

Crude Oil Sales Price ($/Bbl)

      

Gulf Coast

  $30.67  $29.48  $1.19  4%

West

  $40.29  $30.11  $10.18  34%

East

  $38.28  $32.65  $5.63  17%

Canada

  $37.93  $—    $37.93  —   

Total Company

  $31.55  $29.55  $2.00  7%

Crude Oil Revenue (in thousands)

      

Gulf Coast

  $55,357  $76,375  $(21,018) (28%)

West

   6,404   5,675   729  13%

East

   1,049   870   179  21%

Canada

   129   —     129  —   
              

Total Company

  $62,939  $82,920  $(19,981) (24%)
              

Price Variance Impact on Crude Oil Revenue (in thousands)

      

Gulf Coast

  $2,151     

West

   1,604     

East

   179     

Canada

   129     
         

Total Company

  $4,063     
         

Volume Variance Impact on Crude Oil Revenue (in thousands)

      

Gulf Coast

  $(23,169)    

West

   (875)    

East

   —       

Canada

   —       
         

Total Company

  $(24,044)    
         

The decline in crude oil production is due to emphasis on natural gas in the Gulf Coast drilling program, along with the natural decline of existing production in south Louisiana. The increase in the realized crude oil price combined with the decline in production resulted in a net revenue decrease of $20.0 million.

Impact of Derivative Instruments on Operating Revenues

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

 

    Year Ended December 31, 
    2004  2003 
    Realized  Unrealized  Realized  Unrealized 
   (In thousands) 

Operating Revenues - Increase/(Decrease) to Revenue

     

Cash Flow Hedges

     

Natural Gas Production

  $(54,564) $137  $(48,829) $(691)

Crude Oil

   —     6   (2,973)  32 
                 

Total Cash Flow Hedges

   (54,564)  143   (51,802)  (659)

Other Derivative Financial Instruments

     

Natural Gas Production

   (444)  777   —     (777)

Crude Oil

   (17,908)  (2,923)  (990)  (1,911)
                 

Total Other Derivative Financial Instruments

   (18,352)  (2,146)  (990)  (2,688)
                 
  $(72,916) $(2,003) $(52,792) $(3,347)
                 

- 39 -

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

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.

Operating Expenses

Total costs and expenses from operations decreased $85.3 million for the year ended December 31, 2004 compared to the year ended December 31, 2003. The primary reasons for this fluctuation are as follows:

 

Brokered natural gas costNatural Gas Cost decreased $10.9 million. For additional information related to this decrease see the analysis performed for Brokered Natural Gas Revenue and Cost.

 

Exploration expense decreased $10.0 million primarily as a result of higher dry hole expense in 2003. During 2004, we drilled 5 dry exploratory wells compared to 15 in the corresponding period of 2003.

 

Depreciation, Depletion and Amortization increased, as anticipated, by approximately 9% or $8.4 million. The increase was primarily due to negative reserve revisions in south Louisiana in 2003, which increased the per Mcfe DD&A rate.rate in 2004.

 

Impairment of producing propertiesOil 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 incurred infield. Effective February 13, 2003, as discussed belowthe 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 “Operating Expenses” sectionpartnership assets. Based on the receipt of “2003 and 2002 Compared.”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.

 

Taxes other than incomeOther Than Income increased $3.9 million as a result of higher commodity prices realized induring the year ended 2004 as compared to the same period of the prior year.

Interest Expense, Net

Interest expense decreased $1.7 million. This variance is due to a lower average level of outstanding debt on the revolving credit facility offset somewhat by an increase in Prime rates. Average daily borrowings under the revolving credit facility during the year were $0.5 million in 2004 which is a decrease from $0.7 million in 2003. Our other remaining debt is at fixed interest rates.

Income Tax Expense

Income tax expense increased $35.2 million due to a comparablean increase in our pre-tax net income.

 

- 40 -


2003 and 2002 Compared

We reported net income for the year ended December 31, 2003 of $21.1 million, or $0.66 per share. During the corresponding period of 2002, we reported net income of $16.1 million, or $0.51 per share. Operating income increased by $17.5 million compared to the comparable period of the prior year. The increase in net income and operating income was substantially due to an increase in our realized natural gas and crude oil prices.

Natural Gas Production Revenues

The average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $4.51 per Mcf. Due to derivative instruments this price was reduced by $0.68 per Mcf. The following table excludes the unrealized impact of the change in derivative fair value for the year ended December 31, 2003 and 2002. These amounts have been included in the Natural Gas Production Revenues line item on the Statement of Operations. See Item 7A for a discussion of the realized and unrealized impact of derivative instruments on operating revenues.

   

Year Ended

December 31,


  Variance

 
   2003

  2002

  Amount

  Percent

 

Natural Gas Production (Mmcf)

                

Gulf Coast

   29,550   30,408   (858) (3%)

West

   23,776   25,308   (1,533) (6%)

East

   18,580   17,953   626  3%
   


 

  


   

Total Company

   71,906   73,670   (1,764) (2%)
   


 

  


   

Natural Gas Production Sales Price ($/Mcf)

                

Gulf Coast

  $4.78  $3.34  $1.44  43%

West

  $3.67  $2.39  $1.28  54%

East

  $5.15  $3.38  $1.77  52%

Total Company

  $4.51  $3.02  $1.49  49%

Natural Gas Production Revenue (in thousands)

                

Gulf Coast

  $141,107  $101,525  $39,582  39%

West

  $87,245  $60,563  $26,682  44%

East

  $95,672  $60,696  $34,976  58%
   


 

  


   

Total Company

  $324,024  $222,784  $101,240  45%
   


 

  


   

Price Variance Impact on Natural Gas Production Revenue

                

(in thousands)

                

Gulf Coast

  $42,446            

West

  $30,349            

East

  $32,859            
   


           

Total Company

  $105,654            
   


           

Volume Variance Impact on Natural Gas Production Revenue

                

(in thousands)

                

Gulf Coast

  $(2,864)           

West

  $(3,667)           

East

  $2,117            
   


           

Total Company

  $(4,414)           
   


           

The decline in natural gas production is due substantially to the size and timing of Gulf Coast and West drilling programs, along with the natural decline of existing production. The increase in the realized natural gas price combined with the decline in production resulted in a net revenue increase of $101.2 million.

- 41 -


Brokered Natural Gas Revenue and Cost

   

Year Ended

December 31,


  Variance

 
   2003

  2002

  Amount

  Percent

 

Sales Price ($/Mcf)

  $5.16  $3.12  $2.04  65%

Volume Brokered (Mmcf)

   18,557   18,807   (250) (1%)
   


 

        

Brokered Natural Gas Revenues (in thousands)

  $95,754  $58,678        
   


 

        

Purchase Price ($/Mcf)

  $4.64  $2.82  $1.82  65%

Volume Brokered (Mmcf)

   18,557   18,807   (250) (1%)
   


 

        

Brokered Natural Gas Cost (in thousands)

  $86,104  $53,036        
   


 

        

Brokered Natural Gas Margin (in thousands)

  $9,650  $5,642  $4,008  71%
   


 

  


 

(in thousands)

                

Sales Price Variance Impact on Revenue

  $37,856            

Volume Variance Impact on Revenue

  $(780)           
   


           
   $37,076            
   


           

(in thousands)

                

Purchase Price Variance Impact on Purchases

  $(33,774)           

Volume Variance Impact on Purchases

  $705            
   


           
   $(33,069)           
   


           

- 42 -


Crude Oil and Condensate Revenues

The average total company realized crude oil sales price, including the realized impact of derivative instruments, was $29.55 per Bbl for the year ended December 31, 2003. Due to derivative instruments, this price was reduced by $1.41 per Bbl. The following table excludes the unrealized impact of the change in derivative fair value for the year ended December 31, 2003 and 2002. These amounts have been included in the Crude Oil and Condensate revenues line item on the Statement of Operations. See Item 7A for a discussion of the realized and unrealized impact of derivative instruments on operating revenues.

   Year Ended
December 31,


  Variance

 
   2003

  2002

  Amount

  Percent

 

Crude Oil Production (Mbbl)

                

Gulf Coast

   2,591   2,620   (30) (1%)

West

   188   216   (27) (13%)

East

   27   33   (6) (18%)
   


 

  


 

Total Company

   2,806   2,869   (63) (2%)
   


 

  


   

Crude Oil Sales Price ($/Bbl)

                

Gulf Coast

  $29.48  $23.69  $5.79  24%

West

  $30.11  $25.24  $4.87  19%

East

  $32.65  $22.09  $10.56  48%

Total Company

  $29.55  $23.79  $5.77  24%

Crude Oil Revenue (in thousands)

                

Gulf Coast

  $76,375  $62,075  $14,299  23%

West

  $5,675  $5,445  $230  4%

East

  $870  $721  $149  21%
   


 

  


   

Total Company

  $82,919  $68,241  $14,678  22%
   


 

  


   

Price Variance Impact on Crude Oil Revenue

                

(in thousands)

                

Gulf Coast

  $14,999            

West

  $917            

East

  $281            
   


           

Total Company

  $16,197            
   


           

Volume Variance Impact on Crude Oil Revenue

                

(in thousands)

                

Gulf Coast

  $(700)           

West

  $(687)           

East

  $(133)           
   


           

Total Company

  $(1,519)           
   


           

The decline in crude oil production is due substantially to the size and timing of the Gulf Coast drilling program, along with the natural decline of existing production. The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $14.6 million.

- 43 -


Other Operating Revenues

Other operating revenues increased $3.6 million. This change was a result of an increase in plant revenue, transportation revenue and natural gas liquid revenue for the year ended December 31, 2003.

Operating Expenses

Total costs and expenses from operations increased $150.1 million for the year ended December 31, 2003 compared to the year ended December 31, 2002. The primary reasons for this fluctuation are as follows:

Brokered natural gas cost increased $33.2 million. For additional information related to this increase see the analysis performed for Brokered Natural Gas Revenue and Cost.

Exploration expense increased $18.0 million as a result of higher dry hole expense in 2003. During 2003, we drilled 15 dry exploratory wells compared to 3 in the corresponding period of 2002.

Impairment of producing properties expense increased $91.1 million. This increase is substantially related to a pre-tax non-cash impairment charge of $87.9 million 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 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.

Taxes other than income increased $12.4 million as a result of higher commodity prices realized in the year ended 2003 as compared to the same period of the prior year.

Interest Expense

Interest expense decreased $2.4 million. This variance is due to the combination of a lower average level of outstanding debt on the revolving credit facility as well as a decline in interest rates.

Income Tax Expense

Income tax expense increased $7.4 million due to a comparable increase in our pre-tax net income.

- 44 -


ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Declines in oil and natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that we can produce economically. Historically, oil and gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

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

The domestic and foreign supply of oil and natural gas.

The level of consumer product demand.

Weather conditions.

Political conditions in oil producing regions, including the Middle East.

The ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls.

The price of foreign imports.

Actions of governmental authorities.

Domestic and foreign governmental regulations.

The price, availability and acceptance of alternative fuels.

Overall economic conditions.

These factors make it impossible to predict with any certainty the future prices of oil and gas.

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

Derivative Instruments and Hedging Activity

Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. Under our revolving credit agreement, the aggregate level of commodity hedging must not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. At December 31, 2004,2005, we had 15nine cash flow hedges open: 7eight natural gas price collar arrangements and one crude oil price collar arrangement and 7 natural gas price swap arrangements. Additionally, we had two crude oil financial instruments open at December 31, 2004, that did not qualify for hedge accounting under SFAS 133.arrangement. At December 31, 2004,2005, a $28.8$20.7 million ($17.812.9 million net of tax) unrealized loss was recorded to Accumulated Other Comprehensive Income, along with a $38.4$22.4 million short-term derivative liability and a $2.9$1.7 million short-term derivative receivable.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,Revenue, as appropriate.

- 45 -


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

   Year Ended December 31,

 
   2004

  2003

  2002

 
(In thousands)  Realized

  Unrealized

  Realized

  Unrealized

  Realized

  Unrealized

 

Operating Revenues -Increase / (Decrease) to Revenue

                         

Natural Gas Production

  $(55,008) $914  $(48,829) $(1,468) $(574) $(1,683)

Crude Oil

   (17,908)  (2,917)  (3,963)  (1,879)  (5,202)  (693)

Assuming no change in commodity prices, after December 31, 20042005 we would expect to reclassify to earnings,the Statement of Operations, over the next 12 months, $17.8$12.9 million in after-tax expenditurescharges associated with commodity derivatives.hedges. This reclassification represents the net liability associated with open positions currently not reflected in earnings at December 31, 20042005 related to anticipated 20052006 production.

Hedges on Production - Swaps

From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These 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. 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. During 2004,2005, natural gas price swaps covered 29,61720,557 Mmcf, or 41%28% of our gas production, fixing the sales price of this gas at an average of $5.04$5.14 per Mcf.

At December 31, 2004,2005, we had no open natural gas price swap contracts covering 2005 production as follows:

   Natural Gas Price Swaps

 

Contract Period


  Volume
in
Mmcf


  Weighted
Average
Contract Price


  Unrealized
Gain /(Loss)
(In thousands)


 

As of December 31, 2004

            

Natural Gas Price Swaps on Production in:

            

First Quarter 2005

  5,069  $5.14     

Second Quarter 2005

  5,125   5.14     

Third Quarter 2005

  5,181   5.14     

Fourth Quarter 2005

  5,181   5.14     
   
  

  


Full Year 2005

  20,556  $5.14  $(27,897)

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, 2004,2005, we had two open crude oil swap arrangements with an unrealized net lossdid not have any of $5.5 million recognized in Operating Revenues.

- 46 -these types of arrangements.


Hedges on Production - Options

From time to time, we enter into natural gas and crude oil collar agreements with counterparties to hedge price risk associated with a portion of our production. These cash flow hedges are not held for trading purposes. Under the collar arrangements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. During 2004,2005, natural gas price collars covered 22,95415,157 Mmcf of our gas production, or 32%21% of our gas production with a weighted average floor of $4.78$5.59 per Mcf and a weighted average ceiling of $6.06$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, 2004,2005, we had open natural gas price collar contracts covering our 20052006 production as follows:

 

   Natural Gas Price Collars

 

Contract Period


  Volume
in
Mmcf


  Weighted
Average
Ceiling /Floor


  Unrealized
Gain / (Loss)
(In thousands)


 

As of December 31, 2004

            

First Quarter 2005

  4,982  $9.09 / $6.16     

Second Quarter 2005

  3,367   8.38 /   5.30     

Third Quarter 2005

  3,404   8.38 /   5.30     

Fourth Quarter 2005

  3,404   8.38 /   5.30     
   
  

  


Full Year 2005

  15,157  $8.61 / $5.59   $(2,500)

   Natural Gas Price Collars 

Contract Period

  Volume
in
Mmcf
  Weighted
Average
Ceiling / Floor
  

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)
            

At December 31, 2004,2005, we had one open crude oil price collar contract covering our 20052006 production as follows:

 

   Crude Oil Price Collar

Contract Period


  Volume
in
Mbbl


  Weighted
Average
Ceiling /Floor


  Unrealized
Gain /(Loss)
(In thousands)


As of December 31, 2004

           

First Quarter 2005

  90  $50.50 / $40.00    

Second Quarter 2005

  91   50.50 /   40.00    

Third Quarter 2005

  92   50.50 /   40.00    

Fourth Quarter 2005

  92   50.50 /   40.00    
   
  

  

Full Year 2005

  365  $50.50 / $40.00  $454

   Crude Oil Price 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)
   ��        

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

The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See Forward-Looking Information on page 36.

- 47 -“Forward-Looking Information” for further details.


Fair Market Value of Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value. 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.

Long-Term Debt

 

  December 31, 2004

  December 31, 2003

  December 31, 2005  December 31, 2004

(In thousands)


  Carrying
Amount


  Estimated
Fair Value


  Carrying
Amount


  Estimated
Fair Value


  Carrying
Amount
  Estimated
Fair Value
  Carrying
Amount
  Estimated
Fair Value

Debt

                    

7.19% Notes

  $80,000  $87,770  $100,000  $113,673  $60,000  $62,938  $80,000  $87,770

7.26% Notes

   75,000   85,849   75,000   87,345   75,000   81,713   75,000   85,849

7.36% Notes

   75,000   87,111   75,000   87,770   75,000   83,990   75,000   87,111

7.46% Notes

   20,000   23,804   20,000   24,214   20,000   23,083   20,000   23,804

Credit Facility

   —     —     —     —     90,000   90,000   —     —  
  

  

  

  

            
  $250,000  $284,534  $270,000  $313,002  $320,000  $341,724  $250,000  $284,534
  

  

  

  

            

- 48 -


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

   Page

Report of Independent Registered Public Accounting Firm

  5054

Consolidated Statement of Operations for the Years Ended December 31, 2005, 2004 2003 and 20022003

  5256

Consolidated Balance Sheet at December 31, 20042005 and 20032004

  5357

Consolidated Statement of Cash Flows for the Years Ended December 31, 2005, 2004 2003 and 20022003

  5458

Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2005, 2004 2003 and 20022003

  5559

Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2005, 2004 2003 and 20022003

  5660

Notes to the Consolidated Financial Statements

  5761

Supplemental Oil and Gas Information (Unaudited)

85

Quarterly Financial Information (Unaudited)

  89

Quarterly Financial Information (Unaudited)

93

- 49 -


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have completed an integrated auditaudits of Cabot Oil & Gas Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 20042005, and auditsan audit of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Cabot Oil & Gas Corporation and its subsidiaries at December 31, 20042005 and 2003,2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20042005 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 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 Note 1211 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” effective January 1, 2003.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 20042005 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, 2004,2005, 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.

- 50 -


A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

/s/ PricewaterhouseCoopers LLP


Houston, Texas

March 2, 20056, 2006

- 51 -


CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

 

   YEAR ENDED DECEMBER 31,

   2004

  2003

  2002

OPERATING REVENUES

            

Natural Gas Production

  $379,661  $322,556  $221,101

Brokered Natural Gas

   84,416   95,816   58,729

Crude Oil and Condensate

   60,022   81,040   67,548

Other

   6,309   9,979   6,378
   


 


 

    530,408   509,391   353,756

OPERATING EXPENSES

            

Brokered Natural Gas Cost

   75,217   86,162   53,007

Direct Operations - Field and Pipeline

   53,581   50,399   50,047

Exploration

   48,130   58,119   40,167

Depreciation, Depletion and Amortization

   103,343   94,903   96,512

Impairment of Unproved Properties

   10,145   9,348   9,348

Impairment of Oil & Gas Properties (Note 2)

   3,458   93,796   2,720

General and Administrative

   34,735   25,112   28,377

Taxes Other Than Income

   41,022   37,138   24,734
   


 


 

    369,631   454,977   304,912

Gain (Loss) on Sale of Assets

   (124)  12,173   244
   


 


 

INCOME FROM OPERATIONS

   160,653   66,587   49,088

Interest Expense and Other

   22,029   23,545   25,311
   


 


 

Income Before Income Taxes and Cumulative Effect of Accounting Change

   138,624   43,042   23,777

Income Tax Expense

   50,246   15,063   7,674
   


 


 

INCOME BEFORE CUMULATIVE
EFFECT OF ACCOUNTING CHANGE

   88,378   27,979   16,103

CUMULATIVE EFFECT OF
ACCOUNTING CHANGE (Note 12)

   —     (6,847)  —  
   


 


 

NET INCOME

  $88,378  $21,132  $16,103
   


 


 

Basic Earnings Per Share - Before Accounting Change

  $2.72  $0.87  $0.51

Diluted Earnings Per Share - Before Accounting Change

  $2.69  $0.87  $0.50

Basic Loss Per Share - Accounting Change

  $—    $(0.21) $—  

Diluted Loss Per Share - Accounting Change

  $—    $(0.21) $—  

Basic Earnings Per Share

  $2.72  $0.66  $0.51

Diluted Earnings Per Share

  $2.69  $0.65  $0.50
             

Average Common Shares Outstanding

   32,488   32,050   31,737

Diluted Common Shares (Note 14)

   32,893   32,290   32,076

   Year Ended December 31, 
   2005  2004  2003 

OPERATING REVENUES

     

Natural Gas Production

  $499,177  $379,661  $322,556 

Brokered Natural Gas

   98,605   84,416   95,816 

Crude Oil and Condensate

   82,348   60,022   81,040 

Other

   2,667   6,309   9,979 
             
   682,797   530,408   509,391 

OPERATING EXPENSES

     

Brokered Natural Gas Cost

   87,183   75,217   86,162 

Direct Operations - Field and Pipeline

   61,750   53,581   50,399 

Exploration

   61,840   48,130   58,119 

Depreciation, Depletion and Amortization

   108,458   103,343   94,903 

Impairment of Unproved Properties

   12,966   10,145   9,348 

Impairment of Oil & Gas Properties (Note 2)

   —     3,458   93,796 

General and Administrative

   37,650   34,735   25,112 

Taxes Other Than Income

   54,293   41,022   37,138 
             
   424,140   369,631   454,977 

Gain / (Loss) on Sale of Assets

   74   (124)  12,173 
             

INCOME FROM OPERATIONS

   258,731   160,653   66,587 

Interest Expense and Other

   22,497   22,029   23,545 
             

Income Before Income Taxes and Cumulative Effect of Accounting Change

   236,234   138,624   43,042 

Income Tax Expense

   87,789   50,246   15,063 
             

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE

   148,445   88,378   27,979 

CUMULATIVE EFFECT OF ACCOUNTING CHANGE (Note 11)

   —     —     (6,847)
             

NET INCOME

  $148,445  $88,378  $21,132 
             

Basic Earnings Per Share - Before Accounting Change

  $3.04  $1.81  $0.58 

Diluted Earnings Per Share - Before Accounting Change

  $2.99  $1.79  $0.58 

Basic Loss Per Share - Accounting Change

  $—    $—    $(0.14)

Diluted Loss Per Share - Accounting Change

  $—    $—    $(0.14)

Basic Earnings Per Share

  $3.04  $1.81  $0.44 

Diluted Earnings Per Share

  $2.99  $1.79  $0.44 
     —    

Weighted Average Common Shares Outstanding

   48,856   48,733   48,074 

Diluted Common Shares (Note 12)

   49,725   49,339   48,435 

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

- 52 -


CABOT OIL & GAS CORPORATION

CONSOLIDATED BALANCE SHEET

(In thousands, except share amounts)

 

   December 31,

 
   2004

  2003

 

ASSETS

         

Current Assets

         

Cash and Cash Equivalents

  $10,026  $724 

Accounts Receivable

   125,754   87,425 

Inventories

   24,049   18,241 

Deferred Income Taxes

   21,345   21,935 

Other

   13,505   15,006 
   


 


Total Current Assets

   194,679   143,331 

Properties and Equipment, Net (Successful Efforts Method)

   994,081   895,955 

Deferred Income Taxes

   14,855   8,920 

Other Assets

   7,341   6,850 
   


 


   $1,210,956  $1,055,056 
   


 


LIABILITIES AND STOCKHOLDERS’ EQUITY

         

Current Liabilities

         

Accounts Payable

  $104,969  $84,943 

Current Portion of Long-Term Debt

   20,000   —   

Deferred Income Taxes

   944   1,826 

Accrued Liabilities

   70,976   69,758 
   


 


Total Current Liabilities

   196,889   156,527 

Long-Term Debt

   250,000   270,000 

Deferred Income Taxes

   247,376   208,955 

Other Liabilities

   61,029   54,377 

Commitments and Contingencies (Note 8)

         

Stockholders’ Equity

         

Common Stock:

         

Authorized — 80,000,000 Shares of $.10 Par Value Issued and Outstanding — 33,120,610 Shares and 32,538,255 Shares in 2004 and 2003, Respectively

   3,312   3,254 

Additional Paid-in Capital

   381,781   361,699 

Retained Earnings

   110,935   27,763 

Accumulated Other Comprehensive Loss

   (20,351)  (23,135)

Less Treasury Stock, at Cost:

         

707,700 and 302,600 Shares in 2004 and 2003, Respectively

   (20,015)  (4,384)
   


 


Total Stockholders’ Equity

   455,662   365,197 
   


 


   $1,210,956  $1,055,056 
   


 


   December 31, 
   2005  2004 

ASSETS

   

Current Assets

   

Cash and Cash Equivalents

  $10,626  $10,026 

Accounts Receivable

   168,248   125,754 

Inventories

   24,616   24,049 

Deferred Income Taxes

   15,674   21,345 

Other

   11,148   13,505 
         

Total Current Assets

   230,312   194,679 

Properties and Equipment, Net (Successful Efforts Method)

   1,238,055   994,081 

Deferred Income Taxes

   19,587   14,855 

Other Assets

   7,416   7,341 
         
  $1,495,370  $1,210,956 
         

LIABILITIES AND STOCKHOLDERS’ EQUITY

   

Current Liabilities

   

Accounts Payable

  $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

   35,159   32,608 
         

Total Current Liabilities

   218,584   196,889 

Long-Term Debt

   320,000   250,000 

Deferred Income Taxes

   289,381   247,376 

Other Liabilities

   67,194   61,029 

Commitments and Contingencies (Note 7)

   

Stockholders’ Equity

   

Common Stock:

   

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

   397,349   380,125 

Retained Earnings

   252,167   110,935 

Accumulated Other Comprehensive Loss

   (15,115)  (20,351)

Less Treasury Stock, at Cost:

   

1,513,850 and 1,061,550 Shares in 2005 and 2004, respectively

   (39,198)  (20,015)
         

Total Stockholders’ Equity

   600,211   455,662 
         
  $1,495,370  $1,210,956 
         

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

- 53 -


CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

 

  Year Ended December 31,

   Year Ended December 31, 
  2004

 2003

 2002

   2005 2004 2003 

CASH FLOWS FROM OPERATING ACTIVITIES

       

Net Income

  $88,378  $21,132  $16,103   $148,445  $88,378  $21,132 

Adjustments to Reconcile Net Income to Cash

   

Provided by Operating Activities:

   

Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:

    

Cumulative Effect of Accounting Change

   —     6,847   —      —     —     6,847 

Depletion, Depreciation and Amortization

   103,343   94,903   96,512 

Depreciation, Depletion and Amortization

   108,458   103,343   94,903 

Impairment of Unproved Properties

   10,145   9,348   9,348    12,966   10,145   9,348 

Impairment of Long-Lived Assets

   3,458   93,796   2,720 

Impairment of Oil & Gas Properties

   —     3,458   93,796 

Deferred Income Tax Expense

   31,769   (9,837)  7,882    39,628   31,769   (9,837)

(Gain) / Loss on Sale of Assets

   124   (12,173)  (244)   (74)  124   (12,173)

Exploration Expense

   48,130   58,119   40,167    61,840   48,130   58,119 

Change in Derivative Fair Value

   2,003   3,347   2,376 

Unrealized Change in Derivative Fair Value

   (6,626)  2,003   3,347 

Performance Share Compensation

   3,429   —     —      3,357   3,429   —   

Other

   3,475   885   3,888 

Stock-Based Compensation Expense and Other

   6,446   3,475   885 

Changes in Assets and Liabilities:

       

Accounts Receivable

   (39,404)  (17,397)  (19,317)   (42,494)  (39,404)  (17,397)

Inventories

   (5,808)  (2,989)  2,308    (567)  (5,808)  (2,989)

Other Current Assets

   3,255   (9,208)  3,976    1,188   3,255   (9,208)

Other Assets

   (491)  163   (4,307)   (192)  (491)  163 

Accounts Payable and Accrued Liabilities

   17,231   7,041   7,342    29,803   17,231   7,041 

Other Liabilities

   3,985   (2,339)  (4,572)   2,382   3,985   (2,339)
  


 


 


          

Net Cash Provided by Operating Activities

   273,022   241,638   164,182    364,560   273,022   241,638 
  


 


 


          

CASH FLOWS FROM INVESTING ACTIVITIES

       

Capital Expenditures

   (207,346)  (122,018)  (103,189)   (351,306)  (207,346)  (122,018)

Proceeds from Sale of Assets

   119   28,281   4,688    996   119   28,281 

Exploration Expense

   (48,130)  (58,119)  (40,167)   (61,840)  (48,130)  (58,119)
  


 


 


          

Net Cash Used by Investing Activities

   (255,357)  (151,856)  (138,668)   (412,150)  (255,357)  (151,856)
  


 


 


          

CASH FLOWS FROM FINANCING ACTIVITIES

       

Increase in Debt

   187,000   248,655   180,000    265,000   187,000   248,655 

Decrease in Debt

   (187,000)  (341,000)  (205,746)   (195,000)  (187,000)  (341,000)

Sale of Common Stock Proceeds

   12,474   6,728   3,461    4,586   12,474   6,728 

Purchase of Treasury Stock

   (15,631)  —     —      (19,183)  (15,631)  —   

Dividends Paid

   (5,206)  (5,043)  (5,079)   (7,213)  (5,206)  (5,043)
  


 


 


          

Net Cash Used by Financing Activities

   (8,363)  (90,660)  (27,364)

Net Cash Provided / (Used) by Financing Activities

   48,190   (8,363)  (90,660)
  


 


 


          

Net Increase (Decrease) in Cash and Cash Equivalents

   9,302   (878)  (1,850)

Net Increase / (Decrease) in Cash and Cash Equivalents

   600   9,302   (878)

Cash and Cash Equivalents, Beginning of Period

   724   1,602   3,452    10,026   724   1,602 
  


 


 


          

Cash and Cash Equivalents, End of Period

  $10,026  $724  $1,602   $10,626  $10,026  $724 
  


 


 


          

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

CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In thousands)

 

   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 
                               

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

- 54 -


CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITYCOMPREHENSIVE INCOME

(In thousands)

(In thousands)


  Common
Shares


  Stock
Par


  Treasury
Shares


  Treasury
Stock


  Paid-In
Capital


  

Accumulated
Other
Comprehensive
Income

(Loss)


  Retained
Earnings


  Total

 

Balance at December 31, 2001

  31,905  $3,191  303  $(4,384) $346,260  $835  $650  $346,552 
   
  

  
  


 

  


 


 


Net Income

                         16,103   16,103 

Exercise of Stock Options

  209   20          3,845           3,865 

Cash Dividends at $0.16 per Share

                         (5,079)  (5,079)

Other Comprehensive Loss

                     (13,774)      (13,774)

Stock Grant Vesting

  19   2          2,988           2,990 
   
  

  
  


 

  


 


 


Balance at December 31, 2002

  32,133  $3,213  303  $(4,384) $353,093  $(12,939) $11,674  $350,657 
   
  

  
  


 

  


 


 


Net Income

                         21,132   21,132 

Exercise of Stock Options

  345   35          7,733           7,768 

Cash Dividends at $0.16 per Share

                         (5,043)  (5,043)

Other Comprehensive Loss

                     (10,196)      (10,196)

Stock Grant Vesting

  60   6          873           879 
   
  

  
  


 

  


 


 


Balance at December 31, 2003

  32,538  $3,254  303  $(4,384) $361,699  $(23,135) $27,763  $365,197 
   
  

  
  


 

  


 


 


Net Income

                         88,378   88,378 

Exercise of Stock Options

  529   53          15,060           15,113 

Purchase of Treasury Stock

         405   (15,631)              (15,631)

Performance Share Awards

                 2,394           2,394 

Stock Grant Vesting

  54   5          2,628           2,633 

Cash Dividends at $0.16 per Share

                         (5,206)  (5,206)

Other Comprehensive Income

                     2,784       2,784 
   
  

  
  


 

  


 


 


Balance at December 31, 2004

  33,121  $3,312  708  $(20,015) $381,781  $(20,351) $110,935  $455,662 
   
  

  
  


 

  


 


 


 

   Year Ended December 31, 
   2005  2004  2003 

Net Income

  $148,445  $88,378  $21,132 
             

Other Comprehensive Income / (Loss)

    

Reclassification Adjustment for Settled Contracts

   100,653   53,516   47,926 

Changes in Fair Value of Hedge Positions

   (92,559)  (48,494)  (63,014)

Minimum Pension Liability

   (205)  (1,404)  (1,333)

Foreign Currency Translation Adjustment

   808   662   (5)

Deferred Income Tax

   (3,461)(1)  (1,496)(2)  6,230(3)
             

Total Other Comprehensive Income / (Loss)

   5,236   2,784   (10,196)
             

Comprehensive Income

  $153,681  $91,162  $10,936 
             

(1)Deferred income tax of ($3.5) million at December 31, 2005 represents the net deferred tax liability of approximately ($38.4) million on the Reclassification Adjustment for Settled Contracts, approximately $35.3 million on the Changes in Fair Value of Hedge Positions, approximately less than $0.1 million on the Minimum Pension Liability Adjustment and approximately ($0.3) million on the Foreign Currency Translation Adjustment.
(2)Deferred income tax of ($1.5) million at December 31, 2004 represents the net deferred tax liability of approximately ($20.4) million on the Reclassification Adjustment for Settled Contracts, approximately $18.5 million on the Changes in Fair Value of Hedge Positions, approximately $0.6 million on the Minimum Pension Liability Adjustment and ($0.2) million on the Foreign Currency Translation Adjustment.
(3)Deferred income tax of $6.2 million at December 31, 2003 represents the net deferred tax liability of approximately ($18.3) million on the Reclassification Adjustment for Settled Contracts, approximately $24.0 million on the Changes in Fair Value of Hedge Positions, approximately $0.5 million on the Minimum Pension Liability Adjustment and approximately less than $0.1 million on the Foreign Currency Translation Adjustment.

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

- 55 -


CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

   Year Ended December 31,

 

(In thousands)


  2004

  2003

  2002

 

Net Income

  $88,378  $21,132  $16,103 
   


 


 


Other Comprehensive Income (Loss)

             

Reclassification Adjustment for Settled Contracts

   53,516   47,926   6,230 

Changes in Fair Value of Hedge Positions

   (48,494)  (63,014)  (26,361)

Adjustment to Recognize Minimum Pension Liability

   (1,404)  (1,333)  (2,177)

Foreign Currency Translation Adjustment

   662   (5)  —   

Deferred Income Tax

   (1,496)  6,230   8,534 
   


 


 


Total Other Comprehensive Income (Loss)

   2,784   (10,196)  (13,774)
   


 


 


Comprehensive Income

  $91,162  $10,936  $2,329 
   


 


 


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

- 56 -


CABOT OIL & GAS CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Nature of Operations

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 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.

Recently Issued Accounting Pronouncements

In May 2004,March 2005, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP)Interpretation (FIN) No. FAS 106-2,47, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.for Conditional Asset Retirement Obligations.” This FSP provides guidance onInterpretation clarifies the accounting for the effectsdefinition and treatment of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) for employers that sponsor postretirement health care plans that provide prescription drug benefits. This FSP also requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Act (the subsidy). This FSP supersedes FSP 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” and is effective for the first interim period beginning after June 15, 2004. The Company’s current accumulated projected benefit obligation and net periodic postretirement benefit cost does not reflect any amount associated with the subsidy. Furthermore,conditional asset retirement obligations as discussed in 2004, the Company amended its postretirement benefit plan to exclude prescription drug benefits for participants age 65 and older effective January 1, 2006. The adoption of this FSP is not expected to impact the Company’s operating results, financial position or cash flows.

In November 2004, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 151, “Inventory Costs -143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an amendmentasset retirement activity in which the timing and/or method of ARB No. 43, Chapter 4” in an effort to unitesettlement are dependent on future events that may be outside the United States accounting standards for inventories with International Accounting Standards leading to consistent application of certain accounting requirements. FAS 151 addresses accounting for abnormal amounts of freight, handling costs, idle facility expense and spoilage (wasted material) and requires that these costs be recognized as current period expenses. Previously, these costs had to be categorized as “so abnormal as to require treatment as current period charges.” In addition, allocation of fixed production overheads to the costs of conversion must be based on the normal capacitycontrol of the production facilities. FAS 151 will be effectiveCompany. FIN No. 47 states that a company must record a liability when incurred for fiscal periods beginning after June 15, 2005. The adoption of this statement is not expected to impact the Company’s operating results, financial position or cash flows.

In December 2004, the FASB issued SFAS 153 “Exchanges of Nonmonetary Assets – an amendment of APB Opinion No. 29.” This statement requires that nonmonetary exchanges must be recorded at fair value and the appropriate gain or loss must be recognized so long as the fair value is determinable and the transaction has commercial substance. According to this statement, companies can no longer use the “similar productive assets” concept to account for nonmonetary exchanges at book value with no gain or loss being recognized. FAS 153 will be effective for fiscal periods beginning after June 15, 2005. The adoption of this statement may impact the Company’s operating results, financial position or cash flows in future periodsconditional asset retirement obligations if such a nonmonetary exchange occurs.

- 57 -


In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” SFAS 123R revises SFAS 123, “Accounting for Stock-Based Compensation”, and focuses on accounting for share-based payments for services by employer to employee. The statement requires companies to expense the fair value of employee stock optionsthe 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 other equity-based compensation at the grant date. The statement does not require a certain typemore consistent recognition of valuation model and either a binomial or Black-Scholes model may be used. The provisions of SFAS 123R arethese liabilities. FIN No. 47 is effective for financial statements for fiscal periodsyears ending after JuneDecember 15, 2005. The Company is currently evaluating the methodCompany’s financial position, results of adoptionoperations and the impact on the Company’s operating results. Future cash flows of the Company willwere not be impacted by the adoption of this standard. See “Stock Based Compensation” below for further information.Interpretation, since all asset retirement obligations are currently recorded.

In FebruaryOn April 4, 2005, the FASB released for public comment proposedissued FASB Staff Position (FSP) FAS 19-a19-1 “Accounting for Suspended Well Costs.” This proposed staff position would amendamends FASB Statement No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The proposed position states that exploratory well costs should 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. Although this Staff PositionFor the Company’s 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 finalpractical 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 hasa 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 been adopted byfeasible to retrospectively apply the company,change in principle, the company has includedreason that this is not possible and the additional disclosuresmethod used to report the change is required to be disclosed. The statement also provides that changes in Note 2. Comments on this proposed FSP are expected by March 7,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, 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 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, 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 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. The Company 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. The Company 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). The Company will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).

Pipeline ImbalancesInventories

Inventories are comprised of natural gas and oil in storage, tubular goods and well equipment and pipeline imbalances. All inventory balances are carried at the lower of cost or market. Natural gas and oil in storage is valued at average cost. Tubular goods and well equipment is valued at historical cost.

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

Properties and Equipment

The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells, and successful exploratory drilling costs to locate proved reserves are capitalized.

Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. A determination of whether a well has found proved reserves is made shortly after drilling is completed. The determination is based on a process which relies on interpretations of available geologic, geophysic, 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.

- 58 -


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. 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. During 2004, the Company recorded total impairments of $3.5 million. During 2002,2005, the Company recorded total impairments of $2.7 million.

did not record any impairments.

Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs net of estimated salvage values and acquisition costs, are depreciated and depleted on a field basis by the units-of-production method using proved developed and proved reserves, respectively. The costs of unproved oil and gas properties are generally combined and amortizedimpaired over a period that is based on the average holding period for such properties and the Company’s experience of successful drilling. Properties related to gathering and pipeline systems and 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 depreciated on a straight-line basis.

basis over 3 to 10 years. Buildings are depreciated on a straight-line basis over 25 years.

Costs of retired, sold or abandoned properties that make up a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the units-of-production rate is not significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold.

Revenue Recognition and Gas Imbalances

The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. A natural gas imbalance liability is recorded at the actual price realized upon the gas sale in accounts payable in the consolidated balance sheet if the Company’s excess takes of natural gas exceed its estimated remaining proved developed reserves for these properties. See Note 3 of the Notes to the Consolidated Financial Statements for the Company’s wellhead gas imbalances.

Brokered Natural Gas Margin

The revenues and expenses related to brokering natural gas are reported gross as part of Operating Revenues and Operating Expenses. The Company realizes brokered margin as a result of buying and selling natural gas in back-to-back transactions. The Company realized $11.4 million, $9.2 million, $9.7 million, and $5.7$9.7 million of brokered natural gas margin in 2005, 2004, and 2003, and 2002, respectively.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

- 59 -


Natural Gas Measurement

The Company records estimated amounts for natural gas revenues and natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operation, measurement, and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material.

Accounts Payable

This account may include credit balances from outstanding checks in zero balance cash accounts. TheThese credit balance included in accounts payable was $2.7 million at December 31, 2003, which is reflectedbalances are referred to as an increase in short-term borrowings in financing activities inbook overdrafts, as a component of Accounts Payable on the Consolidated Statement of Cash Flows.Balance Sheet. There waswere no credit balancebalances from outstanding checks in zero balance cash accounts included in accounts payable at December 31, 2005 and 2004 as sufficient cash was available for offset.

Allowance for Doubtful Accounts

The Company records an allowance for doubtful accounts for receivables that the Company feels may be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against the accounts receivable line on the balance sheetBalance Sheet, was $5.6 million and $5.3 million and $5.4 million, respectively, as ofat December 31, 2005 and 2004, and 2003.

respectively.

Risk Management Activities

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. All hedge transactions are 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 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.

When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if the hedge is no longer effective, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge. See Note 11,10 of the Notes to the Consolidated Financial Instruments,Statements for further discussion.

Stock Based Compensation

The Company accounts for stock-based compensation in accordance with the intrinsic value based method 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 costexpense for stock options granted when the exercise price for options granted is equal to the excess, if any,fair value of the quoted market priceCompany’s common stock on the date of the stock at grant date over the amount an employee must pay to acquire the stock.

grant.

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.

- 60 -


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.

 

   Year Ended December 31,

(In thousands, except per share amounts)


  2004

  2003

  2002

Net Income, as reported

  $88,378  $21,132  $16,103

Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax

   1,571   1,950   1,605
   

  

  

Pro forma net income

  $86,807  $19,182  $14,498
   

  

  

Earnings per share:

            

Basic - as reported

  $2.72  $0.66  $0.51

Basic - pro forma

  $2.67  $0.60  $0.46

Diluted - as reported

  $2.69  $0.65  $0.50

Diluted - pro forma

  $2.64  $0.59  $0.45

Share Count

   32,488   32,050   31,737

Diluted Share Count

   32,893   32,290   32,076

   Year Ended December 31,
(In thousands, except per share amounts)  2005  2004  2003

Net Income, as reported

  $148,445  $88,378  $21,132

Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax, previously not included in Net Income

   967   1,571   1,950
            

Pro forma Net Income

  $147,478  $86,807  $19,182
            

Earnings per Share:

      

Basic - as reported

  $3.04  $1.81  $0.44

Basic - pro forma

  $3.02  $1.78  $0.40

Diluted - as reported

  $2.99  $1.79  $0.44

Diluted - pro forma

  $2.97  $1.76  $0.40

Weighted Average Common Shares Outstanding

   48,856   48,733   48,074

Diluted Common Shares

   49,725   49,339   48,435

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.

 

  Year Ended December 31,

   Year Ended December 31, 

(In thousands, except per share amounts)


  2004

 2003

 2002

   2005  2004 2003 

Compensation Expense in Net Income, as reported(1)

  $4,043  $1,001  $2,326   $5,965  $4,043  $1,001 

Weighted Average Value per Option Granted During the Period(2)

  $11.31  $6.77  $6.23 

Assumptions:

   

Weighted Average Value per Option Granted During the Period (2) (3)

  $—    $11.31  $6.77 

Assumptions (3)

     

Stock Price Volatility

   38.4%  35.3%  35.8%   —     38.4%  35.3%

Risk Free Rate of Return

   3.3%  2.5%  3.9%   —     3.3%  2.5%

Dividend Rate (per year)

  $0.16  $0.16  $0.16   $0.147  $0.107  $0.107 

Expected Term (in years)

   4   4   4    4   4   4 

(1)Compensation expense is defined as expense related to the vesting of stock grants, net of tax. Compensation expense in 2002 also includes $1.7 million related tofor the acceleration of stock awards due to the retirement of an executive. Compensation expense inyears ended December 31, 2005 and 2004 also includes $2.1 million and $2.0 million, respectively, net of tax related to performance shares.
(2)Calculated using the Black-Scholes fair value based method.

(3)There were no stock options issued during the year ended December 31, 2005.

Cash and Cash Equivalents

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

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Environmental Matters

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.

Use of Estimates

In preparing financial statements, the Company follows generally accepted accounting principles. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas, natural gas liquids and crude oil reserves and related cash flow estimates used in impairment tests of oil and gas properties, natural gas, natural gas liquids and crude oil revenues and expenses, 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.

- 62 -


2. Properties and Equipment

Properties and equipment are comprised of the following:

 

   December 31,

 
   2004

  2003

 
   (In thousands) 

Unproved Oil and Gas Properties

  $94,795  $86,918 

Proved Oil and Gas Properties

   1,646,841   1,469,751 

Gathering and Pipeline Systems

   160,951   146,909 

Land, Building and Improvements

   4,860   4,758 

Other

   31,261   28,658 
   


 


    1,938,708   1,736,994 

Accumulated Depreciation, Depletion and Amortization

   (944,627)  (841,039)
   


 


   $994,081  $895,955 
   


 


   December 31, 
(In thousands)  2005  2004 

Unproved Oil and Gas Properties

  $107,787  $94,795 

Proved Oil and Gas Properties

   1,970,407   1,646,841 

Gathering and Pipeline Systems

   178,876   160,951 

Land, Building and Improvements

   4,892   4,860 

Other

   33,077   31,261 
         
   2,295,039   1,938,708 

Accumulated Depreciation, Depletion and Amortization

   (1,056,984)  (944,627)
         
  $1,238,055  $994,081 
         

As of December 31, 2004,January 1, 2005, the Company has included disclosures that would be required by the pending FASB Staff Position (“FSP”)adopted FSP FAS 19-a,19-1, “Accounting for Suspended Well Costs.” TheUpon adoption of the FSP, the Company evaluated all existing capitalized exploratory well costs under the provisions of the pending FSP. 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 2003 and 2002.2003.

 

(In thousands)

   December 31,

 
   2004

  2003

  2002

 

Beginning balance at January 1

  $13,277  $3,958  $15,548 

Additions to capitalized exploratory well costs pending the determination of proved reserves

   49,685   48,865   26,580 

Reclassifications to wells, facilities, and equipment based on the determination of proved reserves

   (36,247)  (12,003)  (21,235)

Capitalized exploratory well costs charged to expense

   (18,605)  (27,543)  (16,935)
   


 


 


Ending balance at December 31

  $8,110  $13,277  $3,958 
   


 


 


   December 31, 
(In thousands)  2005  2004  2003 

Beginning balance at January 1

  $8,591  $3,681  $3,757 

Additions to capitalized exploratory well costs pending the determination of proved reserves

   6,132   8,591   3,681 

Reclassifications to wells, facilities, and equipment based on the determination of proved reserves

   (1,069)  (3,395)  (2,881)

Capitalized exploratory well costs charged to expense

   (7,522)  (286)  (876)
             

Ending balance at December 31

  $6,132  $8,591  $3,681 
             

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:

 

   December 31,
(In thousands)  2005  2004  2003

Capitalized exploratory well costs that have been capitalized for a period of one year or less

  $6,132  $8,591  $3,681

Capitalized exploratory well costs that have been capitalized for a period greater than one year

   —     —     —  
            

Balance at December 31

  $6,132  $8,591  $3,681
            

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year

   —     —     —  
            

(In thousands)

   December 31,

   2004

Capitalized exploratory well costs that have been capitalized for a period of one year or less

  $6,471

Capitalized exploratory well costs that have been capitalized for a period greater than one year

   —  
   

Balance at December 31

  $6,471
   

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year

   0
   

There were no capitalized exploratory well costs atAt December 31, 2005 and 2003, and 2002 forthe Company had no wells that havehad completed drilling without the ability to determine the existenceand a determination of whether proved reserves.

- 63 -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 iswas in the Rocky MountainMountains area and reached total depth in November 2004. It cannotcould not be completed due to the Bureau of Land Management stipulation which prohibitsprohibited activity until the summer of 2005. Two wells are in Canada and reached completed drilling in October and December 2004. These wells arewere awaiting completion or sidetracking which iswas 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 quarterlyoperating 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. The limited partner was a financial entity and not an industry operator. Their decision to liquidate was based upon their perception that the value of their investment in the partnership had increased due to an increase in underlying commodity prices, primarily oil, since their investment in 1999. We proceeded with the liquidation to avoid having a minority interest in a non-operated water flood field for which the new operator was not designated at the time of liquidation. In connection with the liquidation, an appraisal was required to be obtained to allocate the interest in the partnership assets. Additionally, the Company was required to test the field for recoverability in accordance with SFAS 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 after-tax impairment charge in the first quarter of 2003 of $54.4 million.$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. TheseThe primary assets includesold 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.

In 2002, the Company recorded impairments of $2.7 million. Included in this impairment amount were impairments on four small fields, three of which were in the Gulf Coast and one in the Rocky Mountains. For each of these fields, the capitalized cost exceeded the future undiscounted cash flows. In addition, a pipeline in the Eastern region was written down to fair market value.

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3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

 

  

December 31,

2004


 December 31,
2003


   December 31, 
  (In thousands) 
(In thousands)  2005 2004 

Accounts Receivable

      

Trade Accounts

  $105,378  $79,439   $147,016  $105,378 

Joint Interest Accounts

   13,554   13,312    14,319   13,554 

Current Income Tax Receivable

   10,796   —      12,239   10,796 

Other Accounts

   1,312   81    315   1,312 
  


 


       
   131,040   92,832    173,889   131,040 

Allowance for Doubtful Accounts

   (5,286)  (5,407)   (5,641)  (5,286)
       
  $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 
  


 


       
  $125,754  $87,425   $24,616  $24,049 
  


 


       

Other Current Assets

      

Derivative Contracts

  $2,906  $1,152   $1,736  $2,906 

Drilling Advances

   6,180   6,443    2,169   6,180 

Prepaid Balances

   4,173   4,325    6,939   4,173 

Other Accounts

   246   3,086    304   246 
  


 


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


 


       

Accounts Payable

      

Trade Accounts

  $12,808  $11,872   $18,227  $12,808 

Natural Gas Purchases

   8,669   5,751    12,208   8,669 

Royalty and Other Owners

   35,369   28,001    49,312   35,369 

Capital Costs

   26,203   21,964    37,489   26,203 

Taxes Other Than Income

   5,634   3,280    10,329   5,634 

Drilling Advances

   7,102   5,721    5,760   7,102 

Wellhead Gas Imbalances

   1,991   2,085    2,175   1,991 

Other Accounts

   7,193   6,269    4,506   7,193 
  


 


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


 


       

Accrued Liabilities

      

Employee Benefits

  $10,123  $9,105   $9,020  $10,123 

Taxes Other Than Income

   14,191   13,359    16,188   14,191 

Interest Payable

   6,569   6,368    6,818   6,569 

Derivative Contracts

   38,368   36,582 

Other Accounts

   1,725   4,344    3,133   1,725 
  


 


       
  $70,976  $69,758   $35,159  $32,608 
  


 


       

Other Liabilities

      

Postretirement Benefits Other Than Pension

  $4,717  $2,132   $6,517  $4,717 

Accrued Pension Cost

   5,089   2,664    5,904   5,089 

Rabbi Trust Deferred Compensation Plan

   4,199   3,568    4,883   4,199 

Derivative Contracts

   —     3,051 

Accrued Plugging and Abandonment Liability

   40,375   36,848    42,991   40,375 

Other

   6,649   6,114 

Other Accounts

   6,899   6,649 
  


 


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


 


       

- 65 -


4. Inventories

Inventories are comprised of the following:

   December 31,

 

(In thousands)


  2004

  2003

 

Natural Gas and Oil in Storage

  $17,631  $15,191 

Tubular Goods and Well Equipment

   6,387   3,367 

Pipeline Imbalances

   31   (317)
   

  


   $24,049  $18,241 
   

  


Natural gas and oil in storage is valued at average cost. Tubular goods and well equipment is valued at historical cost. All inventory balances are carried at the lower of cost or market.

5. Debt and Credit Agreements

7.19% Notes

In November 1997, the Company issued an aggregate principal amount of $100 million of its 12-year 7.19% Notes (7.19% Notes) to a group of six institutional investors in a private placement offering. The 7.19% Notes require five annual $20 million principal payments 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.

7.33% Weighted Average Fixed Rate Notes

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 beis being amortized over the life of the Notes, and thereby reducing the effective interest rate by 5.5 basis points. All of the Notes have bullet maturities and were issued in three separate tranches as follows:

 

   Principal

  Term

  Coupon

 

Tranche 1

  $75,000,000  10-year  7.26%

Tranche 2

  $75,000,000  12-year  7.36%

Tranche 3

  $20,000,000  15-year  7.46%

   Principal  Term  Maturity Date  Coupon 

Tranche 1

  $75,000,000  10-year  July 2011  7.26%

Tranche 2

  $75,000,000  12-year  July 2013  7.36%

Tranche 3

  $20,000,000  15-year  July 2016  7.46%

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

Revolving Credit Agreement

On December 10, 2004, the Company amended its Revolving Credit Agreement (Credit Facility)(credit facility) with a group of nine banks. The Credit Facilitycredit facility allows for borrowings of $250 million, of which $90 million was outstanding at year end was $250 million. ItDecember 31, 2005. The facility can be expanded up to $350 million, either with the existing banks or new banks. This Credit Facilitycredit facility is unsecured. The term of the Credit Facilitycredit facility expires in December 2009. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the banks’ petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. While the Company does not expect a reduction in the available credit line, in the event that it is adjusted below the outstanding level of borrowings, the Company has a period of six months to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or pay down one-sixth of the excess during each of the six months.

- 66 -


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

 

   Debt Percentage 
   Lower than 50%  50% or higher but
not exceeding 75%
  

Higher than 75% but

not exceeding 90%

  Higher than 90% 

Euro-Dollar margin

  1.000% 1.250% 1.500% 1.750%

Base Rate margin

  0.000% 0.000% 0.250% 0.500%

The Company’s effective interest rates for the Credit Facilitycredit facility in the years ended December 31, 2005, 2004, and 2003 and 2002 were 6.9%, 4.2%, and 1.9%, and 3.4%, 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 Facilitycredit facility provides for a commitment fee on the unused available balance at an annual rate of one-quarter of 1%. The Credit Facilitycredit facility also contains various customary restrictions, which include the following:

 

 (a)Maintenance of a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.

 (b)Prohibition on the merger or sale of all, or substantially all, of the Company’s or any subsidiary’s assets to a third party, except under certain limited conditions.

The Company was in compliance with all covenants contained in its various debt agreements at December 31, 20042005 and 20032004 and during the years then ended.

6.5. Employee Benefit Plans

Pension Plan

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, 2004.

2005.

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.

Components of Net Periodic Benefit Cost

Net periodic pension cost of the Company during the last three years is comprised of the following:

 

(In thousands)


  2004

 2003

 2002

   2005 2004 2003 

Qualified

       

Current Year Service Cost

  $1,619  $1,481  $1,056   $2,485  $1,619  $1,481 

Interest Accrued on Pension Obligation

   1,697   1,515   1,362 

Interest Cost

   1,896   1,697   1,515 

Expected Return on Plan Assets

   (1,474)  (999)  (991)   (1,507)  (1,474)  (999)

Net Amortization and Deferral

   88   88   88 

Recognized Loss

   383   415   21 

Amortization of Prior Service Cost

   99   88   88 

Recognized Net Actuarial Loss

   921   383   415 
  


 


 


          

Net Periodic Pension Cost

  $2,313  $2,500  $1,536   $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 
          

- 67 -


(In thousands)


  2004

  2003

  2002

Non-Qualified

            

Current Year Service Cost

  $395  $280  $78

Interest Accrued on Pension Obligation

   381   163   29

Net Amortization

   77   77   77

Loss Recognized from Settlement

         963

Recognized Loss

   428   187   7
   

  

  

Net Periodic Pension Cost

  $1,281  $707  $1,154
   

  

  

Obligations and Funded Status

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

 

   2004

  2003

 

(In thousands)


  Qualified

  Non-Qualified

  Qualified

  Non-Qualified

 

Actuarial Present Value of: Accumulated Benefit Obligation

  $23,181  $3,579  $21,347  $3,171 

Projected Benefit Obligation

  $29,809  $6,257  $27,411  $6,136 

Plan Assets at Fair Value

   18,092   —     18,683   —   
   


 


 


 


Projected Benefit Obligation in Excess of Plan Assets

   11,717   6,257   8,728   6,136 

Unrecognized Net Loss

   (9,846)  (4,374)  (7,083)  (5,457)

Unrecognized Prior Service Cost

   (248)  (322)  (336)  (399)

Adjustment to Recognize Minimum Liability

   3,466   2,018   1,355   2,891 
   


 


 


 


Accrued Pension Cost

  $5,089  $3,579  $2,664  $3,171 
   


 


 


 


   2005  2004 
(In thousands)  Qualified  Non-Qualified  Qualified  Non-Qualified 

Actuarial Present Value of:

     

Accumulated Benefit Obligation

  $29,669  $1,204  $23,181  $3,579 

Projected Benefit Obligation

  $39,449  $1,762  $29,809  $6,257 

Fair Value of Plan Assets

   23,765   —     18,092   —   
                 

Projected Benefit Obligation in Excess of Plan Assets

   15,684   1,762   11,717   6,257 

Unrecognized Net Actuarial Loss

   (14,899)  (498)  (9,846)  (4,374)

Unrecognized Prior Service Cost

   (269)  (245)  (248)  (322)

Adjustment to Recognize Minimum Liability

   5,388   185   3,466   2,018 
                 

Accrued Pension Cost

  $5,904  $1,204  $5,089  $3,579 
                 

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:

 

(In thousands)


  2004

  2003

  2002

 

Beginning of Year

  $33,547  $26,042  $19,894 

Service Cost

   2,014   1,761   1,134 

Interest Cost

   2,078   1,678   1,391 

Actuarial Loss

   1,798   4,679   5,860 

Benefits Paid

   (3,371)  (613)  (2,237)
   


 


 


End of Year

  $36,066  $33,547  $26,042 
   


 


 


(In thousands)  2005  2004  2003 

Beginning of Year

  $36,066  $33,547  $26,042 

Service Cost

   1,803   2,014   1,761 

Interest Cost

   1,981   2,078   1,678 

Actuarial Loss

   1,852   1,798   4,679 

Plan Amendments

   120   —     —   

Benefits Paid

   (611)  (3,371)  (613)
             

End of Year

  $41,211  $36,066  $33,547 
             

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

 

(In thousands)


  2004

 2003

 2002

   2005 2004 2003 

Beginning of Year

  $18,683  $10,279  $9,909   $18,092  $18,683  $10,279 

Actual Return on Plan Assets

   957   2,446   (1,280)   1,544   957   2,446 

Employer Contribution

   2,000   6,735   4,080    5,000   2,000   6,735 

Benefits Paid

   (3,371)  (613)  (2,237)   (611)  (3,371)  (613)

Expenses Paid

   (177)  (164)  (193)   (260)  (177)  (164)
  


 


 


          

End of Year

  $18,092  $18,683  $10,279   $23,765  $18,092  $18,683 
  


 


 


          

- 68 -


The reconciliation of the combined funded status of the Company’s qualified and non-qualified pension plans at the end of the last three years is explained as follows:

 

(In thousands)


  2004

 2003

 2002

   2005 2004 2003 

Funded Status(1)

  $17,974  $14,864  $15,762   $17,446  $17,974  $14,864 

Unrecognized Loss

   (14,220)  (12,540)  (9,745)

Unrecognized Prior Service Cost

   (570)  (735)  (899)

Unrecognized Net Actuarial Loss

   (15,397)  (14,220)  (12,540)

Unrecognized Net Prior Service Cost

   (514)  (570)  (735)
  


 


 


          

Net Amount Recognized

  $3,184  $1,589  $5,118   $1,535  $3,184  $1,589 
  


 


 


          

Accrued Benefit Liability – Qualified Plan

  $5,089  $2,664  $7,857 

Accrued Benefit Liability – Non-Qualified Plan

   3,579   3,171   338 

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

   (5,484)  (4,246)  (3,077)   (454)  (570)  (735)

Accumulated Other Comprehensive Income

   (5,119)  (4,914)  (3,511)
  


 


 


          

Net Amount Recognized

  $3,184  $1,589  $5,118   $1,535  $3,184  $1,589 
  


 


 


          

(1)The qualified and non-qualified pension plans are in an under-funded position for 2005, 2004 and 2003 as the projected benefit obligation exceeds the plan assets.

Additional Information

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:

 

(In thousands)  2005  2004  2003 

Qualified Plan

  $1,900  $2,199  $(870)

Non-Qualified Plan

   (1,695)  (795)  2,203 

Assumptions

Assumptions used to determine projected postretirementpension benefit obligations andare as follows:

   2005  2004  2003 

Discount Rate

  5.50% 5.75% 6.25%

Rate of Compensation Increase

  4.00% 4.00% 4.00%

Assumptions used to determine net periodic pension costs are as follows:

 

   2004

  2003

  2002

 

Discount Rate(1)

  5.75% 6.25% 6.50%

Rate of Increase in Compensation Levels

  4.00% 4.00% 4.00%

Long-Term Rate of Return on Plan Assets

  8.00% 8.00% 9.00%

Health Care Cost Trend for Medical Benefits

  10.00% 8.00% 8.00%

(1)Represents the year end rates used to determine the projected benefit obligation. To compute pension cost in 2004, 2003 and 2002, respectively, the beginning of year discount rates of 6.25%, 6.50% and 7.25%, were used.

   2005  2004  2003 

Discount Rate

  5.75% 6.25% 6.50%

Expected Long-Term Return on Plan Assets

  8.00% 8.00% 8.00%

Rate of Compensation Increase

  4.00% 4.00% 4.00%

The long-term expected rate of return on plan assets used in 20042005, as shown above, is eight percent. The Company establishes the long-term expected rate of return by developing a forward looking long-term expected rate of return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation.

Estimated future benefit payments under the Company’s qualified and non-qualified pension plans are expected to be paid as follows:

(In thousands)


  Qualified

  Non-Qualified

  Total

2005

  $553  $216  $769

2006

   640   368   1,008

2007

   731   262   993

2008

   808   316   1,124

2009

   963   504   1,467

Years 2010 - 2014

   8,332   3,697   12,029

Plan Assets

At December 31, 20042005 and 2003,2004, the non-qualified pension plan did not have plan assets. The plan assets of the Company’s qualified pension plan at December 31, 20042005 and 2003,2004, by asset category are as follows:

 

  2004

 2003

   2005 2004 

(In thousands)


  Amount

  Percent

 Amount

  Percent

   Amount  Percent Amount  Percent 

Equity securities

  $13,934  77% $11,722  63%  $19,556  82% $13,934  77%

Debt securities

   3,226  18%  3,349  18%   840  4%  3,226  18%

Other(1)

   932  5%  3,612  19%   3,369  14%  932  5%
  

  

 

  

             

Total

  $18,092  100% $18,683  100%  $23,765�� 100% $18,092  100%
  

  

 

  

             

(1)Primarily consists of cash and cash equivalents.

- 69 -


The Company’s investment strategy for benefit plan assets is to invest in funds to maximize the return over the long-term, subject to an appropriate level of risk. Additionally, the objective is for each class of investments to outperform its representative benchmark over the long term. The Company generally targets a portfolio of assets that are within a range of approximately 60% to 80% for equity securities and approximately 20% to 40% for fixed income securities.

Cash Flows

Contributions

The funding levels of the pension plans are in compliance with standards set by applicable law or regulation. In 20042005 the Company did not have any required minimum funding obligations; however, it chose to fund $2$5 million into the plan. In 20052006 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 2005.2006.

Estimated Future Benefit Payments

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

 

Savings Investment Plan

The Company has a Savings Investment Plan (SIP) which is a defined contribution plan. The Company matches a portion of employees’ contributions in cash. Participation in the SIP is voluntary and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $1.4 million, $1.4 million, and $1.3 million in 2004, 2003, and 2002, respectively. The Company matches employee contributions dollar-for-dollar on the first 6% of an employee’s pretax earnings. The Company’s Common Stock is an investment option within the SIP.

Deferred Compensation Plan

In 1998, the Company established a Deferred Compensation Plan. This plan is available to officers of the Company and acts as a supplement to the Savings Investment Plan. The Company matches a portion of the employee’s contribution and those assets are invested in instruments selected by the employee. Unlike the SIP, the Deferred Compensation Plan does not have dollar limits on tax deferred contributions. However, the assets of this plan are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company. At December 31, 2004, the balance in the Deferred Compensation Plan’s rabbi trust was $4.2 million.

The employee participants guide the diversification of trust assets. The trust assets are invested in mutual funds that cover the investment spectrum from equity to money market. These mutual funds are publicly quoted and reported at market value. No shares of the Company’s stock are held by the trust. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets is recorded on the Company’s balance sheet as a component of Other Assets and the corresponding liability is recorded as a component of Other Liabilities.

There is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets for two reasons. First, the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants. Second, no shares of the Company’s stock are held in the trust.

The Company charged to expense plan contributions of less than $20,000 in each year presented.

(In thousands)  Qualified  Non-Qualified  Total

2006

  $828  $42  $870

2007

   848   54   902

2008

   916   74   990

2009

   1,106   85   1,191

2010

   1,256   176   1,432

Years 2011 - 2015

   10,878   1,418   12,296

Postretirement Benefits Other than Pensions

In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. 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 and 244 retirees and their dependants at the end of 2003.2004. The measurement date used to measure postretirement benefits other than pensions is December 31, 2004.

- 70 -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 $4.6$3.9 million which will be amortized over the next sevensix years.

Components of Net Periodic Benefit Cost

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

 

(In thousands)


  2004

  2003

  2002

 

Service Cost of Benefits Earned During the Year

  $671  $265  $215 

Interest Cost on the Accumulated Postretirement Benefit Obligation

   784   385   381 

Amortization Benefit of the Unrecognized Gain

   (59)  (155)  (267)

Amortization of Prior Service Cost

   1,211   —     —   

Amortization Benefit of the Unrecognized Transition Obligation

   662   662   662 
   


 


 


Total Postretirement Benefit Cost

  $3,269  $1,157  $991 
   


 


 


(In thousands)  2005  2004  2003 

Current Year Service Cost

  $675  $671  $265 

Interest Cost

   605   784   385 

Recognized Net Actuarial Gain

   (79)  (59)  (155)

Amortization of Prior Service Cost

   910   1,211   —   

Amortization of Net Obligation at Transition

   648   662   662 
             

Total Postretirement Benefit Cost

  $2,759  $3,269  $1,157 
             

Obligations and Funded Status

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

 

(In thousands)  2005  2004  2003 

Beginning of Year (1)

  $14,101  $6,181  $6,185 

Service Cost

   675   671   265 

Interest Cost

   605   784   386 

Amendments

   (1,434)  6,901   —   

Actuarial (Gain) / Loss

   (876)  864   221 

Benefits Paid

   (1,278)  (1,300)  (876)
             

End of Year(1)

  $11,793  $14,101  $6,181 
             

(1)The postretirement plan is in an under-funded position for 2005, 2004 and 2003 since the projected benefit obligation exceeds the plan assets. The postretirement plan does not have any plan assets.

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

(In thousands)  2005  2004  2003 

Fair Value of Plan Assets

  $—    $—    $—   

Funded Status

   11,793   14,101   6,181 

Unrecognized Net Gain

   2,475   814   1,736 

Unrecognized Net Prior Service Cost

   (3,366)  (5,691)  —   

Unrecognized Net Transition Obligation

   (3,888)  (4,631)  (5,293)
             

Accrued Postretirement Benefit Liability

  $7,014  $4,593  $2,624 
             

Assumptions

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

   2005  2004  2003 

Discount Rate(1)

  5.50% 5.75% 6.25%

Health Care Cost Trend Rate for Medical Benefits Assumed for Next Year

  9.00% 10.00% 8.00%

Rate to which the cost trend rate is assumed to decline (the Ultimate Trend Rate)

  5.00% 5.00% N/A 

Year that the rate reaches the Ultimate Trend Rate

  2010  2009  2009 

(1)Represents the year end rates used to determine the projected benefit obligation. To compute postretirement cost in 2005, 2004 and 2003, respectively, the beginning of year discount rates of 5.75%, 6.25% and 6.50% were used.

The health care cost trend rate used to measure the expected cost from 2000 to 2003 for medical benefits to retirees was 8%. Provisions of the plan should preventexisting at that time would have prevented significant future increases in employer cost after 2000. During the yearyears ended December 31, 2005 and 2004, the plan was amended and the limit, or cap, on the employer subsidy for medical and prescription drugin several areas effective January 1, 2006. As of January 1, 2006, coverage provided to participants age 65 and older was removed. In addition, certain other modificationswill 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 plan were madeself-funded plan. The Company subsidy will be limited to limit prescription drug coverage (for60% of the expected annual fully-insured premium. For all participants notof any age, 65 and older) and increase the plan deductibles and reimbursements by retirees. The companyCompany subsidy for all retiree medical and prescription drug benefits, for all other participants, beginning January 1, 2006, is limited to an aggregate annual amount not to exceed $648,000. This limit will increase by 3.5% annually thereafter.

The health care cost trend rate used at December 31, 2004 was 10%. The rate 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 which the cost trend rate is assumed to decline (the ultimate trend rate) is 5% as of December 31, 2004. The year that this ultimate trend rate will be reached is 2009.

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:

 

(In thousands)


  

1-Percentage-

Point Increase


  

1-Percentage-

Point Decrease


   1-Percentage-
Point Increase
  1-Percentage-
Point Decrease
 

Effect on total of service and interest cost

  $146  $(163)  $12  $(13)

Effect on postretirement benefit obligation

   1,661   (2,025)   131   (147)

Cash Flows

Contributions

The funded status ofCompany expects to contribute approximately $0.6 million to the postretirement benefit plan in 2006.

Estimated Future Benefit Payments

The following estimated benefit payments under the Company’s postretirement benefit obligation at December 31, 2004, and 2003 is comprised of the following:

(In thousands)


  2004

  2003

 

Plan Assets at Fair Value

  $—    $—   

Accumulated Postretirement Benefits Other Than Pensions

   14,101   6,181 

Unrecognized Cumulative Net Gain

   814   1,736 

Unrecognized Prior Service Cost

   (5,691)  —   

Unrecognized Transition Obligation

   (4,631)  (5,293)
   


 


Accrued Postretirement Benefit Liability

  $4,593  $2,624 
   


 


- 71 -


The change in the accumulated postretirement benefit obligation during the last three years is presentedplans, which reflect expected future service, as follows:

(In thousands)


  2004

  2003

  2002

 

Beginning of Year

  $6,181  $6,185  $5,507 

Service Cost

   671   265   215 

Interest Cost

   784   386   381 

Amendments

   6,901   —     —   

Actuarial Loss

   864   221   912 

Benefits Paid

   (1,300)  (876)  (830)
   


 


 


End of Year

  $14,101  $6,181  $6,185 
   


 


 


Estimated future benefit paymentsappropriate, are expected to be paid as follows:

 

(In thousands)


      

2005

  $1,034

2006

   653  $571

2007

   688   579

2008

   706   580

2009

   735   594

Years 2010 - 2014

   4,479

2010

   616

Years 2011 - 2015

   3,894

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.

Savings Investment Plan

The Company has a Savings Investment Plan (SIP), which is a defined contribution plan. The Company matches a portion of employees’ contributions in cash. Participation in the SIP is voluntary, and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $1.6 million, $1.4 million and $1.4 million in 2005, 2004, and 2003, respectively. The Company matches employee contributions dollar-for-dollar on the first 6% of an employee’s pretax earnings. The Company’s common stock is an investment option within the SIP.

- 72 -Deferred Compensation Plan

In 1998, the Company established a Deferred Compensation Plan. This plan is available to officers of the Company and acts as a supplement to the Savings Investment Plan. If the employee’s base salary and bonus deferrals cause the employee to not receive the full 6% company match to the Savings Investment Plan, the Company will make a contribution annually into the Deferred Compensation Plan to ensure that the employee receives a full matching contribution from the Company. Unlike the SIP, the Deferred Compensation Plan does not have dollar limits on tax deferred contributions. However, the assets of this plan are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company. At December 31, 2005, the balance in the Deferred Compensation Plan’s rabbi trust was $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.


7.6. Income Taxes

Income tax expense (benefit) is summarized as follows:

 

   Year Ended December 31,

 

(In thousands)


  2004

  2003

  2002

 

Current

             

Federal

  $14,767  $22,826  $(1,158)

State

   3,710   2,075   869 
   


 


 


Total

   18,477   24,901   (289)
   


 


 


Deferred

             

Federal

   31,779   (8,549)  7,931 

State

   (10)  (1,289)  32 
   


 


 


Total

   31,769   (9,838)  7,963 
   


 


 


Total Income Tax Expense

  $50,246  $15,063  $7,674 
   


 


 


   Year Ended December 31, 
(In thousands)  2005  2004  2003 

Current

     

Federal

  $42,976  $14,767  $22,826 

State

   5,185   3,710   2,075 
             

Total

   48,161   18,477   24,901 
             

Deferred

     

Federal

   37,565   31,779   (8,549)

State

   2,063   (10)  (1,289)
             

Total

   39,628   31,769   (9,838)
             

Total Income Tax Expense

  $87,789  $50,246  $15,063 
             

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)


  2004

 2003

 2002

   2005 2004 2003 

Statutory Federal Income Tax Rate

   35%  35%  35%   35%  35%  35%

Computed “Expected” Federal Income Tax

  $48,518  $15,065  $8,322   $82,682  $48,518  $15,065 

State Income Tax, Net of Federal Income Tax Benefit

   4,353   1,334   737    7,030   4,353   1,334 

Other, Net

   (2,625)(1)  (1,336)(2)  (1,385)(3)   (1,923)(1)  (2,625)(2)  (1,336)(3)
  


 


 


          

Total Income Tax Expense

  $50,246  $15,063  $7,674   $87,789  $50,246  $15,063 
  


 


 


          

(1)Other, Net includes credit adjustments of $1.3 million related to the qualified production activities deduction, $0.6 million related to the recognition of benefit for federal statutory depletion in excess of basis, $1.0 million related to the recognition of benefit for state statutory depletion in excess of basis, $0.6 million related to the reduction of the state statutory rate and other permanent items. Other, Net also includes debit adjustments of $0.7 million related to excess compensation, $0.7 million related to Internal Revenue Service audit adjustments and other permanent items.
(2)Other, Net includes credit adjustments of $1.6 million related to the recognition of benefit for federal statutory depletion in excess of basis, $0.9 million related to the recognition of benefit for state statutory depletion in excess of basis, and other permanent items.
(2)(3)Other, Net includes credit adjustments of $0.8 million related to the recognition of benefit for a state statutory depletion in excess of basis and $0.5 million related to the recognition of a benefit for a state net operating loss.
(3)Other, Net includes credit adjustments totaling $0.8 million to deferred taxes as a result of a reduction to the state effective tax rate, $0.8 million to deferred taxes as a result of basis adjustments related to the Cody acquisition, and other permanent items.

The tax effects of temporary differences that resulted in significant portions of the deferred tax liabilities and deferred tax assets as of December 31 were as follows:

 

(In thousands)


  2004

  2003

Deferred Tax Liabilities

        

Property, Plant and Equipment

  $246,962  $208,955

Items Accrued for Financial Reporting Purposes

   1,358   1,826
   

  

    248,320   210,781

Deferred Tax Assets

        

Net Operating Loss Carryforwards

   2,045   725

Items Accrued for Financial Reporting Purposes

   21,290   15,893

Other Comprehensive Income

   12,865   14,237
   

  

    36,200   30,855
   

  

Net Deferred Tax Liabilities

  $212,120  $179,926
   

  

- 73 -


    Year Ended December 31,
(In thousands)  2005  2004

Deferred Tax Liabilities

    

Property, Plant and Equipment

  $288,602  $246,962

Items Accrued for Financial Reporting Purposes

   1,720   1,358
        

Total

   290,322   248,320
        

Deferred Tax Assets

    

Net Operating Loss Carryforwards

   2,591   2,045

Items Accrued for Financial Reporting Purposes

   22,840   21,290

Other Comprehensive Income

   9,830   12,865
        

Total

   35,261   36,200
        

Net Deferred Tax Liabilities

  $255,061  $212,120
        

As of December 31, 2004,2005, the Company had a net operating loss carryforward of $39.5$50.3 million for state income tax reporting purposes, the majority of which will expire between 20112013 and 20242025 and none available for regular federal income tax purposes. It is expected that these deferred tax benefits will be utilized prior to their expiration.

8.7. Commitments and Contingencies

Firm Gas Transportation Agreements and Drilling Rig Commitments

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:

(In thousands)   

2006

  $11,661

2007

   11,626

2008

   8,213

2009

   3,381

2010

   3,381

Thereafter

   55,504
    
  $93,766
    

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:

(In thousands)   

2006

  $26,055

2007

   41,245

2008

   27,340

2009

   9,675
    
  $104,315
    

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.

Lease Commitments

The Company leases certain transportation vehicles, warehouse facilities, office space, and machinery and equipment under cancelable and non-cancelable leases. The lease for the Company’s office in Houston runs for approximately fivefour more years. Most of the Company’s leases expire within five years and may be renewed. Rent expense under such arrangements totaled $9.1 million, $8.7 million, $8.5 million, and $8.8$8.5 million for the years ended December 31, 2005, 2004, and 2003, and 2002, respectively.

Future minimum rental commitments under non-cancelable leases in effect at December 31, 20042005 are as follows:

 

(In thousands)


   

2005

  $4,889

2006

   4,542

2007

   4,340

2008

   2,063

2009

   784

Thereafter

   382
   

    $17,000
   

(In thousands)   

2006

  $4,876

2007

   4,633

2008

   4,541

2009

   3,207

2010

   489

Thereafter

   —  
    
  $17,746
    

Contingencies

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

Wyoming Royalty Litigation

In June 2000, the Company was sued by two overriding royalty owners in Wyoming state court for unspecified damages. The plaintiffs requested class certification and alleged that the Company had improperly deducted costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claimed that the Company had failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. At a mediation held in April 2003, the plaintiffs in this case claimed total damages of $9.5 million plus attorney fees. The Company settled the case for a total of $2.25 million and the State District Court Judge entered his order approving the settlement in the fourth quarter of 2003. The class included all private fee royalty and overriding royalty owners of the Company in the State of Wyoming except those in the suit discussed below and one owner who opted out of the settlement. It also includes provisions for the method of valuation of gas for royalty payment purposes going forward and for reporting of royalty payments, which should prevent further litigation of these issues by the class members.

In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district court.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 as the plaintiffs in the Wyoming state court case but have not askedand claims concerning penalties for class certification.

- 74 -


The federal district court judge certified two questionsimproper reporting. As a result of state law for decisionseveral decisions by the Wyoming State Supreme Court which recently answered both questions. The Wyoming Supreme Court ruled that certain deductions taken byfavorable to the Company, the case was settled in September 2005 with no payment from the plaintiffs were not properCompany and thata dismissal with prejudice of all claims by plaintiffs. The settlement included provisions for reporting and payment going forward. Management has reversed the statutes of limitations advanced byreserve it had recorded regarding this case, which had an immaterial impact on the Company are discovery statutes and accordingly do not begin to run until the plaintiffs knew, or had reason to know, of the violation. The Company believes it has properly reported to the plaintiffs, and that if it did not, the plaintiffs knew or should have known the reporting was improper and the nature of the deductions, thus triggering the statute of limitations. The Company still intends to raise defenses to the alleged failure to report claims. There is also a dispute as to how the interest should be calculated.

The federal judge refused to certify a question relating to the issue of the proper calculation of damages for failure to provide certain information required by statute on overriding royalty owner check stubs that had been decided adversely to our position in a state district court letter decision in a separate case. After the federal judge’s refusal to certify this issue, the plaintiffs reduced the damages they were claiming. Based upon recent communication from the plaintiffs they are now claiming $26.2 million in total damages which consists of $20.3 million for alleged violations of the check stub reporting statute and $5.9 million for all other damages.

In the opinion of our outside counsel, Brown, Drew & Massey, LLP, the likelihood of the plaintiffs recovering $20.3 million for the check stub reporting statute is remote. However, a reserve that management believes is adequate to provide for the check stub reporting statute and all other damages has been established based on management’s estimate at this time of the probable outcome of this case.

Company’s consolidated financial statements.

West Virginia Royalty Litigation

In December 2001, the Company was sued by two royalty owners in West Virginia state court for an unspecified amount of damages. The plaintiffs have requested class certification under the West Virginia Rules of Civil Procedure and allege that the Company failed to pay royalty based upon the wholesale market value of the gas, produced, that it had taken improper deductions from the royalty and 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.

Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. A hearingThe Court entered an order on June 1, 2005 granting the plaintiffs’ motion for class certification was heldcertification. 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 October 20, 2003, and proposed findingsafter December 17, 1991. The Court has postponed the trial date from April 17, 2006, in light of fact and conclusionsa case pending before the West Virginia Supreme Court of Appeals which may decide issues of law were submittedthat may apply to the court on December 5, 2003. A status conference was held with the court and the court advised itissue of deductibility of post-production expenses. The Company intends to issue a ruling onchallenge the class certification motion. The court was expected to ruleorder by December 2004, and we are still awaitingfiling a decision. Discovery is proceeding onPetition for Writ of Prohibition with the claims pending the ruling on the class certification motion. Discovery is to be completed by April 1, 2005, and the trial is currently scheduled for August 15, 2005. If a class is certified it is expected this trial date will be continued to a later date.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. ItA reserve has a reservebeen established that management believes is adequate based on its estimate of the probable outcome of this case.

- 75 -


Texas Title Litigation

On January 6, 2003, the Company was served with Plaintiffs’ Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs filed their FirstSecond Supplemental Original Petition on March 17,November 12, 2004 and their SecondThird Supplemental Original Petition on November 12, 2004. The significant change in the second Supplemental Petition is that plaintiffs appear to limit their claim to the mineral estate, rather than making claims to both the surfaceFebruary 22, 2005 (which added Wynn-Crosby 1996, Ltd. and mineral estate. The plaintiffsDominion 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 minerals and all improvements on the lands on which the Company acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass, conversion, all for unspecified actual and exemplary damages. The original trial date of May 19, 2003 was cancelledPlaintiffs 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. Theclaim 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 $14.9 million. The$15.7 million, and that the carrying value of this property is approximately $34$33.6 million. Co-defendants Shell Oil Company and Shell Western E&P filed a motion for summary judgment seeking dismissal of plaintiffs’ causes of action on multiple grounds. The original plaintiffs’ attorneys asked permission from the Court to withdraw from the representation. The Court granted that request, and new attorneys for some, but not all of the plaintiffs have recently entered the case. The motion for summary judgment was reset and a hearing was held in December of 2003. The Company joined in the motion. After a second hearing, the Court denied the motion for summary judgment. The defendants have moved to add parties whose title interests are being challenged by the plaintiffs, and who are therefore necessary to the case, or in the alternative, abate the proceeding until the plaintiffs join all parties whose interests may be affected by plaintiffs’ claims.

Although the investigation into this claim is in its early stages,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 ensuredetermine 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, there has been no reserve established for this matter.

Raymondville Area

In April 2004, the Company’s wholly owned subsidiary, Cody Energy, LLC, filed suit in 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 to certainunder the terms of these co-working interest owners located within jointly owned oil and gas leases.the Joint Operating Agreement. Some of the co-working interest owners elected not to participate and some did not.participate. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.

In December 2003, certain of the co-workingThe working interest owners who elected not to participate in the initial well notified Cody that they believed that they had the right to participate in subsequent wells.wells drilled after the initial well. Cody contends that under the terms of the agreements between the parties, the co-workingworking interest owners that elected not to participate in the initial well in the prospect wereare required to assign their interest in the proposed prospect to those who elected to participate. Alternatively, Cody contends that such owners lost their right to participate in subsequent wells within a 1,200 foot radius of the initial well.

The defendants have filed a counter claim against the Company, and one of the defendants has filed a lien against Cody’s interest in the leases in the Raymondville Area. area.

Cody contends that this lien is improper and has sought damages for its filing. Cody is vigorously prosecuting this case which is in its early stage of discovery. No trial date has been set by the court.

- 76 -


Certainsigned 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 Partial Summary Judgment contending that they didReconsideration and Opposition to Proposed Order. The Court has not have adequate notice of the prospect proposal. Cody is contesting this Motion. In addition, in late December 2004, Cody filedyet made a Motion for Final Summary Judgment asking the court to find that, under the terms of the agreements, Cody and the participating working interest owners are entitled to an assignment of the interests of the co-working interest owners who elected not to participate in the prospect. No hearing date has been set by the court.decision on these two motions.

Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.

Commitment and Contingency Reserves

The Company has established reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur approximately $11.1$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, and cash flow, however, could be significantly impacted in the reporting periods in which such matters are resolved.

9.8. Cash Flow Information

Cash paid for interest and income taxes is as follows:

 

   Year Ended December 31,

(In thousands)


  2004

  2003

  2002

Interest

  $16,415  $18,298  $25,112

Income Taxes

   29,861   19,267   266

    Year Ended December 31,
(In thousands)  2005  2004  2003

Interest

  $17,366  $16,415  $18,298

Income Taxes

   47,142   29,861   19,267

The Company recorded benefits of $3.7 million, $2.6 million $1.0 million and $0.4$1.0 million for the years ended December 31, 2005, 2004 2003 and 2002,2003, respectively, for tax deductions taken due to employee stock option exercises and restricted stock grant vesting.

10.9. Capital Stock

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.

Incentive Plans

On April 29, 2004, the 2004 Incentive Plan was approved by the shareholders. Under the 2004 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2004 Incentive Plan consisting of stock options or stock awards, in addition to the automatic award of an option to purchase 10,00015,000 shares of Common Stockcommon stock on the date the non-employee directors first join the board of directors. A total of 1,700,0002,550,000 shares of Common Stockcommon stock may be issued under the 2004 Incentive Plan. In addition, shares remaining available for award under the 1994 Long-Term Incentive Plan and the Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (herein “Prior Plans”) were subsumed into the 2004 Incentive Plan (228,398(342,597 shares on April 29, 2004)post-split). Under the 2004 Incentive Plan, no more than 600,000900,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 1,000,0001,500,000 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.

- 77 -


During 2004,2005, the Board of Directors granted a series of 168,500110,200 performance share awards to certainthe executives and key employees of the Company. These awards are earned based on the comparative performance of the Company’s Common Stockcommon stock measured against sixteen other companies in the Company’s peer group over a three year vesting period ending on December 31, 2006.

April 30, 2008. Depending on the Company’s performance, employees may earn up to 100% of the award in Common Stock,common stock, and an additional 100% of the award in cash. The performance shares qualify for variable accounting, and accordingly, are recorded at their fair value with compensation expense recognized over the performance period.

During 2004,2005, the Company granted 7,00019,600 restricted stock units to various Company Directors.the non-employee Directors of the Company. These units immediately vest and will be paid out whenever the Director ceases to be a Director of the Company. For all restricted stock units, the Company recognized compensation expense equal to the market value of the Company’s Common Stockcommon stock on the grant date of the respective awards.

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

 

   December 31,

   2004

  2003

  2002

Shares Under Option at Beginning of Period

  1,349,501  1,287,829  1,081,621

Granted

  24,500  467,000  429,300

Exercised

  529,183  345,386  181,027

Surrendered or Expired

  33,129  59,942  42,065
   
  
  

Shares Under Option at End of Period

  811,689  1,349,501  1,287,829
   
  
  

Options Exercisable at End of Period

  377,329  511,719  570,406
   
  
  

    December 31,
    2005  2004  2003

Shares Under Option at Beginning of Period

  1,217,534  2,024,252  1,931,744

Granted

  —    36,750  700,500

Exercised

  300,493  793,775  518,079

Surrendered or Expired

  3,693  49,693  89,913
         

Shares Under Option at End of Period

  913,348  1,217,534  2,024,252
         

Options Exercisable at End of Period

  895,848  565,994  767,579
         

For each of the three most recent years, the price range for outstanding options was $17.44$11.63 to $34.98$23.32 per share. The following tables provide more information about the options by exercise price and year.

Options with exercise prices between $11.63 and $15.00 per share:

    December 31,
    2005  2004  2003

Options Outstanding

      

Number of Options

   225,575   344,945   667,002

Weighted Average Exercise Price

  $12.84  $12.85  $12.81

Weighted Average Contractual Term (in years)

   1.1   2.0   2.6

Options Exercisable

      

Number of Options

   225,575   183,737   306,344

Weighted Average Exercise Price

  $12.84  $12.86  $12.69

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

 

   December 31,

   2004

  2003

  2002

Options Outstanding

            

Number of Options

   229,963   444,668   737,385

Weighted Average Exercise Price

  $19.28  $19.22  $18.97

Weighted Average Contractual Term (in years)

   2.0   2.6   3.0

Options Exercisable

            

Number of Options

   122,491   204,229   301,277

Weighted Average Exercise Price

  $19.29  $19.04  $18.39

Options with exercise prices between $20.01 and $34.98 per share:

   December 31,

   2004

  2003

  2002

Options Outstanding

            

Number of Options

   581,726   904,833   550,444

Weighted Average Exercise Price

  $24.24  $24.69  $25.81

Weighted Average Contractual Term (in years)

   2.7   3.4   3.0

Options Exercisable

            

Number of Options

   254,838   307,490   269,129

Weighted Average Exercise Price

  $24.44  $26.42  $25.39

- 78 -


    December 31,
    2005  2004  2003

Options Outstanding

      

Number of Options

   687,773   872,589   1,357,250

Weighted Average Exercise Price

  $16.14  $16.16  $16.46

Weighted Average Contractual Term (in years)

   1.9   2.7   3.4

Options Exercisable

      

Number of Options

   670,273   382,257   461,235

Weighted Average Exercise Price

  $16.13  $16.29  $17.61

Dividend Restrictions

The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the Common Stockcommon stock depending on, among other things, the Company’s financial condition, funds from operations, the level of its capital and exploration expenditures, and its future business prospects. None of the note or credit agreements in place have a restricted payment provision.

Treasury Stock

In August 1998, the Board of Directors authorized the Company to repurchase up to two million shares of outstanding Common Stockcommon 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. During the year ended December 31, 2004,2005, the Company repurchased 405,100452,300 shares for a total cost of approximately $15.6$19.2 million. The repurchased shares are held as treasury stock. Since the authorization date, the Company has repurchased 707,7001,513,850 shares, or 35%50% of the total shares authorized for repurchase, for a total cost of approximately $20$39.2 million. In 2004,2005, the stock repurchase plan was funded from cash flow from operations. No treasury shares have been delivered or sold by the Company subsequent to the repurchase.

Purchase Rights

On January 21, 1991, the Board of Directors adopted the Preferred Stock Purchase Rights Plan and declared a dividend distribution of one right for each outstanding share of Common Stock.common stock. On December 8, 2000, the rights agreement for the plan was amended and restated to extend the term of the plan to 2010 and to make other changes. Each right becomes exercisable at a price of $55, when any person or group has acquired or made a tender or exchange offer for beneficial ownership of 15% or more of the Company’s outstanding Common Stock.common stock. Each right entitles the holder, other than the acquiring person or group, to purchase one one-hundredtha fraction of a share of Series A Junior Participating Preferred Stock (Junior Preferred Stock). After a person or group acquires beneficial ownership of 15% of the Common Stock,common stock, each right entitles the holder to purchase Common Stockcommon stock or other property having a market value (as defined in the plan) of twice the exercise price of the right. An exception to this triggering event applies in the case of a tender or exchange offer for all outstanding shares of Common Stockcommon stock determined to be fair and in the best interests of the Company and its stockholders by a majority of the independent directors. Under certain circumstances, the Board of Directors may opt to exchange one share of Common Stockcommon stock for each exercisable right. If there is a 15% holder and the Company is acquired in a merger or other business combination in which it is not the survivor, or 50% or more of the Company’s assets or earning power are sold or transferred, each right entitles the holder to purchase common stock of the acquiring company with a market value (as defined in the plan) equal to twice the exercise price of each right. At December 31, 20042005 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.

- 79 -


11.10. Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value. The Company uses available 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.

Long-Term Debt

 

   December 31, 2004

  December 31, 2003

(In thousands)


  Carrying
Amount


  Estimated
Fair Value


  Carrying
Amount


  Estimated
Fair Value


Debt

                

7.19% Notes

  $80,000  $87,770  $100,000  $113,673

7.26% Notes

   75,000   85,849   75,000   87,345

7.36% Notes

   75,000   87,111   75,000   87,770

7.46% Notes

   20,000   23,804   20,000   24,214

Credit Facility

   —     —     —     —  
   

  

  

  

   $250,000  $284,534  $270,000  $313,002
   

  

  

  

   December 31, 2005  December 31, 2004
(In thousands)  Carrying
Amount
  Estimated
Fair Value
  Carrying
Amount
  Estimated
Fair Value

Debt

        

7.19% Notes

  $60,000  $62,938  $80,000  $87,770

7.26% Notes

   75,000   81,713   75,000   85,849

7.36% Notes

   75,000   83,990   75,000   87,111

7.46% Notes

   20,000   23,083   20,000   23,804

Credit Facility

   90,000   90,000   —     —  
                
  $320,000  $341,724  $250,000  $284,534
                

The fair value of long-term debt is the estimated cost to acquire the debt, including a premium or discount for the difference between the issue rate and the year end market rate. The fair value of the 7.19% Notes, the 7.26% Notes, the 7.36% Notes and the 7.46% Notes is based on interest rates currently available to the Company. The Credit Facilitycredit facility approximates fair value because this instrument bears interest at rates based on current market rates.

Derivative Instruments and Hedging Activity

The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. Under the Company’s revolving credit agreement, the aggregate level of commodity hedging must not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. At December 31, 2004,2005, the Company had 15nine cash flow hedges open: 7eight natural gas price collar arrangements and one crude oil collar arrangement and 7 natural gas price swap arrangements. Additionally, the Company had two crude oil financial instruments open at December 31, 2004, that did not qualify for hedge accounting under SFAS 133.arrangement. At December 31, 2004,2005, a $28.8$20.7 million ($17.812.9 million net of tax) unrealized loss was recorded to Accumulated Other Comprehensive Income, along with a $38.4$22.4 million short-term derivative liability and a $2.9$1.7 million short-term derivative receivable.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 changeschange in fair value of all other derivatives is recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate revenue,Revenue, as appropriate.

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

   Year Ended December 31,

 
   2004

  2003

  2002

 

(In thousands)


  Realized

  Unrealized

  Realized

  Unrealized

  Realized

  Unrealized

 

Operating Revenues -Increase / (Decrease) to Revenue

                         

Natural Gas Production

  $(55,008) $914  $(48,829) $(1,468) $(574) $(1,683)

Crude Oil

   (17,908)  (2,917)  (3,963)  (1,879)  (5,202)  (693)

Assuming no change in commodity prices, after December 31, 20042005 the Company would expect to reclassify to earnings,the Statement of Operations, over the next 12 months, $17.8$12.9 million in after-tax expenditurescharges associated with commodity derivatives.hedges. This reclassification represents the net liability associated with open positions currently not reflected in earnings at December 31, 20042005 related to anticipated 20052006 production.

- 80 -


Hedges on Production - Swaps

From time to time, the Company enters into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of its production. These 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 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. During 2004,2005, natural gas price swaps covered 29,61720,557 Mmcf, or 41%28% of the Company’s gas production, fixing the sales price of this gas at an average of $5.04$5.14 per Mcf.

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

   Natural Gas Price Swaps

 

Contract Period


  Volume
in
Mmcf


  Weighted
Average
Contract Price


  Unrealized
Gain /(Loss)
(In thousands)


 

As of December 31, 2004

            

Natural Gas Price Swaps on Production in:

            

First Quarter 2005

  5,069  $5.14     

Second Quarter 2005

  5,125   5.14     

Third Quarter 2005

  5,181   5.14     

Fourth Quarter 2005

  5,181   5.14     
   
  

  


Full Year 2005

  20,556  $5.14  $(27,897)

2006 production.

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, 2004,2005, the Company had two open crude oil swap arrangements with an unrealized net lossdid not have any of $5.5 million recognized in Operating Revenues.these types of arrangements.

- 81 -


Hedges on Production - Options

From time to time, the Company enters into natural gas and crude oil collar agreements with counterparties to hedge price risk associated with a portion of its production. These cash flow hedges are not held for trading purposes. Under the collar arrangements, if the index price rises above the ceiling price, the Company pays the counterparty. If the index price falls below

the floor price, the counterparty pays the Company. During 2004,2005, natural gas price collars covered 22,95415,157 Mmcf of the Company’s gas production, or 32%21% of the Company’s gas production with a weighted average floor of $4.78$5.59 per Mcf and a weighted average ceiling of $6.06$8.61 per Mcf.

During 2005, an oil price collar covered 365 Mbbl of the Company’s crude oil production, or 21% of 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, 2004,2005, the Company had open natural gas price collar contracts covering its 20052006 production as follows:

 

   Natural Gas Price Collars

 

Contract Period


  Volume
in
Mmcf


  Weighted
Average
Ceiling /Floor


  Unrealized
Gain / (Loss)
(In thousands)


 

As of December 31, 2004

            

First Quarter 2005

  4,982  $9.09 /$6.16     

Second Quarter 2005

  3,367   8.38 /  5.30     

Third Quarter 2005

  3,404   8.38 /  5.30     

Fourth Quarter 2005

  3,404   8.38 /  5.30     
   
  

  


Full Year 2005

  15,157  $8.61 /$5.59  $(2,500)

    Natural Gas Price Collars 

Contract Period

  Volume
in
Mmcf
  

Weighted
Average

Ceiling / Floor

  

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)
            

At December 31, 2004, we2005, the Company had one open crude oil price collar contract covering our 2005its 2006 production as follows:

 

   Crude Oil Price Collar

Contract Period


  Volume
in
Mbbl


  Weighted
Average
Ceiling /Floor


  Unrealized
Gain /(Loss)
(In thousands)


As of December 31, 2004

           

First Quarter 2005

  90  $50.50 /$40.00    

Second Quarter 2005

  91   50.50 /  40.00    

Third Quarter 2005

  92   50.50 /  40.00    

Fourth Quarter 2005

  92   50.50 /  40.00    
   
  

  

Full Year 2005

  365  $50.50 /$40.00  $454

    Crude Oil Price 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)
            

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

Credit Risk

Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.

In each of 2005, 2004 and 2003, approximately 11% of the Company’s total sales were made to one customer. In 2003 and 2002, approximately 11% and 14%, respectively, of our total sales were made to one customer. In 2002, this customer operated certain properties in which we have interests in the Gulf Coast and purchased all of the production from these wells. This customer would resell the natural gas and oil to third parties with whom we would deal directly if the customer either ceased to exist or stopped buying our portion of the production.

- 82 -


12.11. 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, 20042005 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 bewas no impact on the Company’s cash flows as a result of adopting SFAS No. 143.

Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense for the yearyears ended December 31, 2005, 2004 was $1.7 million. Accretion expense for the year ended December 31,and 2003 was $1.4 million, $1.7 million and $2.1 million.

million, respectively.

The following table reflects the changes of the asset retirement obligations during the current period.

 

(In thousands)

 

    

Carrying amount of asset retirement obligations at December 31, 2003

  $36,848 

Liabilities added during the current period

   2,316 

Liabilities settled during the current period

   (520)

Current period accretion expense

   1,731 

Revisions to estimated cash flows

   —   
   


Carrying amount of asset retirement obligations at December 31, 2004

  $40,375 
   


If SFAS 143 had been adopted on January 1, 2002, pro forma net income would have been approximately $15.1 million, pro forma basic earnings per share would have been $0.48 and pro forma diluted earnings per share would have been $0.47. These pro forma figures are unaudited.

(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 
     

13. Section 29 Tax Credits

Other revenue includes income generated from the monetization of the value of Section 29 tax credits (monetized credits) from most of the Company’s qualifying East and Rocky Mountains properties. The tax credit wells were repurchased in December 2002 and no tax credits were generated in 2003 or 2004 as the credits expired in 2002. Revenue from these monetized credits was $2.0 million in 2002. The production, revenues, expenses and proved reserves for these properties was reported by the Company as Other Revenue until the credits were repurchased in December 2002. In this repurchase transaction, the Company acquired 26 Bcfe for $7 million, or $0.27 per Mcfe. The effective date of the repurchase was December 31, 2002.

- 83 -


14.12. Earnings per Common Share

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, 2005, 2004 2003 and 2002:2003:

 

  December 31,

  December 31,
  2004

  2003

  2002

  2005  2004  2003

Shares - basic

  32,488,336  32,049,664  31,736,975  48,856,491  48,732,504  48,074,496

Dilution effect of stock options and awards at end of period

  404,198  240,621  338,972  868,904  606,297  360,932
  
  
  
         

Shares - diluted

  32,892,534  32,290,285  32,075,947  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  —    —    1,448,666
  
  
  
         

15. Subsequent Event-Stock Split

On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split on the Company’s Common Stock in the form of a stock distribution. The stock dividend will be distributed on March 31, 2005 to shareholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company will pay cash based on the closing price of the Common stock on the record date. The pro forma effect on the December 31, 2004 balance sheet is to reduce Additional Paid-in-Capital by $1.6 million and increase Common Stock by $1.6 million. Common shares outstanding, giving retroactive effect to the stock split at December 31, 2004 and 2003 would have been 48.6 million and 48.4 million, respectively. Pro forma earnings per share, giving retrospective effect to the stock split is as follows:

   December 31,

   2004

  2003

  2002

Basic Earnings per Share – as reported (pre-stock split)

  $2.72  $0.66  $0.51

Basic Earnings per Share – pro forma (post-stock split)

   1.81   0.44   0.34

Diluted Earnings per Share – as reported (pre-stock split)

   2.69   0.65   0.50

Diluted Earnings per Share – pro forma (post-stock split)

   1.79   0.43   0.33

- 84 -


CABOT OIL & GAS CORPORATION

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made.

Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

Estimates of proved and proved developed reserves at December 31, 2005, 2004, 2003, and 20022003 were based on studies performed by the Company’s petroleum engineering staff. The estimates were computed based on year end prices for oil, natural gas, and natural gas liquids. The estimates were reviewed by Miller and Lents, Ltd., who indicated in their letter dated February 7, 2005,3, 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, 2004,2005, 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)


  2004

 2003

 2002

   2005 2004 2003 

Proved Reserves

       

Beginning of Year

  1,069,484  1,060,959  1,036,004   1,134,081  1,069,484  1,060,959 

Revisions of Prior Estimates

  (7,850) (6,122) 14,405   (1,543) (7,850) (6,122)

Extensions, Discoveries and Other Additions

  140,986  105,497  64,945   185,884  140,986  105,497 

Production

  (72,833) (71,906) (73,670)  (73,879) (72,833) (71,906)

Purchases of Reserves in Place

  5,384  1,590  26,262   17,567  5,384  1,590 

Sales of Reserves in Place

  (1,090) (20,534) (6,987)  (14) (1,090) (20,534)
  

 

 

          

End of Year

  1,134,081  1,069,484  1,060,959   1,262,096  1,134,081  1,069,484 
  

 

 

          

Proved Developed Reserves

  857,834  812,280  819,412   944,897  857,834  812,280 
  

 

 

          

Percentage of Reserves Developed

  75.6% 76.0% 77.2%  74.9% 75.6% 76.0%
  

 

 

          

- 85 -


   Liquids

 
   December 31,

 

(Thousands of barrels)


  2004

  2003

  2002

 

Proved Reserves

          

Beginning of Year

  12,103  18,393  19,684 

Revisions of Prior Estimates

  185  307  1,871 

Extensions, Discoveries and Other Additions

  1,074  1,723  851 

Production

  (2,002) (2,846) (2,909)

Purchases of Reserves in Place

  24  —    261 

Sales of Reserves in Place

  —    (5,474) (1,365)
   

 

 

End of Year

  11,384  12,103  18,393 
   

 

 

Proved Developed Reserves

  8,652  9,405  13,267 
   

 

 

Percentage of Reserves Developed

  76.0% 77.7% 72.1%
   

 

 

   Liquids 
   December 31, 
(Thousands of barrels)  2005  2004  2003 
Proved Reserves    

Beginning of Year

  11,384  12,103  18,393 

Revisions of Prior Estimates

  1,073  185  307 

Extensions, Discoveries and Other Additions

  334  1,074  1,723 

Production

  (1,747) (2,002) (2,846)

Purchases of Reserves in Place

  419  24  —   

Sales of Reserves in Place

  —    —    (5,474)
          

End of Year

  11,463  11,384  12,103 
          

Proved Developed Reserves

  9,127  8,652  9,405 
          

Percentage of Reserves Developed

  79.6% 76.0% 77.7%
          

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization.

 

   December 31,

(In thousands)


  2004

  2003

  2002

Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities

  $1,933,848  $1,732,236  $1,704,746

Aggregate Accumulated Depreciation, Depletion and Amortization

   940,447   837,060   750,857

   December 31,
(In thousands)  2005  2004  2003

Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities

  $2,290,147  $1,933,848  $1,732,236

Aggregate Accumulated Depreciation, Depletion and Amortization

   1,052,654   940,447   837,060

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)


  2004

  2003

  2002

  2005  2004  2003

Property Acquisition Costs, Proved

  $3,953  $1,524  $8,799  $73,127  $3,953  $1,524

Property Acquisition Costs, Unproved

   18,250   14,056   4,869   22,126   18,250   14,056

Exploration and Extension Well Costs(1)

   85,415   83,147   52,012   102,957   85,415   83,147

Development Costs

   136,311   77,006   55,165   208,124   136,311   77,006
  

  

  

         

Total Costs

  $243,929  $175,733  $120,845  $406,334  $243,929  $175,733
  

  

  

         

(1)Includes administrative exploration costs of $12,423, $11,354 $10,582, and $8,942$10,582 for the years ended December 31, 2004, 2003, and 2002, respectively.2005,

- 86 -


Historical Results of Operations from Oil and Gas Producing Activities

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

 

  Year Ended December 31,

  Year Ended December 31,

(In thousands)


  2004

  2003

  2002

  2005  2004  2003

Operating Revenues

  $439,988  $404,503  $280,379  $581,849  $439,988  $404,503

Costs and Expenses

               

Production

   84,015   77,315   63,823   103,477   84,015   77,315

Other Operating

   27,787   20,090   21,731   30,120   27,787   20,090

Exploration(1)

   48,130   58,119   40,167   61,840   48,130   58,119

Depreciation, Depletion and Amortization

   114,906   195,659   102,086   119,122   114,906   195,659
  

  

  

         

Total Costs and Expenses

   274,838   351,183   227,807   314,559   274,838   351,183
  

  

  

         

Income Before Income Taxes

   165,150   53,320   52,572   267,290   165,150   53,320

Provision for Income Taxes

   60,361   18,662   18,400   100,353   60,361   18,662
  

  

  

         

Results of Operations

  $104,789  $34,658  $34,172  $166,937  $104,789  $34,658
  

  

  

         

(1)Includes administrative exploration costs of $12,423, $11,354 $10,582, and $8,942$10,582 for the years ended December 31, 2005, 2004, 2003, and 2002,2003, respectively.

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

The following information has been developed utilizing SFAS No. 69,“Disclosures about Oil and Gas Producing Activities”, procedures and based on natural gas and crude oil reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

 

Future costs and selling prices will probably differ from those required to be used in these calculations.

 

Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations.

 

Selection of a 10% discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues.

 

Future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows were estimated by applying year end oil and gas prices to the estimated future production of year end proved reserves.

The average prices related to proved reserves at December 31, 2005, 2004, 2003, and 20022003 for natural gas ($ per Mcf) were $9.53, $6.26 $5.96, and $4.41,$5.96, respectively, and for oil ($ per Bbl) were $58.48, $41.24 $30.94, and $30.39,$30.94, respectively. Future cash inflows were reduced by estimated future development and production costs based on year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved. SFAS No. 69 requires the use of a 10% discount rate.

Management does not use only the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.

- 87 -


Standardized Measure is as follows:

 

   Year Ended December 31,

 

(In thousands)


  2004

  2003

  2002

 

Future Cash Inflows

  $7,561,728  $6,742,214  $5,236,349 

Future Production Costs

   (1,577,787)  (1,390,398)  (1,137,615)

Future Development Costs

   (396,431)  (310,923)  (284,165)

Future Income Tax Expenses

   (2,009,644)  (1,800,519)  (1,195,082)
   


 


 


Future Net Cash Flows

   3,577,866   3,240,374   2,619,487 

10% Annual Discount for Estimated Timing of Cash Flows

   (1,997,509)  (1,760,966)  (1,364,134)
   


 


 


Standardized Measure of Discounted Future Net Cash Flows

  $1,580,357  $1,479,408  $1,255,353 
   


 


 


   Year Ended December 31, 
(In thousands)  2005  2004  2003 

Future Cash Inflows

  $12,700,390  $7,561,728  $6,742,214 

Future Production Costs

   (2,271,917)  (1,577,787)  (1,390,398)

Future Development Costs

   (536,333)  (396,431)  (310,923)

Future Income Tax Expenses

   (3,588,877)  (2,009,644)  (1,800,519)
             

Future Net Cash Flows

   6,303,263   3,577,866   3,240,374 

10% Annual Discount for Estimated Timing of Cash Flows

   (3,652,030)  (1,997,509)  (1,760,966)
             

Standardized Measure of Discounted Future Net Cash Flows(1)

  $2,651,233  $1,580,357  $1,479,408 
             

(1)The standardized measures of discounted future net cash flows before taxes were $4,001,769, $2,358,430 and $2,196,038 for the years ended December 31, 2005, 2004 and 2003, respectively.

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

The following is an analysis of the changes in the Standardized Measure:

 

  Year Ended December 31,

   Year Ended December 31, 

(In thousands)


  2004

 2003

 2002

   2005 2004 2003 

Beginning of Year

  $1,479,408  $1,255,353  $766,026   $1,580,357  $1,479,408  $1,255,353 

Discoveries and Extensions,

   

Net of Related Future Costs

   321,026   235,079   112,269 

Discoveries and Extensions, Net of Related Future Costs

   494,773   321,026   235,079 

Net Changes in Prices and Production Costs

   (17,976)  475,026   703,874    1,278,303   (17,976)  475,026 

Accretion of Discount

   219,604   171,590   95,110    235,843   219,604   171,590 

Revisions of Previous Quantity

Estimates, Timing and Other

   (46,115)  (35,691)  51,944    (49,550)  (46,115)  (35,691)

Development Costs Incurred

   32,940   27,529   20,516    61,802   32,940   27,529 

Sales and Transfers, Net of Production Costs

   (357,939)  (330,800)  (216,555)   (471,638)  (357,939)  (330,800)

Net Purchases (Sales) of Reserves in Place

   10,853   (62,596)  (2,357)   91,180   10,853   (62,596)

Net Change in Income Taxes

   (61,444)  (256,082)  (275,474)   (569,837)  (61,444)  (256,082)
  


 


 


          

End of Year

  $1,580,357  $1,479,408  $1,255,353   $2,651,233  $1,580,357  $1,479,408 
  


 


 


          

- 88 -


CABOT OIL & GAS CORPORATION

SELECTED DATA (UNAUDITED)

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

 

(In thousands, except per share amounts)


  First

  Second

  Third

  Fourth

  Total

2004

                    

Operating Revenues

  $136,604  $119,742  $119,423  $154,639  $530,408

Impairment of Oil and Gas Properties

   —     —     3,458   —     3,458

Operating Income

   36,090   36,439   34,278   53,846   160,653

Income Before Cumulative Effect of Accounting Change

   19,011   19,318   17,822   32,227   88,378

Net Income

   19,011   19,318   17,822   32,227   88,378

Basic Earnings per Share

-Before Accounting Change

  $0.59  $0.59  $0.55  $0.99  $2.72

Diluted Earnings per Share

-Before Accounting Change

  $0.58  $0.59  $0.54  $0.98  $2.69

Basic Earnings per Share

  $0.59  $0.59  $0.55  $0.99  $2.72

Diluted Earnings per Share

  $0.58  $0.59  $0.54  $0.98  $2.69

2003

                    

Operating Revenues

  $135,916  $126,756  $125,471  $121,248  $509,391

Impairment of Oil and Gas Properties

   87,926   —     5,870   —     93,796

Operating Income (Loss)

   (46,691)  34,850   43,630   34,798   66,587

Income (Loss) Before Cumulative Effect of Accounting Change

   (32,376)  17,904   23,220   19,231   27,979

Net Income (Loss)(1)

   (39,223)  17,904   23,220   19,231   21,132

Basic Earnings (Loss) per Share

-Before Accounting Change(1)

  $(1.02) $0.56  $0.73  $0.60  $0.87

Diluted Earnings (Loss) per Share

-Before Accounting Change(1)

  $(1.02) $0.55  $0.73  $0.60  $0.87

Basic Earnings (Loss) per Share(1)

  $(1.23) $0.56  $0.73  $0.60  $0.66

Diluted Earnings (Loss) per Share(1)

  $(1.23) $0.55  $0.73  $0.60  $0.65
(In thousands, except per share amounts)  First  Second  Third  Fourth  Total

2005

          

Operating Revenues

  $144,074  $151,884  $161,757  $225,082  $682,797

Impairment of Oil and Gas Properties (1)

   —     —     —     —     —  

Operating Income

   38,044   61,722   59,023   99,942   258,731

Net Income

   20,762   35,422   33,756   58,505   148,445

Basic Earnings per Share (2)

   0.43   0.72   0.69   1.20   3.04

Diluted Earnings per Share (2)

   0.42   0.71   0.68   1.18   2.99

2004

          

Operating Revenues

  $136,604  $119,742  $119,423  $154,639  $530,408

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)

   0.39   0.40   0.37   0.66   1.81

Diluted Earnings per Share (2)

   0.39   0.39   0.36   0.65   1.79

(1)Net income reported in Form 10-Q asFor discussion of September 30, 2003 has been revisedimpairment of oil and gas properties, refer to reflect the reversalNote 2 of the adoption of SFAS 150. This reversal resulted in an increase of $0.6 million or $0.02Notes to the Consolidated Financial Statements.
(2)All Earnings per common and diluted shareShare figures have been retroactively adjusted for the three months then ended.3-for-2 split of the Company’s Common Stock effective March 31, 2005.

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

None.

- 89 -


ITEM 9A. CONTROLS AND PROCEDURES

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

As of the end of December 31, 2004,2005, 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.

There were no significant changes in the Company’s internal control over financial reporting that occurred during the fourth quarter that has materially affected, or is reasonably likely to materially effect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

The management of Cabot Oil & Gas Corporation is responsible for establishing and maintaining adequate internal control over financial reporting. Cabot Oil & Gas Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Cabot Oil & Gas Corporation’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004.2005. 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, 2004,2005, the Company’s internal control over financial reporting is effective based on those criteria.

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, 20042005 as stated in their report entitled “Report of Independent Registered Public Accounting Firm” which appears herein. This report appears on page 50.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information under the captioncaptions “Election of Directors”, “Audit Committee” and “Code of Business Conduct” in the Company’s definitive Proxy Statement in connection with the 20052006 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.

- 90 -reference in response to this item.


ITEM 11. EXECUTIVE COMPENSATION

The information under the caption “Executive Compensation” in the Company’s definitive Proxy Statement in connection with the 20052006 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 20052006 annual stockholders’ meeting isare incorporated by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information under the caption “Fees Billed by Independent Registered Public Accounting FirmAccountants for Services in 20032005 and 2002”2004” in the Company’s definitive Proxy Statement in connection with the 20052006 annual stockholders’ meeting is incorporated by reference.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

A. INDEX

1.1. Consolidated Financial Statements

See Index on page 49.53.

2.2. Financial Statement Schedules

None.

- 91 -


3. Exhibits

The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.

 

Exhibit
Number

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).

4.74.6  Note Purchase Agreement dated November 14, 1997, among the Company and the purchasers named therein (Form 10-K for 1997).
4.84.7  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).
4.94.8  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).
  

(a)

Amendment No. 1 to Credit Agreement dated December 10, 2004.

10.1Supplemental Executive Retirement Agreement between the Company and Charles P. Siess, Jr.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).
10.3Letter 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).
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).

10.6Form of Stock Subscription Agreement between the Company and certain executive officers and directors of the Company (Registration Statement No. 33-32553).
10.7Transaction Agreement between Cabot Corporation and the Company dated February 1, 1991 (Registration Statement No. 33-37455).
10.8Tax Sharing Agreement between Cabot Corporation and the Company dated February 1, 1991 (Registration Statement No. 33-37455).
10.9Amendment 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).

- 92 -


Exhibit
Number

Number


    

Description


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).
10.12Settlement 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).
10.13Agreement 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).
10.17Employment 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).
10.2010.11    Trust Agreement dated September 2000 between Harris Trust and Savings Bank and the Company (Form 10-K for 2001).
10.2110.12    Lease Agreement between the Company and DNA COG, Ltd. dated April 24, 1998 (Form 10-K for 1998).
10.2210.13    Credit Agreement dated as of December 17, 1998, between the Company and the banks named therein (Form 10-K for 1998).
10.23Letter Agreement with Puget Sound Energy Company dated September 21, 1999 (Form 10-K for 1999).
10.24Agreement 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).
10.26*10.15    2004 Incentive Plan (Form 10-Q for the quarter ended June 30, 2004).
10.27*10.16    2004 Performance Award Agreement (Form 10-Q for the quarter ended June 30, 2004).
10.28*10.17    2004 Annual Target Cash Incentive Plan Measurement Criteria for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005).
10.29*10.18    Form of Restricted Stock Awards Terms and Conditions for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005).
*10.192005 Form of Non-Employee Director Restricted Stock Unit Award Agreement (Form 8-K for May 24, 2005).
*10.20Savings Investment Plan of the Company, as amended and restated effective January 1, 2001 (Form 10-K for 2005).
(a)First Amendment to the Savings Investment Plan effective January 1, 2002 (Form 10-K for 2005).
(b)Second Amendment to the Savings Investment Plan effective January 1, 2003 (Form 10-K for 2005).
(c)Third Amendment to the Savings Investment Plan effective January 1, 2005 (Form 10-K for 2005).
14.1Amendment 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.
23.2    Consent of Miller and Lents, Ltd.
23.3  Consent of Brown, Drew & Massey, LLP.
31.1    302 Certification – Chairman, President and Chief Executive Officer.

Exhibit
Number

Description

31.2  302 Certification – Vice President and Chief Financial Officer.
32.1  906 Certification.
99.1  Miller and Lents, Ltd. Review Letter.


*Compensatory plan, contract or arrangement.

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SIGNATURES

Pursuant to the requirements of Section 13 and 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 2nd6th of March 2005.2006.

 

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.

 

Signature


  

Title


  

Date


/s/ Dan O. Dinges


Dan O. Dinges

  

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

  March 2, 20056, 2006

/s/ Scott C. Schroeder


Scott C. Schroeder

  

Vice President and Chief Financial Officer (Principal

(Principal Financial Officer)

  March 2, 20056, 2006

/s/ Henry C. Smyth


Henry C. Smyth

  

Vice President, Controller and Treasurer (Principal

(Principal Accounting Officer)

  March 2, 20056, 2006

/s/ Robert F. Bailey


Robert F. Bailey

  Director  March 2, 20056, 2006

/s/ John G. L. Cabot


John G. L. Cabot

  Director  March 2, 20056, 2006

/s/ David M. Carmichael

David M. Carmichael

DirectorMarch6, 2006

/s/ James G. Floyd


James G. Floyd

  Director  March 2, 20056, 2006

/s/ Robert L. Keiser

Robert L. Keiser

DirectorMarch6, 2006

/s/ Robert Kelley


Robert Kelley

  Director  March 2, 20056, 2006

/s/ C. Wayne Nance


C. Wayne Nance

  Director  March 2, 20056, 2006

/s/ P. Dexter Peacock


P. Dexter Peacock

  Director  March 2, 20056, 2006

/s/ William P. Vititoe


William P. Vititoe

  Director  March 2, 20056, 2006

 

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