Use these links to rapidly review the documentCONTENTS INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

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SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

Form 10-K/A

|ý                                                             | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934    
|------------------------------------------------------------- | ----------------------------------------------------------------------------------------
|For the Fiscal Year Ended December 31, 2002                  
|or                                                           
|o                                                             | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|For the Transition Period
from                             to

Commission File Number 001-31308

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Tom Brown, Inc.(Exact name of registrant as specified in its charter)

|Delaware(State or other jurisdiction
of incorporation or organization)                                                                                |  | 95-1949781(I.R.S. Employer Identification No.)
|----------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------------------------------
|555 Seventeenth Street
Suite 1850
Denver, Colorado(Address of principal executive offices)                                                            |  | 80202(Zip Code)                               
|303-260-5000(Registrant's telephone number, including area code)                                                                                     
|Securities Registered Pursuant to Section 12(b) of the Act:None                                                                                      
|Securities Registered Pursuant to Section 12(g) of the Act: Common Stock, $.10 par Value
Convertible Preferred Stock, $.10 par Value
(Title of Class)

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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes ý    No o

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. o

Indicate
by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).
Yes ý    No o

The
aggregate market value of the Registrant's Common Stock held by non-affiliates was approximately $944,162,050 as of June 28, 2002 (based on the last reported sale
price of such stock on the New York Stock Exchange Composite Tape on that day).

As
of March 11, 2003, there were 39,398,903 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant's definitive proxy statement for the 2003 Annual Meeting of Stockholders to be held on May 8, 2003 are incorporated by reference
into Part III.

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TOM BROWN, INC.

FORM 10-K

CONTENTS



|           |  |                                                                                       |  | Page
|---------- |  | ------------------------------------------------------------------------------------- |  | ----
|PART I    
|Item 1.    |  | Business                                                                              |  | 3   
|Item 2.    |  | Properties                                                                            |  | 23  
|Item 3.    |  | Legal Proceedings                                                                     |  | 27  
|Item 4.    |  | Submission of Matters to a Vote of Security Holders                                   |  | 27  
|Item 4A.   |  | Executive Officers of the Registrant                                                  |  | 27  
|PART II   
|Item 5.    |  | Market for Registrant's Common Equity and Related Stockholder Matters                 |  | 29  
|Item 6.    |  | Selected Financial Data                                                               |  | 30  
|Item 7.    |  | Management's Discussion and Analysis of Financial Condition and Results of Operations |  | 32  
|Item 7A.   |  | Quantitative and Qualitative Disclosures About Market Risk                            |  | 42  
|Item 8.    |  | Financial Statements and Supplementary Data                                           |  | 44  
|Item 9.    |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure  |  | 87  
|PART III  
|Item 10.   |  | Directors and Executive Officers of the Registrant                                    |  | 87  
|Item 11.   |  | Executive Compensation                                                                |  | 87  
|Item 12.   |  | Security Ownership of Certain Beneficial Owners and Management                        |  | 87  
|Item 13.   |  | Certain Relationships and Related Transactions                                        |  | 88  
|Item 14.   |  | Controls and Procedures                                                               |  | 88  
|PART IV   
|Item 15.   |  | Exhibits, Consolidated Financial Statement Schedules and Reports on Form 8-K          |  | 89  
|Signatures |  | 93                                                                                   





EXPLANATORY NOTE

Tom Brown, Inc. (the "Company") is filing this amendment in response to comments received from the Securities and Exchange Commission regarding the Company's
Annual Report on Form 10-K/A for the fiscal year ended December 31, 2002 that was originally filed on March 25, 2003. This report significantly revises the disclosures
pertaining to the Company's business, the Company's properties, the Company's legal proceedings, management's discussion and analysis of financial condition and results of operations, and the
Company's financial statements. This report continues to speak as of the date of the original filing, and the Company has not updated the disclosure in this report to speak as of a later date. All
information contained in this report and the original filing is subject to updating and supplementing as provided in the Company's periodic reports filed with the Securities and Exchange Commission.

PART I

ITEM 1.Business



Tom Brown, Inc. (the "Company") was organized in 1955 as a privately-owned drilling company known as Scarber-Brown Drilling Company and in 1959 as Tom
Brown Drilling Company, Inc. In 1968, the Company merged into Gold Metals Consolidated Mining Company, a publicly-traded Nevada corporation. The name of the Company after the merger was changed
to Tom Brown Drilling Company, Inc. and to Tom Brown, Inc. in 1971. In February 1987, the Company changed its state of incorporation from Nevada to Delaware. In 1999, the Company
relocated its headquarters and
executive offices to 555 Seventeenth Street, Suite 1850, Denver, Colorado 80202 and its telephone number at that address is (303) 260-5000. Unless the context otherwise
requires, all references to the "Company" include Tom Brown, Inc. and its subsidiaries.

The
Company is engaged primarily in the exploration for, and the acquisition, development, production, marketing and sale of, natural gas, natural gas liquids and crude oil in North
America. The Company's activities are conducted principally in the Wind River and Green River Basins of Wyoming, the Piceance Basin of Colorado, the Paradox Basin of Utah and Colorado, the Val Verde
Basin and Permian Basin of west Texas and southeastern New Mexico, the east Texas Basin and the western Canadian Sedimentary Basin. The Company also, to a lesser extent, conducts exploration and
development activities in other areas of the continental United States and Canada.

In
December 2000, the Company initiated a cash tender for all the outstanding stock of Stellarton Energy Corporation ("Stellarton"). This transaction was completed on
January 12, 2001.

The
Company's industry segments are (i) the exploration for, and the acquisition, development and production of, natural gas, natural gas liquids and crude oil, (ii) the
marketing, gathering, processing and sale of natural gas and (iii) the drilling of gas and oil wells.

Except
for its gas and oil leases with governmental entities and other third parties who enter into gas and oil leases or assignments with the Company in the regular course of its
business and options to purchase gas and oil leases with the Eastern Shoshone and Northern Arapaho Tribes, the Company has no material patents, licenses, franchises or concessions that it considers
significant to its gas and oil operations.

The
nature of the Company's business is such that it does not maintain or require a substantial amount of products, customer orders or inventory. The Company's gas and oil operations are
not subject to renegotiations of profits or termination of contracts at the election of the federal government.

The
Company has not been a party to any bankruptcy, receivership, reorganization or similar proceeding, except in connection with its participation as a joint proponent of a plan of
reorganization for Presidio Oil Company in 1996.



The Company's business strategy is to increase stockholder value through the discovery, acquisition and development of long-lived gas and oil reserves
in areas where the Company has industry knowledge and operations expertise. The Company's principal investments have been in natural gas prone basins, which the Company believes will continue to
provide the opportunity to accumulate significant long-lived gas and oil reserves at attractive prices. The expansion into Canada in 2001 was an extension of this fundamental strategy.

The
Company's year-end domestic acreage position was approximately 2,677,000 gross (1,773,000 net) acres (including options) located primarily in the Wind River and Green
River Basins of Wyoming, the Piceance Basin of Colorado, the Paradox Basin of Colorado and Utah, and the Permian, Val Verde and east Texas Basins of Texas where the Company can utilize its geological
and technical expertise and its control of operations for the further development and expansion of these areas. Approximately 89% of the net acreage is undeveloped.

The
Company's year-end Canadian acreage position located in western Alberta was approximately 540,000 gross (359,000 net) acres. Approximately 78% of the net acreage is
undeveloped.

Additionally,
by staying focused in its core basins, the Company continues to develop more effective drilling and completion techniques which can improve overall economic efficiency.

The
Company increased its reserves in 2002 over 2001 by 2% due primarily to continued drilling success in its core areas. Year-end proved reserves were 750 billion
cubic feet equivalent ("Bcfe"), compared to year-end 2001 reserves of 732 Bcfe. At December 31, 2002, the Canadian reserve base was 82 Bcfe compared to 77 Bcfe at
December 31, 2001. Since December 31, 1995, the Company has increased proved reserves at a compounded annual growth rate of 22%, or from 188 Bcfe to 750 Bcfe.

Reserve
replacement for 2002 was 137% from all sources and 119% from extensions, discoveries and revisions only. The Company's reserve to production ratio was 8.8 years at
year-end 2002 compared to 9.6 years at year-end 2001. In addition to increasing reserves, the Company also increased its production 12% from 76.4 Bcfe in 2001 to 85.5
Bcfe in 2002.

The
Company markets a majority of its operated gas production and some third party gas in the Rocky Mountains through Retex, Inc. ("Retex"), the Company's wholly-owned marketing
subsidiary.

The
Company also conducts gas gathering and processing activities in the Rocky Mountain area. Initially, these functions were conducted through Wildhorse Energy Partners, LLC
("Wildhorse") which was owned 55% by Kinder Morgan, Inc. ("KM") and 45% by the Company. In November 2000, the Wildhorse gathering and processing assets were distributed to the Company in
anticipation of the dissolution of Wildhorse. KM received the Wildhorse storage facility and a cash payment of $14.7 million. TBI Field Services, Inc. ("TBIFS") was formed as a
wholly-owned subsidiary of Tom Brown, Inc. to administer these gathering and processing assets. In 2001, TBIFS selectively sold many of the gathering and processing facilities received in the
Wildhorse asset distribution, retaining only those gathering systems considered integral to the Company's gas and oil reserve base. As the Company directly owns and operates several gas processing and
gathering systems adjacent to its areas of operations, the systems ultimately retained by TBIFS after the Wildhorse dissolution were merged into the Company's operations in 2002 and TBIFS ceased to
function as a separate entity.

The
Company plans to continue to selectively pursue acquisitions of gas and oil properties in its core areas of activity and, in connection therewith, the Company from time to time will
be involved in


evaluations of, or discussions with, potential acquisition candidates. The consideration for any such acquisition might involve the payment of cash and/or the issuance of equity or debt securities.

Notwithstanding
the Company's historical ability to implement the above strategy, the Company may not be able to successfully implement its strategy in the future. See "Risk Factors."



The following discussion focuses on areas the Company considers to be its core areas of operations and those that offer the Company the greatest opportunities for
further exploration and development activities.



The Wind River and Green River Basins of Wyoming, the Piceance Basin of Colorado, and the Paradox Basin of Colorado and Utah account for the major portion of the
Company's current and anticipated domestic exploration and development activities with approximately 74% of the Company's proved reserves at December 31, 2002. The Company owns interests in
1,278 producing wells in these basins that averaged net daily production of 159 Mmcfe for 2002. The Company has approximately
1,565,000 gross (1,224,000 net) developed and undeveloped acres in these basins, including option acreage of approximately 281,000 gross undeveloped (253,000 net) acres in the Wind River Basin.

In
2002, the Company drilled and completed 16 wells in the Wind River basin, the majority of which were located in the Pavillion field where the Company holds a 92% working interest. In
the Piceance basin, the Company drilled 26 wells in 2002 (completing 25). The Piceance wells were principally drilled at the Company's 100% owned White River Dome coal bed methane project in western
Colorado.

The
Rocky Mountain region has experienced limited natural gas transportation capacity. Recognizing these restrictions, various pipelines have constructed lines and are continuing to add
additional pipeline capacity into this area.



The Permian and Val Verde Basins accounted for approximately 9% of the Company's proved reserves at December 31, 2002. The Company's share of production
from these basins averaged 28 Mmcfepd for 2002. The Company holds between 30% to 50% working interests in approximately 46,800 gross (20,300 net) acres in the Val Verde Basin. The Permian Basin
contains significant oil reserves for the Company, located primarily in the Sprayberry Field.

In
the Deep Valley exploration project area of the Permian Basin, the Company drilled a horizontal Montoya well in 2001 which tested non-commercial in the Montoya formation
but will be tested in the Devonian formation in 2003. In 2002, the Company successfully completed a Devonian well in this area with a 50% working interest that commenced production in June 2002
at initial rates approximating 10 Mmcfepd declining to 2.5 Mmcfepd in early 2003. Two wells were drilled subsequent to this discovery in 2002 that are currently being evaluated. The Company also
attempted a horizontal re-entry in Deep Valley to test the Devonian section of a well in 2002 that was unsuccessful.



The Company participates in a continuing developmental drilling program in the Mimms Creek Field (Bossier Sands play) in Freestone County, Texas. During 2002, 11
wells were drilled and completed under this program, with the Company owning working interests ranging from 50% to 62.5%.

In
recent years, the Company has acquired approximately 80,000 net acres in the James Lime (horizontal) Trend of the east Texas Basin. In 2001, the Company drilled seven wells in
the James Lime (horizontal) Trend of which five were initially completed. This large regional play is in its early stages of development and the Company is working to determine its potential based
upon the initial production rates and variable decline rates of the wells drilled to date.



The western Canadian Sedimentary Basin accounted for approximately 11% of the Company's proved reserves at December 31, 2002. The Company's share of
production from these basins averaged 24 Mmcfepd in 2002. The Company owns interests in 252 wells and has approximately 540,000 gross (359,000 net) developed and undeveloped acres in this area. In
2002, the Company drilled 13 wells in Canada of which 12 were completed. These wells were primarily located in the Carrot Creek and Edson fields operated by the Company.



Effective January 16, 2001, the Company purchased 100% of Stellarton Energy Corporation ("Stellarton") for $95 million. The acquisition was funded
through a five-year Canadian term loan. Stellarton's assets are located in western Alberta, Canada with estimated total net proved reserves (after royalty) of 58.8 billion cubic
feet (Bcf) of gas and 2.82 million barrels of oil and natural gas liquids for total equivalent proved reserves of 75.5 Bcfe, as of the date of this acquisition. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of OperationsCapital Resources and LiquidityDebt" for a description of the material terms of the Company's bank
credit facility, including the Canadian term loan.



In June 2002, the Company purchased Rocky Mountain gas and oil properties located within the Greater Green River Basin of Wyoming for approximately
$8.1 million from an unrelated third party. In December 2002, the Company acquired additional assets within this basin from this seller for $6.8 million. The acquisition cost of
both of these transactions was net of normal closing adjustments. The acquired interests from these two transactions included an estimated 12.7 Bcfe of proved reserves.

In
June 2000, the Company purchased an additional working interest in the Company-operated Pavillion Field in the Wind River Basin in Wyoming. The Company acquired the additional
interest from State Farm Mutual Automobile Insurance Company, a stockholder of the Company. The acquired interests included an estimated 24 Bcfe of proved reserves purchased for total consideration of
$15.2 million net of normal closing adjustments.



In July 1999, the Company completed an acquisition of substantially all of the Rocky Mountain oil and gas assets of Unocal Corporation ("Unocal") for
5.8 million shares of common stock and $5 million in cash for a total purchase price of $68.5 million ($60.9 million after deducting normal purchase price adjustments).

The
Unocal oil and gas assets are primarily located in the Paradox Basin of southwestern Colorado and southeastern Utah. These assets and properties compliment the Company's 163,000 net
undeveloped acres in the Paradox Basin.

Included
in the acquisition was the Lisbon Plant, a modern sophisticated cryogenic (60 million cubic feet per day capacity) natural gas processing plant that extracts natural gas
liquids and merchantable helium; and separates carbon dioxide, hydrogen sulfide and nitrogen from the raw gas stream. The net proved reserves of these Unocal properties were estimated to be
93.2 billion cubic feet equivalent of gas as of the closing date of July 1, 1999. Approximately 65,000 net undeveloped acres were also acquired.



In September 1999, KM became the operator of, and 55% partner in, Wildhorse as a result of a merger with KN Energy, Inc. ("KNE"). Wildhorse was
formed in connection with the Company's 1996 acquisition of KN Production Company, the wholly-owned oil and gas production subsidiary of KNE. Wildhorse was created to provide services related to
natural gas, natural gas liquids and other natural gas products, including gathering, processing and storage services and field services. The Company owned 45% of Wildhorse since its inception.
Effective September 1, 1999, Wildhorse assigned 100% of its marketing operations to Retex, the Company's wholly-owned marketing subsidiary. Additionally, firm transportation contracts were
assigned 55% to KM and 45% remained in Retex. In November 2000, the Wildhorse gathering and processing assets were distributed to the Company in anticipation of the dissolution of Wildhorse. KM
received the Wildhorse storage facility and a cash payment of $14.7 million. "TBIFS" was formed as a wholly-owned subsidiary of Tom Brown, Inc. to administer the gathering and processing
assets received in this distribution.

In
2001, TBIFS selectively sold many of the gathering and processing facilities received in the Wildhorse asset distribution. The systems sold were considered non-strategic
to the Company's operations and, as these divestitures were part of the Wildhorse integration process, the net cash proceeds of $24.0 million were recorded as a reduction to the investment in
gathering assets. After these divestitures, the only significant asset retained was the Wind River gathering system in one of the Company's core areas. In 2002, the Company liquidated TBIFS to
transfer the remaining gathering and processing assets to Tom Brown, Inc.



On January 7, 1998, the Company completed the acquisition of all of the drilling assets of W. E. Sauer Companies L.L.C. of Casper, Wyoming for
approximately $8.1 million. The Company operates the assets in its subsidiary, Sauer Drilling Company ("Sauer"), and plans to continue to serve the drilling needs of operators in the central
Rocky Mountain region in addition to drilling for the Company. The assets included five drilling rigs, tubular goods, a yard and related assets. Subsequent to the acquisition, Sauer has acquired three
additional drilling rigs for approximately $4 million.



The Company's gas production has historically been sold primarily under month-to-month contracts with marketing companies and local
distribution companies (LDC's). During 2001 and 2002, there was a significant amount of volatility in the prices received for natural gas. Monthly closing gas prices in 2001 as measured on the New
York Mercantile Exchange ("NYMEX") varied from a high of $9.98 per million British thermal unit ("Mmbtu") for January 2001 to a low of $1.83 per Mmbtu for October 2001. In 2002,
the NYMEX gas prices varied from a high of $4.14 per Mmbtu in December 2002 to a low of $2.01 per Mmbtu in February 2002. The U.S. Rocky Mountain region represented approximately 68% of
the Company's 2002 gas production and 66% of its 2001 production. The price of gas in the Rocky Mountains at the Colorado Interstate Gas (CIG) hub was $1.25 and $.77 per Mmbtu below the NYMEX posted
gas price on average for 2002 and 2001, respectively. The


Company's Canadian production base has also been subject to price volatility. In 2001, gas production from the Canadian fields was subject to gas pricing that ranged from $1.10 per Mmbtu above the
February 2001 NYMEX price to a price that was $.98 per Mmbtu below the October 2001 NYMEX price. In 2002, the Canadian gas prices continued to be volatile ranging from $.12 per Mmbtu
below the NYMEX posting for February 2002 to $1.24 below the August 2002 NYMEX price.

The
Company markets most of its oil production with independent third-party resellers and refiners at market ("posted") prices. These posted prices generally reflect the prices
determined by the trading of
West Texas Intermediate ("WTI") oil futures contracts on the NYMEX, with adjustments due to basis differential and for the quality of oil produced.

NYMEX
prices for both gas and oil are influenced by weather, seasonal demand, levels of storage, production levels and a variety of political and economic factors over which the Company
has no control. See "Risk Factors."



The following table sets forth certain information regarding the Company's volumes of production sold and average prices received associated with its production
and sales of natural gas, natural gas liquids and crude oil for each of the years ended December 31, 2002, 2001 and 2000.

|                                      |                               | Years Ended December 31,
|------------------------------------- | ----------------------------- | ------------------------
|
|
|Production Volumes:                   |                               |                         
|                                      | Natural Gas (MMcf)            |                         
|                                      | Crude Oil (MBbls)             |                         
|                                      | Natural Gas Liquids (MBbls)   |                         
|Net Average Daily Production Volumes: |                               |                         
|                                      | Natural Gas (Mcf)             |                         
|                                      | Crude Oil (Bbls)              |                         
|                                      | Natural Gas Liquids (Bbls)    |                         
|Average Sales Prices:                 |                               |                         
|                                      | Natural Gas (per Mcf):        |                         
|                                      |                               | Price received          
|                                      |                               | Effect of hedges        
|                                      |                               |                         
|                                      |                               | Net sales price         
|                                      | Crude Oil (per Bbl)           |                         
|                                      | Natural Gas Liquids (per Bbl) |                         
|Average Production Cost (per Mcfe)(1) |                               | $                       



|                                      |                               | Years Ended December 31, |     |       
|------------------------------------- | ----------------------------- | ------------------------ | --- | ------
|
|
|Production Volumes:                   |                               |                          |     |       
|                                      | Natural Gas (MMcf)            |                          |     | 6,386 
|                                      | Crude Oil (Mbbls)             |                          |     | 220   
|                                      | Natural Gas Liquids (Mbbls)   |                          |     | 193   
|Net Average Daily Production Volumes: |                               |                          |     |       
|                                      | Natural Gas (Mcf)             |                          |     | 17,496
|                                      | Crude Oil (Bbls)              |                          |     | 601   
|                                      | Natural Gas Liquids (Bbls)    |                          |     | 529   
|Average Sales Prices:                 |                               |                          |     |       
|                                      | Natural Gas (per Mcf):        |                          |     |       
|                                      |                               | Price received           |     | $     
|                                      |                               | Effect of hedges         |     | $     
|                                      |                               |                          |     |       
|                                      |                               | Net sales price          |     | $     
|                                      | Crude Oil (per Bbl)           |                          | $   | 23.86 
|                                      | Natural Gas Liquids (per Bbl) |                          | $   | 16.17 
|Average Production Cost (per Mcfe)(1) |                               | $                        | .55 |       

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Gas and oil sales to ConocoPhillips, Inc. accounted for 17% of the Company's gas and oil sales for the year ended December 31, 2002. No other
purchaser accounted for 10% or more of the Company's total gas and oil revenue during 2002. Because there are numerous other parties available to purchase the Company's production, the Company
believes the loss of ConocoPhillips would not materially affect its ability to sell natural gas or crude oil.

In
2002, a previous purchaser of the Company's natural gas liquids in the Paradox Basin of Colorado and Utah defaulted on payments owed the Company totaling $6.2 million. In the
fourth quarter of 2002, the Company received a $1.4 million cash settlement in connection with this default. For additional information, please see Note 10Related Parties
and Significant Customers in the Notes to the Company's Consolidated Financial Statements.



The Company encounters strong competition from major oil companies and independent operators in acquiring properties and leases for the exploration for, and the
development and production of, natural gas and crude oil. Competition is particularly intense with respect to the acquisition of desirable undeveloped gas and oil leases. The principal competitive
factors in the acquisition of undeveloped gas and oil leases include the availability and quality of staff and data necessary to identify, investigate and purchase such leases, and the financial
resources necessary to acquire and develop such leases. Many of the Company's competitors have financial resources, staffs and facilities substantially greater than those of the Company. In addition,
the producing, processing and marketing of natural gas and crude oil is affected by a number of factors which are beyond the control of the Company, the effect of which cannot be accurately predicted.
See "Risk Factors."

The
principal raw materials and resources necessary for the exploration and development of natural gas and crude oil are leasehold prospects under which gas and oil reserves may be
discovered, drilling rigs and related equipment to drill for and produce such reserves and knowledgeable personnel



to conduct all phases of gas and oil operations. The Company must compete for such raw materials and resources with both major oil companies and independent operators.

Retex
encounters competition from other natural gas transportation and marketing entities in the marketing of gas. Such competition may materially affect the volumes and margins that
Retex may derive.



At December 31, 2002, the Company had 429 employees of which 103 were employed by Sauer. None of the Company's employees are represented by labor unions or
covered by any collective bargaining agreement. The Company considers its relations with its employees to be satisfactory.



Gas and oil operations are subject to various types of regulation by state and federal agencies. Legislation affecting the gas and oil industry is under constant
review for amendment or expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the gas and oil industry and its
individual members, some of which carry substantial penalties for failure to comply. The regulatory burden on the gas and oil industry increases the Company's cost of doing business and, consequently,
affects its profitability.

States
in which the Company conducts its gas and oil activities regulate the production and sale of natural gas and crude oil, including requirements for obtaining drilling permits, the
method of
developing new fields, the spacing and operation of wells and the prevention of waste of gas and oil resources. In addition, most states regulate the rate of production and may establish maximum daily
production allowables for wells on a market demand or conservation basis.



Prior to January 1993, certain natural gas sold by the Company was subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the
Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 ("NGPA"). The NGPA prescribed maximum lawful prices for natural gas sales effective December 1, 1978. Effective January 1,
1993, natural gas prices were completely deregulated and sales of the Company's natural gas are now made at market prices. The majority of the Company's gas sales contracts either contain decontrolled
price provisions or already provide for market prices.



Sales of crude oil, condensate and gas liquids by the Company are not regulated and are made at market prices.



The Company's natural gas and oil exploration, development and production operations are subject to stringent federal, state and local laws and regulations
governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (EPA),
issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in
injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various
substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on


certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require remedial action to prevent pollution from former operations, such as plugging abandoned wells
or closing pits, and impose substantial liabilities for pollution resulting from the Company's operations. The regulatory burden on the natural gas and oil industry increases the cost of doing
business and consequently affects profitability. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage,
transport, disposal or cleanup requirements could materially adversely affect the Company's operations and financial position, as well as the gas and oil industry in general. Management believes that
the Company is in substantial compliance with current applicable environmental laws and regulations and the Company has not experienced any material adverse effect from compliance with these
environmental requirements; this trend, however, may not continue in the future.

The
Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or Superfund, and comparable state laws impose liability without regard to
fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include
the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA,
such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for
the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of
hazardous substances or other pollutants into the environment. Rocno Corporation, a wholly owned subsidiary of the Company, has been identified as a potentially responsible party, or PRP, at the
Sheridan Superfund Site in Waller County, Texas. However, given the large number of PRPs identified at this site, as well as Rocno's relatively small proportionate share of estimated cleanup costs for
the site, management of the Company does not expect that Rocno's participation in the cleanup of the Sheridan Superfund Site will have a material adverse effect on the Company's operations. See "Item
3. Legal Proceedings."

The
Resource Conservation and Recovery Act (RCRA), as amended, generally does not regulate most wastes generated by the exploration and production of natural gas and oil. RCRA
specifically excludes from the definition of hazardous waste "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas
or geothermal energy." However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes
and waste compressor oils, may be regulated as hazardous waste. Although the costs of managing solid and hazardous waste may be significant, the Company does not expect to experience more burdensome
costs than similarly situated companies involved in natural gas and oil exploration and production.

The
Company currently owns or leases, and has in the past owned or leased, numerous properties that for many years have been used for the exploration and production of gas and oil.
Although the Company has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the
properties owned or leased by the Company or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose
treatment and disposal or release of hydrocarbons or other wastes was not under the Company's control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous
state laws. Under such laws, the Company could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial plugging or pit closure operations to
prevent future contamination.

The
Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge
of


pollutants, including produced waters and other gas and oil wastes, into state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in
accordance with the terms of a permit issued by the EPA or the state. These proscriptions also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of
Engineers. The EPA has also adopted regulations requiring certain gas and oil exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the
treatment of wastewater or developing and implementing storm water pollution prevention plans. The Company's management believes that the Company has obtained or applied for all permits required under
the Clean Water Act. Sanctions for failure to comply with Clean Water Act requirements include administrative, civil and criminal penalties, as well as injunctive relief.

The
Clean Air Act (CAA), as amended, restricts the emission of air pollutants from many sources, including natural gas and oil operations. New facilities may be required to obtain
permits before work can begin, and existing facilities may be required to incur capital costs in order to remain in compliance. In addition, more stringent regulations governing emissions of toxic air
pollutants are being developed by the EPA, and may increase the costs of compliance for some facilities. The Company's management believes that the Company is in substantial compliance with all air
emissions regulations and that the Company has or has applied for all necessary permits for its operations. Management also believes that air emission permits for operation of the Company's Pavillion
Gas Plant in Fremont
County, Wyoming and Lisbon Gas Plant in Moab, Utah are material to the Company's operations. Currently, the Pavillion Gas Plant holds a Title V air emission operating permit that will not expire until
January 9, 2009. The Lisbon Gas Plant is expected to be issued a Title V air emissions operating permit in the third quarter of 2003 and, until it receives the Title V permit, continues to
operate under a state-issued Approval Order that allows the facility to conduct operations under the state permit until such time as the Title V permit is issued. The Title V permit, once issued, is
expected to have an initial term of at least five years, and renewals and extensions of air emissions permits are routinely granted. The costs associated with obtaining and maintaining these permits
are not material.



The Company's Muddy Ridge and Pavillion Fields are located on the Wind River Indian Reservation. The Eastern Shoshone and Northern Arapaho Tribes levy taxes on
the production of hydrocarbons. The Bureau of Indian Affairs, Minerals Management Service and Bureau of Land Management of the U.S. Department of the Interior perform certain regulatory functions
relating to operation of Indian gas and oil leases. The Company owns interests in three leases in the Pavillion Field which were issued pursuant to the provisions of the Act of August 21, 1916,
for initial terms of 20 years each, with a preferential right by the lessee to renew the leases for subsequent ten-year terms. The leases were renewed for an additional
ten-year term in 1992, effective as of June 23, 1993. One of these leases has been amended to provide for incremental extensions of this lease term of up to an additional
12 years by drilling and completing additional wells on each lease prior to June 2003. In December of 2000 the Company added to its Tribal base inventory around the Pavillion Field by
signing eleven additional ten-year leases covering nearly 25,800 net acres. The Company is currently awaiting final approval of the leases by the Bureau of Indian Affairs and has deferred
drilling initially planned for early 2003 until the agreement between the Tribes and the Company on a methodology for payment of Tribal gas royalties is approved and executed by the Tribal Council and
the Minerals Management Service.



The oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any
of these controls or regulations will affect


our operations in a manner materially different than they would affect other oil and gas companies of similar size.

In
Canada, oil and gas exports are subject to regulation by the National Energy Board (NEB), an independent federal regulatory agency. The Company does not, at present, export oil or gas
under the terms of these regulations, but may be affected if regulations imposed by the NEB act to restrict the sales of gas and oil by other companies. Exports are also subject to the North American
Free Trade Agreement (NAFTA) which became effective on January 1, 1994. NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In
the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed provided that any export restrictions do not:
(i) reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36-month period), (ii) impose an
export price higher than the domestic price, and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements. NAFTA
contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural
gas exports.

The
provincial government of Alberta also regulates the volume of natural gas which may be removed from the province for consumption elsewhere based on such factors as reserve
availability, transportation arrangements and market considerations.

In
addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The
royalty regime on Crown lands is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by
negotiations between the mineral owner and the lessee. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and
the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product
produced.

From
time to time the governments of Canada and Alberta have established incentive programs which have included royalty rate deductions, royalty holidays and tax credits for the purpose
of encouraging
oil and natural gas exploration or enhanced recovery projects. At present, few of these programs are currently in effect.

In
Alberta, certain producers of oil or natural gas are currently entitled to a credit against the royalties to the Crown by virtue of the ARTC (Alberta royalty tax credit) program. The
credit is determined by applying a specified rate to a maximum of $2 million CDN of Alberta Crown royalties payable for each producer or associated group of producers. The specified rate is a
function of the Royalty Tax Credit reference price (RTCRP) which is set quarterly by the Alberta Department of Energy and ranges from 25% to 75%, depending on oil and gas par prices for the previous
calendar quarter. The provincial government of Alberta has proposed changes to the ARTC program which have not been finalized.



In Canada, the oil and natural gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental
legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition,
legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. The Company operates within this regulatory framework and continues to
monitor and evaluate the impact of the regulatory regime when determining parameters for engaging in gas and oil activities and investments in Canada. In


addition, the Company routinely obtains permits for its facilities and operations in accordance with these applicable laws and regulations on an ongoing basis. There are no known issues that have a
significant adverse effect on the permitting process or permit compliance status of any of the Company's facilities or operations.

In
Alberta, environmental compliance has been governed by the Alberta Environmental Protection and Enhancement Act ("AEPEA") since September 1, 1993. In addition, AEPEA also
imposes certain environmental responsibilities on oil and natural gas operators in Alberta and in certain instances also imposes penalties for violations. The Company has not received any violation
notices under the AEPEA or from any Canadian environmental regulatory agency. The Company believes that it is in substantial compliance with current applicable Canadian environmental laws and
regulations and that continued compliance with existing requirements would not have a material adverse impact on the Company's results of operations or financial condition.



The information in this Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933
and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical or present facts, that address activities, events, outcomes and other matters that
the Company plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are
forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. When
considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K.

Forward-looking
statements may appear in a number of places and include statements with respect to, among other things:



Forward-looking
statements are subject to all of the risks and uncertainties, many of which are beyond the Company's control, incident to the exploration for and acquisition,
development, production, marketing and sale of natural gas, natural gas liquids and crude oil in North America. These risks include, but are not limited to, commodity price volatility, third party
interruption of sales to market, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in
estimating proved natural gas and oil reserves and in projecting future rates of production and timing of development expenditures and the other risks described in this Form 10-K.

Reserve
engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate
depends on the


quality of available data and the interpretation of that data by geological engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that
were made previously. If significant, these revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the
quantities of natural gas and oil that are ultimately recovered.

Should
one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should underlying assumptions prove incorrect, the Company's
actual results and plans could differ materially from those expressed in any forward-looking statements. The Company specifically disclaims all responsibility to publicly update any information
contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaims any resulting liability for potentially related damages.

All
forward-looking statements attributable to the Company are expressly qualified in their entirety by this cautionary statement.



The Company's business is subject to a number of risks including, but not limited to, those described below:



The Company's revenues, profitability and future rate of growth depend substantially upon the market prices of natural gas and oil, which fluctuate widely.
Sustained declines in gas and oil prices may adversely affect the Company's financial condition, liquidity and results of operations. Factors that can cause market prices of natural gas and oil to
fluctuate include:



The
Company cannot predict future natural gas and oil prices. At various times, excess domestic and imported supplies have depressed gas and oil prices. Lower prices may reduce the
amount of natural gas and oil that the Company can produce economically and may also require the Company to write down the carrying value of its gas and oil properties. Substantially all of the
Company's natural gas and oil sales are made in the spot market or pursuant to contracts based on spot market prices, not long-term fixed price contracts.

In
an attempt to reduce price risk, the Company periodically enters into hedging transactions with respect to a portion of its expected future production. Such transactions may not
reduce the risk or


minimize the effect of any decline in natural gas or oil prices. Any substantial or extended decline in the prices of or demand for natural gas or oil would have a material adverse effect on the
Company's financial condition and results of operations.



There is a risk that the Company will be required to write down the carrying value of its gas and oil properties, which would reduce the Company's earnings and
stockholders' equity. A writedown could occur when gas and oil prices are low or if the Company has substantial downward adjustments to its estimated proved reserves, increases in its estimates of
development costs or deterioration in its exploration results.

The
Company accounts for its natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of
productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Gas and oil lease acquisition costs are also capitalized. Exploration costs, including
personnel costs, certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but
charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of the
Company's gas and oil properties may not exceed the estimated future net cash flows from its properties. If capitalized costs exceed future net revenues, the Company must write down the costs of the
properties to the Company's estimate of fair market value. Any such charge will not affect the Company's cash flow from operating activities, but it will reduce the Company's earnings and
stockholders' equity.

The
application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory,
which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial
reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver gas and oil in quantities insufficient to be
economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an
allocation of costs is required to properly account for the results. The evaluation of gas and oil leasehold acquisition costs requires judgment to estimate the fair value of these costs with
reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The
Company reviews its gas and oil properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a
writedown of gas and oil properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with gas and oil reserve estimates and the history of price
volatility in the gas and oil markets, events may arise that would require the Company to record an impairment of the recorded book values associated with gas and oil properties. In 1998, the Company
recognized a pre-tax impairment of $51.3 million, primarily as a result of the low market prices in effect at that time; similar impairments may be required in the future.



The marketability of the Company's production depends upon the availability, operation and capacity of gas gathering systems, pipelines and processing facilities.
The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or


discontinuance of development plans for properties. United States federal, state and foreign regulation of gas and oil production and transportation, general economic conditions and changes in supply
and demand could adversely affect the Company's ability to produce and market natural gas and oil. If market factors changed dramatically, the financial impact on the Company could be substantial. The
availability of markets and the volatility of product prices are beyond the Company's control and represent a significant risk.



The Company's revenues are derived principally from uncollateralized sales to customers in the gas and oil industry. The concentration of credit risk in a single
industry affects the Company's overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. The publicly disclosed deteriorating financial
conditions and recently reduced credit ratings of certain purchasers of production increase the possibility that the Company may not receive payment for a portion of its future production. In 2002, a
previous purchaser of the Company's natural gas liquids in the Paradox Basin of Colorado and Utah defaulted on payments owed the Company totaling $6.2 million; to date, the Company has received
only a $1.4 million cash settlement in connection with this default. The Company has attempted to obtain credit protections such as letters of credit, guarantees and prepayments from certain of
its purchasers. The Company is unable to predict, however, what impact the financial difficulties of certain purchasers may have on its future results of operations and liquidity.



This Form 10-K contains estimates of the Company's proved gas and oil reserves and the estimated future net revenues from such reserves. Actual
results will likely vary from amounts estimated and any significant variance could have a material adverse effect on the Company's future results of operations.

Gas
and oil reserve estimates are based upon various assumptions, including assumptions required by the Securities and Exchange Commission relating to gas and oil prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. The process of estimating gas and oil reserves is complex. This process requires significant decisions and assumptions in the
evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

Actual
future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable gas and oil reserves will most likely vary from
those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this document and the information incorporated by reference. The
Company's properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, the Company may adjust estimates of proved reserves to
reflect production history, results of exploration and development, prevailing gas and oil prices and other factors, many of which are beyond its control.

At
December 31, 2002, approximately 26% of the Company's U.S. estimated proved reserves were proved undeveloped, while 8% of the Company's Canadian estimated proved reserves were
proved undeveloped. Proved undeveloped reserves and proved developed non-producing reserves, by their nature, are less certain than proved developed producing reserves. Estimation of these
non-producing categories is nearly always based on volumetric calculations rather than the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves
requires significant capital expenditures and successful drilling operations. Production revenues from proved non-producing reserves will not be realized until some time in the future. The
reserve data assumes that the Company


will make significant capital expenditures to develop its reserves. Although the Company has prepared estimates of its gas and oil reserves and the costs associated with these reserves in accordance
with industry standards, these estimated costs may not be accurate, development may not occur as scheduled and actual results may not be as estimated.

You
should not assume that the estimated present value of future net cash flow referred to in this Form 10-K is the current fair value of the Company's estimated gas
and oil reserves. In accordance with Securities and Exchange Commission requirements, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date
of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by gas purchasers or in
governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of gas and oil properties
will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the Securities and Exchange Commission
to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor for the Company.



The Company has historically addressed its short and long-term liquidity needs through the use of cash flow provided by operating activities, the use
of bank credit facilities and the issuance of equity securities. Without adequate financing, the Company may not be able to successfully execute its operating strategy. The Company continues to
examine the following alternative sources of capital:



The
availability of these sources of capital will depend upon a number of factors, some of which are beyond the Company's control. These factors include general economic and financial market
conditions, natural gas and oil prices and the Company's market value and operating performance. The Company may be unable to execute its operating strategy if it cannot obtain adequate capital.



The Company spends and will continue to spend a substantial amount of capital for the acquisition, exploration, exploitation, development and production of gas
and oil reserves. If low natural gas and oil prices, operating difficulties or other factors, many of which are beyond the Company's control, cause its revenues and cash flows from operating
activities to decrease, the Company may be limited in its ability to spend the capital necessary to complete its capital expenditures program. In addition, if the Company's borrowing base under its
credit facility is re-determined to a lower amount, this could adversely affect the Company's ability to fund its planned capital expenditures. The Company's capital expenditures,
including acquisitions, were $161.7 million during 2002, $358.1 million during 2001 and $150.5 million during 2000. The Company anticipates capital and exploration expenditures
between $155 and $185 million in 2003, approximately 90% of which will be allocated to exploration and development activity. After utilizing its available sources of financing, the Company may
be forced to raise additional equity or debt proceeds to fund such expenditures. Additional equity or debt financing or cash flow provided by operations may not be available to meet the Company's
capital expenditures requirements.



The Company's reserves will decline as they are produced unless the Company acquires properties with proved reserves or conducts successful development and
exploration drilling activities. The Company's future natural gas and oil production is highly dependent upon its level of success in finding or acquiring additional reserves, which it may not be
successful in doing.

The
successful acquisition of producing properties requires an assessment of a number of factors, many of which are beyond the Company's control. These factors include recoverable
reserves, future gas and oil prices, operating costs and potential environmental and other liabilities, title issues and other factors. Such assessments are inexact and their accuracy is inherently
uncertain. In connection with such assessments, the Company performs a review of the subject properties, which it believes is generally consistent with industry practices. However, such a review will
not reveal all existing or potential problems. In addition, the review will not permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.
The Company may not be able to acquire properties at acceptable prices because the competition for producing gas and oil properties is intense and many of the Company's competitors have financial and
other resources that are substantially greater than those available to the Company.



Gas and oil drilling and production activities are subject to numerous risks, including the risk that no commercially productive natural gas or oil reservoirs
will be found. Gas and oil drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond the Company's control. These factors
include:



The
prevailing prices of natural gas and oil also affect the cost of and the demand for drilling rigs, production equipment and related services.

New
wells that the Company drills may not be productive and the Company may not recover all or any portion of its investment. The cost of drilling and completing wells is often
uncertain. Drilling for natural gas and oil may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating
and other costs to recoup drilling costs.



The exploration, development and operation of gas and oil properties involves a variety of operating risks including the risk of fire, explosions, blowouts, pipe
failure, abnormally pressured formations and environmental hazards, including oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. If any of these industry-operating risks occur, the
Company could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other
environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations.

The
Company maintains insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, the Company cannot
predict the continued availability of insurance at premium levels that justify its purchase. The terrorist attacks on September 11, 2001 and the changes in the insurance markets attributable to
those attacks may make some types of insurance more difficult to obtain. The Company may be unable to secure the level and types of insurance it would otherwise have secured prior to
September 11th. The Company may not be able to maintain insurance in the future at rates it considers reasonable. The occurrence of a significant event, not fully insured or indemnified
against, could materially and adversely affect the Company's financial condition and operations.



On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scale. Since the September 11th attacks, the U.S.
government has issued warnings that U.S. energy assets may
be the future targets of terrorist organizations. These developments have subjected the Company's operations to increased risks. Any future terrorist attack at the Company's facilities, or those of
its purchasers, could have a material adverse effect on the Company's business.



The terms of the agreements governing the Company's debt impose significant restrictions on the Company's ability and the ability of its subsidiaries to take a
number of actions that the Company may otherwise desire to take, thereby negatively impacting the Company's financial condition, results of operations and business prospects. These provisions
restrict:



The
Company's level of indebtedness, and the covenants contained in the agreements governing the Company's debt, could have important consequences on its operations, including, for
example, making the Company vulnerable to increases in interest rates, because debt under the Company's credit facility will be at variable rates.

The
Company may be required to repay all or a portion of its debt on an accelerated basis in certain circumstances. If the Company fails to comply with the covenants and other
restrictions in the agreements governing its debt, it could lead to an event of default and the acceleration of the Company's repayment of outstanding debt. The Company's ability to comply with these
covenants and other restrictions may be affected by events beyond the Company's control, including prevailing economic and financial conditions. The credit facility allows the lenders one scheduled
redetermination of the borrowing base each December. In addition, the lenders may elect to require one unscheduled


redetermination in the event the borrowing base utilization exceeds 50% of the borrowing base at any time for a period of 15 consecutive business days. Upon a redetermination, if borrowings in excess
of the revised borrowing capacity were outstanding, the Company could be forced to repay a portion of its bank debt.

The
Company may not have sufficient funds to make such repayments. If the Company is unable to repay its debt out of cash on hand, it could attempt to refinance such debt, sell assets or
repay such debt with the proceeds from an equity offering. The Company may not be able to generate sufficient cash flow from operating activities to pay the interest on its debt. In addition, future
borrowings, equity financings or proceeds from the sale of assets may not be available to pay or refinance such debt. The terms of the Company's debt, including its credit facility, may also prohibit
the Company from taking such actions. Factors that will affect the Company's ability to raise cash through an offering of its capital stock, a refinancing of its debt or a sale of assets include
financial market conditions and the Company's market value and operating performance at the time of such offering or other financing. The Company may not successfully complete any such offering,
refinancing or sale of assets.



Competition in the Wind River and Green River Basins of Wyoming, the Piceance Basin of Colorado and the Paradox Basin of Utah and Colorado is intense,
particularly with respect to the acquisition of producing properties and proved undeveloped acreage. The Company competes with major gas and oil companies and other independent producers of varying
sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of the Company's competitors have financial resources and exploration and
development budgets that are substantially greater than the Company's, which may adversely affect the Company's ability to compete.



The Company's gas and oil operations are subject to stringent U.S. federal, state and local laws and regulations relating to the release or disposal of materials
into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties,
the incurrence of investigatory or remedial obligations, or the imposition of injunctive relief.

The
environmental laws and regulations to which the Company is subject may:



Changes
in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup
requirements could require the Company to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on the earnings, results of operations, competitive
position or financial condition of the Company. Over the years, the Company has owned or leased numerous properties for gas and oil activities upon which petroleum hydrocarbons or other materials may
have been released by the Company or by predecessor property owners or lessees who were not under the Company's control.


Under applicable environmental laws and regulations, including CERCLA, RCRA and analogous state laws, the Company could be held strictly liable for the removal or remediation of previously released
materials or property contamination at such locations regardless of whether the Company was responsible for the release or if the Company's operations were standard in the industry at the time they
were performed. For additional information about the specific environmental laws and regulations to which the Company is subject, see "RegulationUnited
StatesEnvironmental Regulation."



The Company's operations are dependent upon a relatively small group of key management and technical personnel. The unexpected loss of the services of one or more
of these individuals could have an adverse effect on the Company. The Company considers all of its executive officers to be key employees. Such individuals may not remain with the Company for the
immediate or foreseeable future. The Company does not maintain key man insurance on any employee, and has an employment contract only with James D. Lightner, the Company's Chairman, Chief Executive
Officer and President.



In order to manage its exposure to price risks in the marketing of gas and oil, the Company periodically enters into gas and oil price hedging arrangements, such
as commodity swap agreements, forward sale contracts, commodity futures, options and similar agreements, with respect to a portion of its expected production. While intended to reduce the effects of
volatile gas and oil prices, such transactions, depending on the hedging instrument used, may limit the Company's potential gains if gas and oil prices were to rise substantially over the price
established by the hedge. In addition, such transactions may expose the Company to the risk of financial loss in certain circumstances, including instances in which:



The Company has never declared or paid any cash dividends on its common stock and has no intention to do so in the near future. The restrictions on the Company's
present or future ability to pay dividends are included in the provisions of the Delaware General Corporation Law. In addition, the Company has entered into a credit facility that contains provisions
that may have the effect of limiting or prohibiting the payment of dividends.



Certain provisions of the Company's Certificate of Incorporation and stockholders' rights plan and the provisions of the Delaware General Corporation Law may
encourage persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with the Company's board of directors rather than pursue non-negotiated takeover
attempts. As a result, these provisions could have the effect of preventing stockholders from realizing a premium on their investment.

The
Company's Certificate of Incorporation authorizes the Company's board of directors to issue preferred stock without stockholder approval and to set the rights, preferences and other
designations, including voting rights of those shares, as the board may determine. Additional provisions include restrictions on business combinations and the availability of authorized but unissued
common stock. These provisions, alone or in combination with each other and with the rights plan described below,


may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for
their common stock.

In
1991, the Company adopted a rights plan, pursuant to which uncertificated stock purchase rights were distributed to stockholders at a rate of one right for each share of common stock
held of record as of March 15, 1991. On March 1, 2001, the Company amended and restated the rights plan. Each right entitles the registered holder to purchase, for a $120 per share
exercise price, shares of common stock or other securities of the Company (or, under certain circumstances, of the acquiring person) worth twice the per share exercise price of the right. The rights
plan is designed to enhance the Company's ability to prevent an acquirer from depriving stockholders of the long-term value of their investment and to protect stockholders against attempts
to acquire the Company by means of unfair or abusive takeover tactics. However, the existence of the rights plan may impede a takeover not supported by the Company's board, including a takeover that
may be desired by a majority of stockholders or involving a premium over the prevailing stock price.

ITEM 2.Properties



The principal properties of the Company consist of developed and undeveloped gas and oil leases. Generally, the terms of developed gas and oil leaseholds are
continuing and such leases remain in force by virtue of, and so long as, production from lands under lease is maintained. Undeveloped gas and oil leaseholds are generally for a primary term, such as
five or ten years, subject to maintenance with the payment of specified minimum delay rentals or extension by production. The Company also has options to lease undeveloped gas and oil
leaseholds on Eastern Shoshone and Northern Arapaho Tribal lands. The oil and gas leases had initial terms of twenty years and the Company has a preferential right to negotiate with the Tribes
for renewals of subsequent ten-year terms.



As is customary in the gas and oil industry, the Company makes only a cursory review of title to undeveloped gas and oil leases at the time they are acquired by
the Company. However, before drilling commences, the Company causes a thorough title search to be conducted, and any material defects in title are remedied prior to the time actual drilling of a well
on the lease begins. The Company believes that it has good title to its gas and oil properties, some of which are subject to immaterial encumbrances, easements and restrictions. The gas and oil
properties owned by the Company are also typically subject to royalty and other similar non-cost bearing interests customary in the industry. The Company does not believe that any of these
encumbrances or burdens materially affects the Company's ownership or use of its properties.



The following table sets forth the gross and net acres of developed and undeveloped gas and oil leases held by the Company at December 31, 2002. Included
in the table are approximately 281,000


gross (253,000 net) acres in Wyoming under gas and oil option agreements acquired from certain Indian tribes.

|              |       | DEVELOPED |         | UNDEVELOPED
|------------- | ----- | --------- | ------- | -----------
|
|Colorado      |       | 106,681   |         | 87,045     
|Louisiana     |       | 1,419     |         | 671        
|Michigan      |       |          |         |           
|Montana       |       | 102       |         | 76         
|Nebraska      |       |          |         |           
|New Mexico    |       | 15,412    |         | 3,952      
|North Dakota  |       |          |         |           
|Texas         |       | 112,526   |         | 42,852     
|Utah          |       | 6,599     |         | 5,821      
|West Virginia |       | 3,852     |         | 1,240      
|Wyoming       |       | 116,632   |         | 57,983     
|Canada        |       | 143,520   |         | 80,889     
|Other         |       |          |         |           
|              |       |           |         |            
|              | Total |           | 506,743 |            
|              |       |           |         |            

"Gross"
acres refer to the number of acres in which the Company owns a working interest. "Net" acres refer to the sum of the fractional working interests owned by the Company in gross
acres.



Estimates of the Company's gas, oil and natural gas liquids reserves, including future net revenues and the present value of future net cash flows, were prepared
by the Company's petroleum engineering staff and reviewed by Ryder Scott (independent petroleum consultants). Guidelines established by the Securities and Exchange Commission were utilized to prepare
these reserve estimates. Estimates of gas, oil and natural gas liquids reserves and their estimated values require numerous engineering assumptions as to the productive capacity and production rates
of existing geological formations and require the use of certain Securities and Exchange Commission guidelines as to assumptions regarding costs to be incurred in developing and producing reserves and
prices to be realized from the sale of future production.

Accordingly,
estimates of reserves and their value are inherently imprecise and are subject to constant revision and change and should not be construed as representing the actual
quantities of future production or cash flows to be realized from the Company's gas and oil properties or the fair market value of such properties. See "Risk Factors."

Certain
additional unaudited information regarding the Company's reserves, including the present value of future net cash flows, is set forth in the Notes to Consolidated Financial
Statements included herein.

The
Company has no gas, oil and natural gas liquids reserves or production subject to long-term supply or similar agreements with foreign governments or authorities.

Estimates
of the Company's total proved gas and oil reserves have not been filed with or included in reports to any federal authority or agency other than the Securities and Exchange
Commission.



The following table sets forth the gross and net productive gas and oil wells in wells in which the Company owned an interest at December 31, 2002.

|              |       | Productive Wells
|------------- | ----- | ----------------
|
|
|Colorado      |       | 556             
|Louisiana     |       | 4               
|New Mexico    |       | 22              
|Utah          |       | 9               
|Texas         |       | 191             
|West Virginia |       | 89              
|Wyoming       |       | 639             
|Canada        |       | 150             
|              |       |                 
|              | Total |                 
|              |       |                 

A
"gross" well is a well in which the Company owns a working interest. "Net" wells refer to the sum of the fractional working interests owned by the Company in gross wells.



The following table sets forth the Company's gross and net interests in exploratory and development wells drilled during the periods indicated.

|            |     | United States |    | Canada
|----------- | --- | ------------- | -- | ------
|
|
|
|
|Exploratory |     |               |    |       
|            | Gas |               | 5  |       
|            | Oil |               |   |       
|            | Dry |               | 7  |       
|            |     |               |    |       
|            |     | 12            |    | 6.4   
|            |     |               |    |       
|Development |     |               |    |       
|            | Gas |               | 66 |       
|            | Oil |               |   |       
|            | Dry |               | 3  |       
|            |     |               |    |       
|            |     | 69            |    | 46.1  
|            |     |               |    |       
|Total       |     | 81            |    | 52.5  
|            |     |               |    |       



|            |     | United States |     | Canada
|----------- | --- | ------------- | --- | ------
|
|
|
|
|Exploratory |     |               |     |       
|            | Gas |               | 7   |       
|            | Oil |               |    |       
|            | Dry |               | 12  |       
|            |     |               |     |       
|            |     | 19            |     | 13.3  
|            |     |               |     |       
|Development |     |               |     |       
|            | Gas |               | 139 |       
|            | Oil |               |    |       
|            | Dry |               | 7   |       
|            |     |               |     |       
|            |     | 146           |     | 101.4 
|            |     |               |     |       
|Total       |     | 165           |     | 114.7 
|            |     |               |     |       

|            |     | United States |    |      |      |     |     | 
|----------- | --- | ------------- | -- | ---- | ---- | --- | --- | 
|
|
|
|
|Exploratory |     |               |    |      |      |     |     | 
|            | Gas |               |   |      |     |     |    | 
|            | Oil |               |   |      |     |     |    | 
|            | Dry |               | 3  |      | 2.3  |     | 100 | 
|            |     |               |    |      |      |     |     | 
|            |     | 3             |    | 2.3  |      | 100 |     | 
|            |     |               |    |      |      |     |     | 
|Development |     |               |    |      |      |     |     | 
|            | Gas |               | 63 |      | 33.7 |     | 93  | 
|            | Oil |               | 1  |      | .2   |     | 1   | 
|            | Dry |               | 4  |      | 2.3  |     | 6   | 
|            |     |               |    |      |      |     |     | 
|            |     | 68            |    | 36.2 |      | 100 |     | 
|            |     |               |    |      |      |     |     | 
|Total       |     | 71            |    | 38.5 |      |     |     | 
|            |     |               |    |      |      |     |     | 

At
December 31, 2002, 5 gross (2.6 net) development wells and 6 gross (4.7 net) exploration wells were in various stages of drilling and completion in Texas, Colorado, and
Wyoming, while 3 gross (2.5 net) development wells were in various stages of drilling and completion in Canada. The investment in the exploratory wells in progress was approximately $10 million
at December 31, 2002.



The Company leases its corporate office facilities in Denver, Colorado. The lease covers approximately 56,500 square feet and expires January 31, 2004. Of
this amount, the Company subleases 7,246 square feet under an agreement that expires January 31, 2004.

The
Company leases office facilities in Midland, Texas. The lease covers approximately 33,150 square feet for a term of five years and expires December 31, 2003.

The
Company also leases office facilities in Calgary, Alberta. The lease covers approximately 14,600 square feet for a term of five years and expires August 31, 2004.

For
a summary of the rental commitments associated with these leases, see Note 13Commitments and Contingencies in the Notes to the Company's Consolidated Financial
Statements.

ITEM 3.Legal Proceedings

The Company is a defendant in several routine legal proceedings incidental to its business.

In
addition to routine legal proceedings incidental to the Company's business, Rocno was a defendant in a complaint filed by the United States of America which, among other things,
alleged that Rocno and approximately 117 other companies arranged for the disposal of "hazardous materials" (within the meaning of CERCLA) in Waller County, Texas (the "Sheridan Superfund Site").
Effective August 31,
1989, Rocno and thirty-six other defendants executed the Sheridan Site Trust Agreement (the "Trust") for the purpose of creating a trust to perform agreed upon remedial action at the
Sheridan Superfund Site. In connection with the establishment of the Trust, the parties to the Trust agreed to the terms of a Consent Decree entered December 3, 1991 in the United States
District Court, Southern District of Texas, Houston Division, Civil Action No. H-91-3529, pursuant to which the defendants joining the Consent Decree will carry out the
clean-up plan prescribed by the Consent Decree. In December 2002, the EPA approved a change in the remedy that was originally selected for clean-up of the Sheridan
Superfund Site by eliminating the biotreatment of site wastes prior to stabilization and capping of the wastes. The EPA is currently amending the Consent Decree to include the revised remedy. The
estimate of the total clean-up cost under the revised remedy is approximately $14.3 million. Under terms of the Trust, each party is allocated a percentage of costs necessary to
fund the Trust for clean-up costs. Rocno's proportionate share of the estimated clean-up costs is 0.33% or $47,200, of which $16,000 has been paid, and the remainder was
accrued in the Company's consolidated financial statements. If the clean-up costs exceed the projected amount, Rocno will be required to pay its pro rata share of the excess
clean-up costs.

The
Company is also a party to an action brought in Sweetwater County, Wyoming by three overriding royalty interest owners seeking certification as a class of all
non-governmental entities which are paid royalties or overriding royalties by the Company in Wyoming. This action is one of more than a dozen virtually identical class action lawsuits
filed in various Wyoming courts against producers and operators in Wyoming. The complaint alleges that the Company violated the Wyoming Royalty Payment Act (the "Act") by improperly deducting gas
transportation costs in calculating royalties and overriding royalties on Wyoming production and by failing to properly itemize all deductions taken on its payee reports. The complaint does not allege
specific money damages. The issue in the case is whether transportation of natural gas off the lease to market is deductible transportation or nondeductible gathering within the meaning of the Act. In
January 2003, the Wyoming Supreme Court agreed to answer two certified questions in a separate lawsuit which are (1) what is meant by the term "gathering" as that term is employed in the
Act in defining nondeductible "costs of production," and (2) when do the causes of action for recovery of the reporting penalty and for improper deductions under the Act accrue. Because of the
preliminary nature of the proceedings, it is not possible to fully determine the ultimate loss exposure or probable outcome of this litigation.

ITEM 4.Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of the Company's stockholders in the fourth quarter of the year ended December 31, 2002.

ITEM 4A.Executive Officers of the Registrant

On January 19, 2001, Donald L. Evans, the Company's Chairman of the Board and Chief Executive Officer, resigned to accept an appointment as the Secretary
of the U.S. Department of Commerce. The Company's Board of Directors elected James B. Wallace as the new Chairman of the


Board and James D. Lightner to the additional position of Chief Executive Officer in 2001 following Mr. Evans' resignation. At the annual stockholder's meeting in May 2002, James D.
Lightner was elected to replace Mr. Wallace as the new Chairman of the Board.

The
executive officers of the Company on March 18, 2003 were as follows:

|Name                |  | Age |  | Position with Company                                          
|------------------- |  | --- |  | ---------------------------------------------------------------
|James D. Lightner   |  | 50  |  | Chairman, Chief Executive Officer and President                
|Daniel G. Blanchard |  | 42  |  | Executive Vice President, Chief Financial Officer and Treasurer
|Thomas W. Dyk       |  | 49  |  | Executive Vice President and Chief Operating Officer           
|Peter R. Scherer    |  | 46  |  | Executive Vice President                                       
|Bruce R. DeBoer     |  | 50  |  | Vice President, General Counsel and Secretary                  
|Douglas R. Harris   |  | 48  |  | Vice PresidentOperations                                      
|Rodney G. Mellott   |  | 45  |  | Vice PresidentLand and Business Development                   

Each
executive officer is elected annually by the Company's Board of Directors to serve at the Board's discretion.

The
following biographies describe the business experience of the Company's executive officers for at least the past five years.

James
D. Lightner joined the Company in May 1999 as President. In January 2001, he was named Chief Executive Officer. He was appointed Chairman of the Board in
May 2002. Mr. Lightner has been a member of the Board of Directors since 1999. He also serves as a member of the Executive Committee. Prior to joining Tom Brown, Mr. Lightner
served as Vice President and General Manager of the Denver Division of EOG Resources from April 1989 through April 1999.

Daniel
G. Blanchard joined the Company in July 1999 as Vice President and Chief Financial Officer and was subsequently named Executive Vice President and Treasurer. From
January 1999 through May 1999, Mr. Blanchard served as Assistant Treasurer with Gulf Canada Resources. He served as Treasurer and Director of Corporate Development for Forest Oil
Company from September 1994 through December 1998.

Thomas
W. Dyk joined the Company in April 1998 as Executive Vice President and was subsequently named the Company's Chief Operating Officer in 1999. Prior to joining Tom Brown,
Mr. Dyk served as Regional Vice President for the Rocky Mountain Division of Burlington Resources.

Peter
R. Scherer joined the Company in 1982. He has held various positions, most recently Executive Vice President and General Manager of the Southern Region. Prior to joining Tom Brown,
Mr. Scherer was employed by Amoco Oil and Gas Company.

Bruce
R. DeBoer joined the Company in 1997 as Vice President, General Counsel and Secretary. Prior to joining Tom Brown, he served in a similar capacity for eight years with Presidio Oil
Company.

Douglas
R. Harris joined the Company in February 2001 as Vice PresidentOperations. From February 1986 through January 2001, he served as Vice
PresidentProduction for Burlington Resources Canada in Calgary.

Rodney
G. Mellott joined the Company in December 1999 as Vice PresidentLand and Business Development. Prior to joining Tom Brown, Mr. Mellott was employed for
15 years in various capacities by EOG Resources, Inc.





PART II

ITEM 5.Market for Registrant's Common Equity and Related Stockholder Matters

The Company's Common Stock is listed and principally traded on the New York Stock Exchange ("NYSE") under the ticker symbol "TBI". Prior to May 16, 2002,
the Company traded on the NASDAQ National Market System. The following table sets forth the range of high and low closing quotations for each quarterly period during the past two fiscal years
as reported by NASDAQ National Market System for the March 31, 2001 through the March 31, 2002 periods, and the NYSE for the June 30, 2002 through December 31, 2002 period.

|                   |  | Closing Sale Price
|------------------ |  | ------------------
|
|
|March 31, 2001     |  | $                 
|June 30, 2001      |  |                   
|September 30, 2001 |  |                   
|December 31, 2001  |  |                   
|March 31, 2002     |  |                   
|June 30, 2002      |  |                   
|September 30, 2002 |  |                   
|December 31, 2002  |  |                   

On
March 11, 2003 the last sale price of the Company's Common Stock, as reported by the New York Stock Exchange was $24.75 per share.

The
transfer agent for the Company's Common Stock is EquiServe Trust Company, N.A., Canton, Massachusetts.

On
December 31, 2002, the outstanding shares of the Company's Common Stock (39,261,191 shares) were held by approximately 1,763 holders of record.

The
Company has never declared or paid any cash dividends to the holders of Common Stock and has no present intention to pay cash dividends to the holders of Common Stock in the future.
Under the terms of the Company's Credit Agreement, the Company is prohibited from paying cash dividends to the holders of Common Stock without the written consent of the bank lenders.

In
January 1996, in connection with the acquisition of KN Production Company ("KNPC"), the Company issued 1,000,000 shares of its $1.75 Convertible Preferred Stock,
Series A (the "Preferred Stock") to the seller. The Preferred Stock was exchangeable, in whole or in part, at the option of the Company on any dividend payment date at any time on or after
March 15, 1999, and prior to March 15, 2001, for shares of Common Stock at the exchange rate of 1.666 shares of Common Stock for each share of Preferred Stock; provided that
(i) on or prior to the date of exchange, the Company shall have declared and paid or set apart for payment to the holders of Preferred Stock all accumulated and unpaid dividends to the date of
exchange, and (ii) the current market price of the Common Stock was above $18.375 (the "Threshold Price"). On June 15, 2000, the Company elected to exchange 1,666,000 shares of its
Common Stock for all 1,000,000 outstanding shares of the Preferred Stock as the Common Stock had traded above the Threshold Price.

In
July 1999, the Company completed an acquisition of substantially all of the Rocky Mountain oil and gas assets of Unocal Corporation for 5.8 million shares of common
stock and $5 million in cash.

On
March 1, 1991, the Board of Directors adopted a Rights Plan designed to help assure that all stockholders receive fair and equal treatment in the event of a hostile attempt to
take over the Company, and to help guard against abusive takeover tactics. The Board of Directors declared a


dividend of one preferred share purchase right (a "Right") for each outstanding share of Common Stock. The dividend was distributed on March 15, 1991 to the stockholders of record on that date.
As of March 1, 2001, the Board of Directors amended and restated the Rights Plan. Each Right entitles the registered holder to purchase, for the $120 per share exercise price, shares of Common
Stock or other securities of the Company (or, under certain circumstances, of the acquiring person) worth twice the per share exercise price of the Right.

The
Rights will be exercisable only if a person or group acquires 15% or more of the Company's Common Stock or announces a tender offer which would result in ownership by a person or
group of 15% or more of the Common Stock. The date on which the above occurs is to be known as the "Distribution Date". The Rights will expire on March 1, 2011, unless extended or redeemed
earlier by the Company.

At
the time the Rights dividend was declared, the Board of Directors further authorized the issuance of one Right with respect to each share of the Company's Common Stock that shall
become outstanding between March 15, 1991 and the earlier of the Distribution Date or the expiration or redemption of the Rights. Until the Distribution Date occurs, the certificates
representing shares of the Company's Common Stock also evidence the Rights. Following the Distribution Date, the Rights will be evidenced by separate certificates.

The
provisions described above may tend to deter any potential unsolicited tender offers or other efforts to obtain control of the Company that are not approved by the Board of Directors
and thereby deprive the stockholders of opportunities to sell shares of the Company's Common Stock at prices higher than the prevailing market price. See "Risk Factors." On the other hand, these
provisions will tend to assure continuity of management and corporate policies and to induce any person seeking control of the Company or a business combination with the Company to negotiate on terms
acceptable to the then elected Board of Directors.

ITEM 6.Selected Financial Data

The following tables set forth selected financial information for the Company for each of the years shown.

The
Company's historical results of operations have been materially affected by the increase in the Company's size as a result of the Stellarton Acquisition in January 2001 and
the Unocal Acquisition in


July 1999. (See the Notes to Consolidated Financial Statements of the Company included elsewhere herein.)

|                                                                            |                                                     | Years Ended December 31, |        
|--------------------------------------------------------------------------- | --------------------------------------------------- | ------------------------ | -------
|
|
|Revenues                                                                    |                                                     | $                        | 235,645
|                                                                            |                                                     |                          |        
|Income (loss) before cumulative effect of change in accounting principle(1) |                                                     |                          | 9,926  
|                                                                            |                                                     |                          |        
|Net (loss) income attributable to common stock                              |                                                     |                          | (8,177 
|                                                                            |                                                     |                          |        
|Weighted average number of common shares outstanding                        |                                                     |                          |        
|                                                                            | Basic                                               |                          |        
|                                                                            |                                                     |                          |        
|                                                                            | Diluted                                             |                          |        
|                                                                            |                                                     |                          |        
|Net (loss) income per common share                                          |                                                     |                          |        
|                                                                            | Basic                                               |                          |        
|                                                                            |                                                     |                          |        
|                                                                            | Diluted                                             |                          |        
|                                                                            |                                                     |                          |        
|Total assets                                                                |                                                     |                          | 850,952
|                                                                            |                                                     |                          |        
|Long-term debt, net of current maturities                                   |                                                     |                          | 133,172
|                                                                            |                                                     |                          |        
|Other Financial Data:                                                       |                                                     |                          |        
|                                                                            | Net cash provided by operating activities           |                          |        
|                                                                            | Net cash used in investing activities               |                          |        
|                                                                            | Net cash provided by (used in) financing activities |                          |        

---



The
following tables set forth selected information for the Company's gas and oil sales volumes and the proved reserves for each of the years shown.

|                               |                             | Years Ended December 31,
|------------------------------ | --------------------------- | ------------------------
|
|Volumes sold:                  |                             |                         
|                               | Gas (Mmcf)                  |                         
|                               | Oil (MBbls)                 |                         
|                               | Natural Gas Liquids (MBbls) |                         
|Proved reserves at period end: |                             |                         
|                               | Gas (Mmcf)                  |                         
|                               | Oil (MBbls)                 |                         
|                               | Natural Gas Liquids (MBbls) |                         

ITEM 7.Management's Discussion and Analysis of Financial Condition and Results of Operations



The discussion and analysis of the Company's financial condition and results of operations was based upon the consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that
affect the reported amounts of assets, liabilities, revenues and expenses. The Company's significant accounting policies are described in the notes to our consolidated financial statements. The
Company has identified certain of these policies as being of particular importance to the portrayal of the Company's financial position and results of operations and which require the application of
significant judgment by management. The Company analyzes its estimates, including those related to the accounting for oil and gas revenues, bad debts, oil and gas properties, marketable securities,
income taxes, derivatives, contingencies and litigation, and bases its estimates on historical experience and various other assumptions that the Company believes to be reasonable under the
circumstances. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies relate to the more significant
judgments and estimates used in the preparation of the Company's financial statements:



The Company accounts for its natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this
method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Gas and oil lease acquisition costs are also capitalized. Exploration
costs, including personnel costs, certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially
capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a
cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized
for all other sales of producing properties.

The
application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory
which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling


operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are
assumed to be productive and actually deliver gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have
targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. The evaluation of gas and oil leasehold
acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also
effectively condemn leasehold positions.

The
successful efforts method of accounting can have a significant impact on the operational results reported when the Company is entering a new exploratory area in hopes of finding a
gas and oil field that will be the focus of future development drilling activity. Any initial exploratory wells that are unsuccessful are expensed. Seismic costs can be substantial which will result
in additional exploration expenses when incurred.



The Company's estimates of gas, oil and natural gas liquids reserves, by necessity, are projections based on geologic and engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective
process of estimating underground accumulations of gas and oil and the recovery factor for each accumulation, both of which are difficult to measure. The accuracy of any reserve estimate is a function
of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas, oil and natural gas liquids reserves and future net cash flows
necessarily depend upon a number of variable factors and assumptions, such as historical production from the area, the assumed effects of regulations by governmental agencies and assumptions governing
future gas, oil and natural gas liquids prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The
future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these
reasons, estimates of the economically recoverable quantities of gas, oil and natural gas liquids attributable to any particular group of properties, classifications of such reserves based on risk of
recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of
the reserves, which could affect the carrying value of the Company's gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures
with respect to the Company's reserves will likely vary from estimates, and such variances may be material.



The Company reviews its gas and oil properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value.
The Company estimates the expected undiscounted future cash flows of its gas and oil properties and compares such future cash flows to the carrying amount of the gas and oil properties to determine if
the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the gas and oil properties to their fair
value. The factors used to determine fair value include estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate
commensurate with the risk associated with realizing the expected cash flows projected. There were no impairments of producing gas and oil properties in 2002, 2001 or 2000.

Given
the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require the Company to
record an impairment of the recorded book values associated with gas and oil properties. In 1998, the Company recognized an impairment of $51.3 million primarily as a result of the low market
prices in effect at that time; similar impairments may be required in the future. See "Risk Factors."



The Company periodically hedges a portion of its gas and oil production through swap and collar agreements. The purpose of the hedges is to provide a measure of
stability to the Company's cash flows in an environment of volatile gas and oil prices and to manage the exposure to commodity price risk. The Company recognizes all derivative instruments as assets
or liabilities in the balance sheet at fair value. For cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item
is recognized in earnings. For derivative instruments that do not qualify as hedges, changes in fair value are recognized in earnings currently.

The
estimation of fair values for the Company's hedging derivatives requires substantial judgment. The fair values of the Company's derivatives are estimated on a monthly basis using an
option-pricing model. The option-pricing model uses various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, volatility and the time
value of options. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differentials and interest rates.



The following analysis of operations for the years ended December 31, 2002, 2001 and 2000 should be read in conjunction with the Consolidated
Financial Statements and associated footnotes included in this 10-K.

The
Company operates in three segments: (i) gas and oil exploration and development in the United States and Canada, (ii) marketing, gathering and processing and
(iii) drilling. The revenue and segment profit attributable to each reportable segment are set forth in Note 12Segment Information in the Notes to the Company's Consolidated
Financial Statements. The factors that individually influenced the reported results of each of these business segments are set forth below.

Excluding
the cumulative effect of changes in accounting principles, the Company realized net income for the year ended December 31, 2002 of $9.9 million or $.25 per share
(diluted basis) as compared to net income of $67.5 million or $1.68 per share (diluted basis) for the same period in 2001. The majority of this decrease was attributable to lower commodity
prices in 2002. The Company realized net income of $65.7 million or $1.76 per share (diluted basis) in the year ended December 31, 2000. The majority of the Company's production is
natural gas and these general earnings trends were impacted significantly by the natural gas prices in effect each of these periods. The average realized natural gas price for 2002, 2001 and 2000 was
$2.19 per Mcf, $3.71 per Mcf and $3.46 per Mcf, respectively.

The
net loss and net income recognized in the years ended December 31, 2002 and 2001 were both impacted by the adoption of new accounting principles during these periods.
On January 1, 2002, the Company adopted the new accounting standard SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS No. 142). The Company conducted a fair value based
test effective January 1, 2002 to evaluate the goodwill originally recorded in conjunction with the January 2001 Stellarton Energy Corporation acquisition. The fair value of the
reporting unit was determined with reference to the estimated discounted future net revenues of the underlying gas and oil reserves as of the date of the test and other financial considerations
including going-concern value. This test resulted in the Company recording a non-cash charge of $18.1 million in the quarter ended March 31, 2002. The year ended


December 31, 2001 was similarly impacted by the adoption of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities effective January 1, 2001 for which a
$2.0 million gain (net of tax) was recognized.



During 2002, revenues from gas, oil and natural gas liquids production decreased 29% to $194.3 million, as compared to $274.0 million in 2001. This
decrease was the result of (i) a decrease in average gas prices realized by the Company from $3.71 per Mcf in 2001 to $2.19 per Mcf in 2002, which decreased revenues $109.7 million,
(ii) a decrease in average oil and natural gas liquids prices received from $17.86 to $16.35 which decreased revenues $3.4 million partially offset by, (iii) an increase in gas
sales volumes of 13% to 72 Bcf which increased revenues by $31.0 million, and (iv) an increase in oil and natural gas liquids sales volumes of 6% to 2.2 million barrels, which
increased revenues by $2.4 million.

Revenues
in 2002 were not materially impacted by hedging activities.

During
2001, revenues from gas, oil and natural gas liquids production increased 26% to $274.0 million, as compared to $217.0 million in 2000. This increase was the result
of (i) an increase in average gas prices received by the Company from $3.46 per Mcf in 2000 to $3.71 per Mcf in 2001, which increased revenues $16.0 million, (ii) a decrease in
average oil and natural gas liquids prices received from $21.49 to $17.86 which decreased revenues $7.6 million, (iii) an increase in gas sales volumes of 25% to 63.8 Bcf which increased
revenues by $43.7 million, and (iv) an increase in oil and natural gas liquids sales volumes of 14% to 2.1 million barrels, which increased revenues by $4.9 million.

Revenues
in 2001 were also impacted by cash gains realized from hedging activities. The NYMEX collar and swap transactions considered effective hedges and settled in 2001, resulted in
realized gains of $15.9 million, which were included in gas and oil sales. There was no material hedging activity in 2000.

The
revenues contributed by the Stellarton transaction for the period subsequent to the closing date of January 12, 2001 were $30.1 million in 2001 and $27.8 million
in 2002.



The
following table reflects the Company's revenues, average prices received for gas and oil, and amount of gas and oil production in each of the years shown:

|          |                                     | Years Ended December 31,
|--------- | ----------------------------------- | ------------------------
|
|
|Revenues: |                                     |                         
|          | Natural gas sales                   |                         
|          | Crude oil sales                     |                         
|          | Natural gas liquids                 |                         
|          | Gathering and processing            |                         
|          | Marketing and trading, net          |                         
|          | Drilling                            |                         
|          | Cash (paid) received on derivatives |                         
|          | Change in derivative fair value     |                         
|          | Gain on sale of property            |                         
|          | Interest income and other           |                         
|          |                                     |                         
|          | Total revenues                      |                         
|          |                                     |                         

|                                               |  | Years Ended December 31,
|---------------------------------------------- |  | ------------------------
|
|Natural gas production (Mmcf)                  |  |                         
|Crude oil production (MBbls)                   |  |                         
|Natural gas liquid production (MBbls)          |  |                         
|Average natural gas sales price ($/Mcf)        |  | $                       
|Average crude oil sales price ($/Bbl)          |  | $                       
|Average natural gas liquid sales price ($/Bbl) |  | $                       

Gathering
and processing revenues decreased 12% to $20.5 million in 2002 compared to $23.2 million in 2001. A number of non-strategic gathering and processing
assets were sold throughout 2001 resulting in the decrease in gathering and processing revenue in 2002. In 2001, gathering and processing revenue increased 27% to $23.2 million, as compared to
$18.3 million in 2000. This increase was attributable to the distribution of certain gathering and processing assets to the Company from Wildhorse Energy Partners, LLC ("Wildhorse") in
November 2000. Incremental revenues were
recognized in 2001 as a result of the 100% ownership of these gathering and processing assets which previously were 45% owned by the Company through the Wildhorse partnership.

Net
marketing and trading income increased to $5.3 million in 2002 from a net margin of $1.9 million in 2001 and $5.8 million in 2000. Income increased in 2002 due
to the Company transporting gas into the Mid Continent region to take advantage of higher gas prices in this market. Net marketing and trading income has increased principally as a result of this
marketing opportunity that utilized the Company's firm transportation. Although this marketing differential increased marketing and trading income, the Company had previously entered into certain
financial instruments to lock the basis differential for the June through October contract periods in the Mid Continent market. As these financial instruments were considered trading
derivatives under SFAS No. 133, the cash settlements of $2.1 million in 2002 were recognized as derivative losses during the year ended December 31, 2002. The cash profits
realized on the physical sales included in marketing and trading income were partially offset by the $2.1 million cash settlement on the trading derivatives. However, the net impact of these
transactions for 2002 was that the Company was successful in realizing an additional $.29 Mmbtu margin (after transportation costs) on gas moved into the Mid Continent region. The marketing and
trading margins in 2000 benefited from certain term and spot marketing arrangements at more favorable terms than were available in the 2001 market.





Drilling revenue associated with the Company's wholly-owned subsidiary, Sauer, remained relatively unchanged in 2002 at $14.3 million. In 2002 Sauer generated a higher percentage
of its contract drilling revenue from third-party contracts not affiliated with Tom Brown. Contract drilling revenues associated with wells operated by the Company and drilled by Sauer are eliminated
in consolidation. This change in mix for 2002 resulted in essentially equivalent drilling revenues for 2002 and 2001 despite a decrease in the rig utilization rates from over 90% in 2001 to
approximately 70% in 2002. Drilling revenue increased from $11.5 million in 2000 to $14.8 million in 2001 due to higher rig utilization rates and increased day rates resulting from the
general increase in activity within the oil and gas industry in 2001 as compared to 2000.



Expenses related to gas and oil production remained flat from 2001 to 2002. On an Mcfe basis, gas and oil production costs decreased to $.38 in 2002 from $.42 in
2001 as a result of a continued focus on cost containment.

Expenses
related to gas and oil production increased 26% from 2000 to 2001 due primarily to the Stellarton acquisition and increased production levels in 2001. On an Mcfe basis, gas and
oil production costs remained relatively flat at $.42 in 2001 and $.41 in 2000.

Taxes
on gas and oil production decreased by 21% or ($4.4 million) in 2002 primarily due to a 29% or ($80 million) decrease in revenue from gas, oil and natural gas liquids
from 2001 due to lower natural gas and natural gas liquids commodity prices.

Taxes
on gas and oil production decreased by 5% or ($1.1 million) in 2001 despite a 26% or ($57 million) increase in revenue from gas, oil and natural gas liquids for 2001.
This resulted from the inclusion of $30.1 million of Canadian revenues in the 2001 results which are not subject to severance and other taxes typically incurred in the United States.
Additionally, $15.9 million realized on the natural gas hedge transactions was included in gas and oil sales in 2001 which is not subject to production related taxes. The Company also obtained
a refund in 2001 of a portion of the production taxes paid in prior years which reduced the expenses reported.

Depreciation,
depletion and amortization increased $16.9 million in 2002 as compared to 2001. The production increase of 12% on a Mcfe basis for 2002 contributed
$8.8 million to the increased depreciation, depletion and amortization. The Company's per unit depletion rate also increased in 2002 as a result of higher finding costs on the gas and oil
reserve additions associated with the 2002 and 2001 capital programs. In 2002, depreciation, depletion and amortization expense on the producing gas and oil properties was $.95 per Mcfe as compared to
$.83 per Mcfe in 2001.

Depreciation,
depletion and amortization increased $24.0 million in 2001 as compared to 2000. Approximately $14.1 million of this increase was associated with the depletion
recorded on the Stellarton assets acquired in January 2001. The production increase of 9% on a Mcfe basis on the domestic properties for 2001 also increased depreciation, depletion and
amortization.

Gathering
and processing costs principally represent costs associated with operating and maintaining the field systems. The $3.9 million decrease in gathering and processing costs
for 2002 was caused by the Company's disposition of a number of the gathering and processing assets in 2001 which were considered non-strategic to the Company's operations.

Expenses
associated with the Company's exploration activities were $22.8 million, $34.2 million and $11.0 million for the years 2002, 2001 and 2000,
respectively. Exploration expense for these periods was impacted by the dry hole costs of $7.8 million, $15.8 million and $1.2 million recognized in 2002, 2001 and 2000,
respectively. The Company also incurred additional seismic costs in 2001 which were primarily associated with the James Lime and Deep Valley projects in Texas that contributed to the increased
exploration expense incurred in that period. Capital expenditures of $161.7 million were


incurred in 2002 compared to $358.1 million in 2001, which included $95 million associated with the Stellarton Acquisition. The 2002 exploration, development and land related
expenditures were $139 million, a decrease of 43% in comparison to 2001. In 2000, the exploration, development and land related expenditures were $109.6 million. The Company's capital
program budgets are influenced by the gas and oil prices received for its production. The exploration expenses recognized by the Company are influenced by the magnitude of the capital expenditures
incurred in each year. Capital programs are risk adjusted to balance exploration and development opportunities.

Recurring
general and administrative expenses have increased from year to year as a result of the Company's increased level of operations. On an Mcfe basis, general and administrative
expenses were $.22, $.30, and $.19 for the years 2002, 2001 and 2000, respectively. Included in the expenses for 2001 was a $5.3 million ($.07 per Mcfe) pre-tax charge
recorded in the first quarter of 2001 associated with the retirement of Donald L. Evans, the Company's former Chairman and CEO. Mr. Evans received a $1.5 million retirement payment and
the Company recognized a $3.8 million non-cash charge in conjunction with the acceleration of Mr. Evans' stock options. General and administrative expenses related to the new
Canadian operations contributed $2.0 million ($.02 per Mcfe) to the increase in 2002 and $2.5 million ($.03 per Mcfe) for 2001. Expenses also
increased due to the addition of personnel necessary to implement the increased capital expenditure programs in 2001 and 2002.

Bad
debt expense increased in 2002 as a result of a default by a previous purchaser of the Company's natural gas liquids in the Paradox Basin of Colorado and Utah on payments owed the
Company totaling $6.2 million. An allowance for this entire receivable was recorded in the third quarter of 2002 given the uncertainty of collection at that time. The Company continued to
aggressively pursue recovery of the amount owed and in the fourth quarter of 2002, a $1.4 million settlement was received in cash. The collection of this settlement was treated as an adjustment
to the allowance originally recorded. As of December 31, 2002, the Company does not anticipate that any future settlements will be received that will materially reduce the loss recognized as a
result of this purchaser's default.

Interest
and other expense in 2002 was impacted by standby fees incurred under the terms of a two-year commitment for a drilling rig utilized by the Company at the Deep
Valley project in West Texas. This rig became available in 2002 and $1.6 million of standby fees were charged to expense when the rig was not being utilized. Interest expense also increased in
2001 and 2002 after the Stellarton acquisition in January 2001 for which $95 million in debt was incurred. The Company's effective interest rate under its credit facility was 3.9% at
December 31, 2002 and 4.1% at December 31, 2001.

The
Company recorded income tax provisions of $3.2 million, $38.1 million and $39.8 million in 2002, 2001, and 2000, respectively, resulting in effective tax rates
of 24.4%, 36.1% and 37.4%, respectively. The 2002 income tax provision of $3.2 million was impacted by a $1.6 million tax reduction associated with certain Canadian expenses deductible
in the United States and by $0.7 million in state tax credits associated with drilling incentives in Colorado and Utah. There was no tax impact associated with the goodwill impairment recorded
in conjunction with the change in accounting principle as goodwill is not considered a deductible expense for tax purposes. At December 31, 2002, the Company has a net operating loss
carryforward available for U.S. Federal tax purposes of $25.9 million and a net operating loss carryforward available to reduce future Canadian federal income taxes of $6.0 million
($9.4 million CDN). Additionally, statutory depletion carryforwards of approximately $7.2 million and $4.8 million of alternative minimum tax credit carryforwards are available in
the U.S. to offset future taxes. Based upon the operating results for 2002 and the present economic environment for the gas and oil industry, the Company believes that it will generate sufficient
taxable income to utilize these carryforwards.



The Company continues to pursue opportunities which will add value by economically increasing its reserve base and presence in significant natural gas areas, and
further developing the Company's ability to control and market the production of natural gas. As the Company continues to evaluate potential acquisitions and property development opportunities, it
will benefit from its financing flexibility and the leverage potential of the Company's overall capital structure.



The Company's capital and exploration expenditures and sources of financing for the years ended December 31, 2002, 2001 and 2000 are as follows:

|                                           |                                 | 2002 |       | 2001 |   | 2000  |     
|------------------------------------------ | ------------------------------- | ---- | ----- | ---- | - | ----- | ----
|
|CAPITAL AND EXPLORATION EXPENDITURES:      |                                 |      |       |      |   |       |     
|ACQUISITIONS:                              |                                 |      |       |      |   |       |     
|                                           | Stellarton                      |      | $     |     |   | $     | 95.0
|                                           | Rocky Mountain assets and other |      |       | 15.9 |   |       | 3.3 
|Exploration costs                          |                                 |      | 33.2  |      |   | 56.0  |     
|Development costs                          |                                 |      | 94.6  |      |   | 163.2 |     
|Acreage                                    |                                 |      | 10.9  |      |   | 22.6  |     
|Gas gathering and processing               |                                 |      | 4.7   |      |   | 9.3   |     
|Sauer Drilling Company                     |                                 |      | .9    |      |   | 5.2   |     
|Other                                      |                                 |      | 1.5   |      |   | 3.5   |     
|                                           |                                 |      |       |      |   |       |     
|                                           |                                 | $    | 161.7 |      | $ | 358.1 |     
|                                           |                                 |      |       |      |   |       |     
|FINANCING SOURCES:                         |                                 |      |       |      |   |       |     
|Common stock issued                        |                                 | $    | 2.2   |      | $ | 11.2  |     
|Net long term bank debt                    |                                 |      | 11.8  |      |   | 55.8  |     
|Debt assumed on Stellarton transaction     |                                 |      |      |      |   | 16.8  |     
|Proceeds from sale of assets               |                                 |      | 10.8  |      |   | 52.4  |     
|Cash flow provided by operating activities |                                 |      | 121.6 |      |   | 207.9 |     
|Other                                      |                                 |      | 15.3  |      |   | 14.0  |     
|                                           |                                 |      |       |      |   |       |     
|                                           |                                 | $    | 161.7 |      | $ | 358.1 |     
|                                           |                                 |      |       |      |   |       |     

The
Company anticipates capital and exploration expenditures between $155 to $185 million in 2003, approximately 90% of which will be allocated to exploration and development
activity. The timing of most of the Company's capital expenditures is discretionary and there are no material long-term commitments associated with the Company's capital expenditure plans.
Consequently, the Company is able to adjust the level of its capital expenditures as circumstances warrant. The level of capital expenditures by the Company will vary in future periods depending on
energy market conditions and other related economic factors.

Historically,
the Company has funded capital expenditures and working capital requirements with both internally generated cash, borrowings and stock transactions.



In April 2002, the Company sold its interest in oil and gas properties located in the Powder River Basin of Wyoming to an unrelated third party for net
cash proceeds of $7.2 million. These properties had a net book value of $3.1 million, which resulted in a $4.1 million gain on the sale.

In
April 2002, the Company also sold certain oil and gas properties located primarily in Louisiana to an unrelated third party for $2.0 million. In November 2002,
the Company sold certain oil and gas properties located in Colorado to an unrelated third party for $1.6 million. As these sales represented partial interests in these proved properties, the
proceeds were recorded as a reduction to the recorded cost of the oil and gas properties.

In
2001, $52.4 million in cash proceeds were derived from property sales. In May 2001, the Company sold its interest in gas and oil properties located in Oklahoma to an
unrelated third party. These properties had a net book basis of $14.4 million. This transaction resulted in a gain of $10.l million with net cash proceeds of $24.5 million. Cash
proceeds of $24 million were also realized in conjunction with several sales transactions in 2001 associated with the disposition of gathering and processing facilities received in the
Wildhorse distribution in November 2000. As the systems sold were non-strategic to the Company's operations and these divestitures were anticipated as part of the Wildhorse
integration process, the proceeds derived on these transactions were recorded as a reduction to the investment in the gathering assets.



In addition to the bank credit facility discussed in the following note, the Company had various other contractual obligations as of December 31, 2002. The
Company has no off-balance sheet debt or other such unrecorded obligations and the Company has not guaranteed the debt of any other party. The following table lists the Company's
significant liabilities at December 31, 2002 including the credit facility:

|                           |                                    | Payments Due by Period
|-------------------------- | ---------------------------------- | ----------------------
|
|
|Bank credit facility       |                                    | $                     
|Operating leases           |                                    |                       
|Transportation commitments |                                    |                       
|Processing commitment      |                                    |                       
|Drilling rig obligation    |                                    |                       
|                           |                                    |                       
|                           | Total contractual cash obligations |                       
|                           |                                    |                       

The
Company leases its corporate office in Denver, Colorado under the terms of an operating lease, which expires in January 2004. Yearly payments under the lease are approximately
$1,061,000 net of sublease income. The Company's offices in Midland, Texas represents a commitment of $215,000 per year through December 2003 and the office lease in Calgary, Alberta expires in
August 2004 at a rate of $152,000 per year. The remaining operating lease commitments represent equipment leases, which expire during 2002 through 2008.

The
Company has entered into various firm transportation commitments for approximately 56.8 Mmcf of gross gas sales per day as of December 31, 2002. The majority of these
contracts expire in 2003 through 2006. Subsequent to December 31, 2002, the Company entered into additional firm transportation commitments on approximately 29 Mmcf of gross gas sales per day
under varying terms


that expire in 2008 and 2011. These 2003 commitments totaled $19.6 million and are not included in the above schedule.

On
December 31, 2001, the Company entered into an agreement with an unrelated third party to process its gas production from the White River Dome coal bed methane project in the
Piceance Basin. Under the terms of this agreement, the Company is obligated to pay the third party $220,000 per month over the ten year term to cover the fixed operating costs of the plant and provide
for a recovery of the plant investment to the third party. The Company is also obligated to reimburse the third party
for certain variable expenses associated with the volumes processed through the plant and for compression made available to the Company. The Company has the right but not the obligation to purchase
the processing facility from the third party during the term of this agreement upon 60 days prior written notice of its election to purchase the facilities.

To
assure the availability of a drilling rig in conjunction with an exploration program in west Texas, the Company entered into a two-year commitment with a drilling
contractor in 2001. The rig became available in 2002 and the two-year drilling obligation commenced on May 29, 2002. Under the terms of this arrangement, the Company is required to
pay a day rate of $20,100 per day during drilling operations and $16,700 per day for rig moves.



On June 30, 2000, the Company entered into a $125 million credit facility (the "Credit Facility") that was to mature in June 2003. Under the
terms of the Credit Facility, the borrowing base was established at $225 million.

On
March 20, 2001, as part of the final financing of the Stellarton acquisition, the Company repaid and cancelled its previous $125 million Credit Facility and entered into
a new $225 million credit facility (the "Global Credit Facility"). The Global Credit Facility is comprised of: a $75 million line of credit in the U.S. and a $55 million line of
credit in Canada which both mature in March 2004, and a $95 million five-year term loan in Canada. The borrowing base under the Global Credit Facility was set at
$300 million. The Global Credit Facility allows the lenders one scheduled redetermination of the borrowing base each December. In addition, the lenders may elect to require one unscheduled
redetermination in the event the borrowing base utilization exceeds 50% of the borrowing base at any time for a period of 15 consecutive business days. At December 31, 2002, the Company
had borrowings outstanding under the Global Credit Facility totaling $133.2 million or 44% of the borrowing base at an average interest rate of 3.9% The amount available for borrowing under the
Global Credit Facility at December 31, 2002 was $91.8 million.

Borrowings
under the Global Credit Facility are unsecured and bear interest, at the election of the Company, at a rate equal to (i) the greater of the global administrative agents
prime rate or the federal funds effective rate plus an applicable margin, (ii) adjusted LIBOR for Eurodollar loans plus applicable margin, or (iii) Bankers' Acceptances plus applicable
margin for Canadian dollar loans. Interest on amounts outstanding under the Global Credit Facility is due on the last day of each quarter for prime based loans, and in the case of Eurodollar loans
with an interest period of more than three months, interest is due at the end of each three month interval.

The
Global Credit Facility contains certain financial covenants that require the Company to maintain a minimum consolidated tangible net worth of not less than $350 million
(adjusted upward by 50% of quarterly net income subsequent to March 31, 2001 and 50% of the net cash proceeds of any stock offering). The Company must also maintain a ratio of indebtedness to
earnings before interest expense, state and federal taxes and depreciation, depletion and amortization expense and exploration expense of not more than 3.0 to 1.0 as calculated at the end of each
fiscal quarter. The Company was in compliance with all covenants during 2002 and at December 31, 2002.



The Company's revenues and associated cash flows are significantly impacted by changes in gas and oil prices. All of the Company's gas and oil production is
currently market sensitive as none of the Company's gas and oil production has been presold at contractually specified prices. During 2002, the average prices received for gas and oil by the Company
were $2.19 per Mcf and $16.35 per barrel, respectively, as compared to $3.71 Mcf and $17.86 per barrel in 2001 and $3.46 per Mcf and $21.49 per barrel in 2000.



In connection with a review of the Company's financial statements by the staff of the Securities and Exchange Commission, the Company has been made aware that an
issue has arisen within the industry regarding the application of provisions of Statement of Financial Accounting Standards No. 141, "Business Combinations," and Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142), to companies in the extractive industries, including gas and oil companies. The issue is whether SFAS
No. 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart
from other capitalized gas and oil property costs. Historically, the Company and other gas and oil companies have included the cost of these gas and oil leasehold interests as part of gas and oil
properties. Also under consideration is whether SFAS No. 142 requires registrants to provide the additional disclosures prescribed by SFAS No. 142 for intangible assets for costs
associated with mineral rights.

If
it is ultimately determined that SFAS No. 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the
amounts that would be reclassified are as follows:

|                                     |                                   | December 31,
|------------------------------------ | --------------------------------- | ------------
|
|
|INTANGIBLE ASSETS:                   |                                   |             
|Proved leasehold acquisition costs   |                                   | $           
|Unproved leasehold acquisition costs |                                   |             
|                                     |                                   |             
|                                     | Total leasehold acquisition costs |             
|Less: Accumulated depletion          |                                   |             
|                                     |                                   |             
|                                     | Net leasehold acquisition costs   |             
|                                     |                                   |             

The
reclassification of these amounts would not effect the method in which such costs are amortized or the manner in which the Company assesses impairment of capitalized costs. As a
result, net income would not be affected by the reclassification.

ITEM 7A.Quantitative and Qualitative Disclosure About Market Risk



The Company's results of operations are highly dependent upon the prices received for oil and natural gas production. Accordingly, in order to increase the
financial flexibility and to protect the Company against commodity price fluctuations, the Company may, from time to time in the ordinary course of business, enter into hedging arrangements, including
commodity swap agreements, forward sale contracts, commodity futures, options and other similar agreements relating to natural gas and crude oil expected to be produced. The Company has also entered
into certain financial instruments that did not qualify as hedging arrangements. These transactions have principally involved basis


contracts entered into to secure a pricing differential into markets where the Company has transportation agreements.

Financial
instruments designated as hedges are accounted for on the accrual basis with gains and losses being recognized based on the type of contract and exposure being hedged. Gains
and losses on natural gas and crude oil swaps designated as hedges of anticipated transactions, including gains or losses recognized upon early termination of contracts, are deferred and recognized in
income when the associated hedged commodities are produced. In order for natural gas and crude oil swaps or collars to qualify as a hedge of an anticipated transaction, the derivative contract must
identify the expected date of the transaction, the commodity involved, and the expected quantity to be purchased or sold among other requirements. In the event that it becomes probable that a hedged
transaction will not occur, gains and losses, including gains or losses upon early termination of contracts, are included in the income statement.

The
Company has natural gas hedges, in the form of costless collars and swaps (including related basis swaps), as follows as of December 31, 2002:

|                    |  | Natural Gas Collars |  | Natural Gas Swaps
|------------------- |  | ------------------- |  | -----------------
|
|First Quarter 2003  |  | 37,500              |  | $3.82/5.01       
|Second Quarter 2003 |  | 40,000              |  | $3.37/4.65       
|Third Quarter 2003  |  | 40,000              |  | $3.37/4.65       
|Fourth Quarter 2003 |  | 23,500              |  | $3.27/4.61       

The
Company also entered into certain financial instruments to lock the basis differential on 15,000 Mmbtu/day of firm transportation volumes during the June through
October contract periods of 2002. These contracts effectively fixed a price differential into the Mid Continent market at a weighted average price of $0.78 above the price index for a delivery
point in the Rocky Mountain area where the Company markets a significant portion of its natural gas production. Under SFAS 133, these basis swaps did not qualify for hedge accounting.
Accordingly, these basis swaps resulted in the recognition of derivative losses of $2.1 million in 2002 which were recorded directly to earnings.



At December 31, 2002, the Company had $133.2 million outstanding under the Global Credit Facility at an average interest rate of 3.9%. Borrowings
under the Global Credit Facility bear interest, at the election of the Company, at (i) the greater of the agent bank's prime rate or the federal funds effective rate, plus an applicable margin
or (ii) the agent bank's Eurodollar rate, plus an applicable margin. As a result, the Company's annual interest cost in 2003 will fluctuate based on short-term interest rates.
Assuming no change in the amount outstanding during 2003, the impact on interest expense of a ten percent change in the average interest rate would be approximately $.5 million. As the interest
rate is variable and is reflective of current market conditions, the carrying value of the Global Credit Facility approximates the fair value.



The Company conducts business in Canada where the Canadian dollar has been designated as the functional currency. This subjects the Company to foreign currency
exchange risk on cash flows related to sales, expenses, financing and investing transactions. The Company has not entered into any foreign currency forward contracts or other similar financial
instruments to manage this risk.



ITEM 8.Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



|                                                                                                        
|--------------------------------------------------------------------------------------------------------
|Independent Auditors' Report                                                                            
|Report of Independent Public Accountants                                                                
|Consolidated Balance Sheets, December 31, 2002 and 2001                                                 
|Consolidated Statements of Operations, Years ended December 31, 2002, 2001 and 2000                     
|Consolidated Statements of Changes in Stockholders' Equity, Years ended December 31, 2002, 2001 and 2000
|Consolidated Statements of Cash Flows, Years ended December 31, 2002, 2001 and 2000                     
|Notes to Consolidated Financial Statements                                                              



Independent Auditors' Report

The
Board of Directors and Stockholders
Tom Brown, Inc.:

We
have audited the 2002 consolidated financial statements of Tom Brown, Inc. (a Delaware corporation) and subsidiaries as listed in the accompanying index. These consolidated
financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. The 2001 and 2000
consolidated financial statements of Tom Brown, Inc. and subsidiaries as listed in the accompanying index were audited by other auditors who have ceased operations. Those auditors' report,
dated February 27, 2002, on those consolidated financial statement was unqualified and included an explanatory paragraph that described the change in the Company's method of accounting for
derivative instruments and hedging activities discussed in Notes 2 and 9 to the consolidated financial statements.

We
conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation
We believe that our audit provides a reasonable basis for our opinion.

In
our opinion, the 2002 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Tom Brown, Inc. and subsidiaries
as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of
America.

As
discussed in Notes 2 and 3 to the consolidated financial statements, the Company changed its method of accounting for goodwill and other intangible assets in 2002, and as discussed in
Notes 2 and 9 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities in 2001.

| |  | KPMG LLP
| |  | --------

Denver,
Colorado
February 20, 2003



REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

THE FOLLOWING REPORT IS A COPY OF THE PREVIOUSLY ISSUED REPORT FROM ARTHUR ANDERSEN LLP (ANDERSEN). ANDERSEN DID NOT PERFORM ANY PROCEDURES IN CONNECTION WITH THIS ANNUAL
REPORT ON FORM 10-K NOR HAS ANDERSEN PROVIDED A CONSENT TO THE INCLUSION OF ITS REPORT IN THIS FORM 10-K. FOR FURTHER DISCUSSION, SEE EXHIBIT 23.2 TO THE FORM 10-K OF
WHICH THIS REPORT FORMS A PART. ACCORDINGLY, THIS REPORT HAS NOT BEEN REISSUED BY ANDERSEN.

To the Board of Directors and Stockholders of Tom Brown, Inc.:

We have audited the accompanying consolidated balance sheets of Tom Brown, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2001
and 2000, and the related consolidated statements of operations, changes in stockholders' equity and cash flows for each of the three years in the period ended December 31, 2001. 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 in accordance with auditing standards generally accepted in the 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.

In
our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Tom Brown, Inc. and subsidiaries as of
December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with
accounting principles generally accepted in the United States.

As
explained in Notes 2 and 10 to the consolidated financial statements, on January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging
activities.

| |  | ARTHUR ANDERSEN LLP
| |  | -------------------

Denver,
Colorado
February 27, 2002





TOM BROWN, INC. AND SUBSIDIARIES        CONSOLIDATED BALANCE SHEETS

|                                        |                                                                                                                                  | December 31,                 |        
|--------------------------------------- | -------------------------------------------------------------------------------------------------------------------------------- | ---------------------------- | -------
|
|
|ASSETS                                  |                                                                                                                                  |                              |        
|CURRENT ASSETS:                         |                                                                                                                                  |                              |        
|                                        | Cash and cash equivalents                                                                                                        |                              | $      
|                                        | Accounts receivable, net of allowance for doubtful accounts                                                                      |                              |        
|                                        | Inventories                                                                                                                      |                              |        
|                                        | Other                                                                                                                            |                              |        
|                                        |                                                                                                                                  |                              |        
|                                        |                                                                                                                                  | Total current assets         |        
|                                        |                                                                                                                                  |                              |        
|PROPERTY AND EQUIPMENT, AT COST:        |                                                                                                                                  |                              |        
|                                        | Gas and oil properties, successful efforts method of accounting                                                                  |                              |        
|                                        | Gas gathering and processing and other plant                                                                                     |                              |        
|                                        | Other                                                                                                                            |                              |        
|                                        |                                                                                                                                  |                              |        
|                                        |                                                                                                                                  | Total property and equipment |        
|                                        | Less: Accumulated depreciation, depletion and amortization                                                                       |                              |        
|                                        |                                                                                                                                  |                              |        
|                                        |                                                                                                                                  | Net property and equipment   |        
|                                        |                                                                                                                                  |                              |        
|OTHER ASSETS:                           |                                                                                                                                  |                              |        
|                                        | Goodwill, net                                                                                                                    |                              |        
|                                        | Other assets                                                                                                                     |                              |        
|                                        |                                                                                                                                  |                              |        
|                                        |                                                                                                                                  | $                            | 850,952
|                                        |                                                                                                                                  |                              |        
|LIABILITIES AND STOCKHOLDERS' EQUITY    |                                                                                                                                  |                              |        
|CURRENT LIABILITIES:                    |                                                                                                                                  |                              |        
|                                        | Accounts payable                                                                                                                 |                              | $      
|                                        | Accrued expenses                                                                                                                 |                              |        
|                                        | Fair value of derivative instruments                                                                                             |                              |        
|                                        |                                                                                                                                  |                              |        
|                                        |                                                                                                                                  | Total current liabilities    |        
|                                        |                                                                                                                                  |                              |        
|BANK DEBT                               |                                                                                                                                  |                              | 133,172
|DEFERRED INCOME TAXES                   |                                                                                                                                  |                              | 73,967 
|OTHER NON-CURRENT LIABILITIES           |                                                                                                                                  |                              | 4,543  
|COMMITMENTS AND CONTINGENCIES (Note 13) |                                                                                                                                  |                              |        
|STOCKHOLDERS' EQUITY:                   |                                                                                                                                  |                              |        
|                                        | Convertible preferred stock, $.10 par value
Authorized 2,500,000 shares; none issued                                             |                              |        
|                                        | Common Stock, $.10 par value
Authorized 55,000,000 shares; Issued and outstanding 39,261,191 and 39,127,649 shares, respectively |                              |        
|                                        | Additional paid-in capital                                                                                                       |                              |        
|                                        | Retained earnings                                                                                                                |                              |        
|                                        | Accumulated other comprehensive loss                                                                                             |                              |        
|                                        |                                                                                                                                  |                              |        
|                                        |                                                                                                                                  | Total stockholders' equity   |        
|                                        |                                                                                                                                  |                              |        
|                                        |                                                                                                                                  | $                            | 850,952
|                                        |                                                                                                                                  |                              |        

See
accompanying notes to consolidated financial statements.



TOM BROWN, INC. AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF OPERATIONS

|                                                                  |                                                                   | Years Ended December 31,                                                           |        
|----------------------------------------------------------------- | ----------------------------------------------------------------- | ---------------------------------------------------------------------------------- | -------
|
|
|REVENUES:                                                         |                                                                   |                                                                                    |        
|                                                                  | Gas, oil and natural gas liquids sales                            |                                                                                    | $      
|                                                                  | Gathering and processing                                          |                                                                                    |        
|                                                                  | Marketing and trading, net                                        |                                                                                    |        
|                                                                  | Drilling                                                          |                                                                                    |        
|                                                                  | Gain on sale of properties                                        |                                                                                    |        
|                                                                  | Cash (paid) received on derivatives                               |                                                                                    |        
|                                                                  | Change in derivative fair value                                   |                                                                                    |        
|                                                                  | Loss on marketable security                                       |                                                                                    |        
|                                                                  | Interest income and other                                         |                                                                                    |        
|                                                                  |                                                                   |                                                                                    |        
|                                                                  |                                                                   | Total revenues                                                                     |        
|                                                                  |                                                                   |                                                                                    |        
|COSTS AND EXPENSES:                                               |                                                                   |                                                                                    |        
|Gas and oil production                                            |                                                                   |                                                                                    | 32,151 
|                                                                  | Taxes on gas and oil production                                   |                                                                                    |        
|                                                                  | Gathering and processing costs                                    |                                                                                    |        
|                                                                  | Drilling operations                                               |                                                                                    |        
|                                                                  | Exploration costs                                                 |                                                                                    |        
|                                                                  | Impairments of leasehold costs                                    |                                                                                    |        
|                                                                  | General and administrative                                        |                                                                                    |        
|                                                                  | Depreciation, depletion and amortization                          |                                                                                    |        
|                                                                  | Bad debts                                                         |                                                                                    |        
|                                                                  | Interest expense and other                                        |                                                                                    |        
|                                                                  |                                                                   |                                                                                    |        
|                                                                  |                                                                   | Total costs and expenses                                                           |        
|                                                                  |                                                                   |                                                                                    |        
|                                                                  |                                                                   | Income before income taxes and cumulative effect of change in accounting principle |        
|Income tax provision                                              |                                                                   |                                                                                    |        
|                                                                  | Current                                                           |                                                                                    |        
|                                                                  | Deferred                                                          |                                                                                    |        
|                                                                  |                                                                   |                                                                                    |        
|Income before cumulative effect of change in accounting principle |                                                                   |                                                                                    | 9,926  
|Cumulative effect of change in accounting principle               |                                                                   |                                                                                    | (18,103
|                                                                  |                                                                   |                                                                                    |        
|Net (loss) income                                                 |                                                                   |                                                                                    | (8,177 
|Preferred stock dividends                                         |                                                                   |                                                                                    |       
|                                                                  |                                                                   |                                                                                    |        
|Net (loss) income attributable to common stock                    |                                                                   | $                                                                                  | (8,177 
|                                                                  |                                                                   |                                                                                    |        
|Weighted average number of common shares outstanding:             |                                                                   |                                                                                    |        
|                                                                  | Basic                                                             |                                                                                    |        
|                                                                  |                                                                   |                                                                                    |        
|                                                                  | Diluted                                                           |                                                                                    |        
|                                                                  |                                                                   |                                                                                    |        
|Earnings per common share-Basic:                                  |                                                                   |                                                                                    |        
|                                                                  | Income before cumulative effect of change in accounting principle |                                                                                    | $      
|                                                                  | Cumulative effect of change in accounting principle               |                                                                                    |        
|                                                                  |                                                                   |                                                                                    |        
|Net (loss) income attributable to common stock                    |                                                                   | $                                                                                  | (.21   
|                                                                  |                                                                   |                                                                                    |        
|Earnings per common share-Diluted:                                |                                                                   |                                                                                    |        
|                                                                  | Income before cumulative effect of change in accounting principle |                                                                                    | $      
|                                                                  | Cumulative effect of change in accounting principle               |                                                                                    |        
|                                                                  |                                                                   |                                                                                    |        
|Net (loss) income attributable to common stock                    |                                                                   | $                                                                                  | (.20   
|                                                                  |                                                                   |                                                                                    |        

See
accompanying notes to consolidated financial statements.





TOM BROWN, INC. AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

|                                              |                                                                                   | Preferred Stock |   | Common Stock |      |   |        | Retained
Earnings
(Accumulated
Deficit) |   | Accumulated
Other
Comprehensive
Income (Loss) |   |   |        
|--------------------------------------------- | --------------------------------------------------------------------------------- | --------------- | - | ------------ | ---- | - | ------ | --------------------------------------- | - | --------------------------------------------- | - | - | -------
|
|
|
|Balance as of December 31, 1999               |                                                                                   | 1,000           |   | $            | 100  |   | 35,308 |                                         | $ | 3,531                                         |   | $ | 495,724
|Stock options exercised                       |                                                                                   |                |   |              |     |   | 1,378  |                                         |   | 137                                           |   |   | 17,475 
|Income tax benefit of stock options exercised |                                                                                   |                |   |              |     |   |       |                                         |   |                                              |   |   | 3,779  
|Preferred stock dividends                     |                                                                                   |                |   |              |     |   |       |                                         |   |                                              |   |   |       
|Preferred stock conversion                    |                                                                                   | (1,000          | ) |              | (100 | ) | 1,666  |                                         |   | 167                                           |   |   | (67    
|Comprehensive income (loss):                  |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        
|                                              | Unrealized loss on marketable securities                                          |                 |  |              |      |  |        |                                        |   |                                               |  |   |        
|                                              | Net income                                                                        |                 |  |              |      |  |        |                                        |   |                                               |  |   |        
|                                              |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        
|Total comprehensive income                    |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        
|                                              |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        
|Balance as of December 31, 2000               |                                                                                   |                |   |              |     |   | 38,352 |                                         |   | 3,835                                         |   |   | 516,911
|Stock options exercised                       |                                                                                   |                |   |              |     |   | 776    |                                         |   | 78                                            |   |   | 11,085 
|Income tax benefit of stock options exercised |                                                                                   |                |   |              |     |   |       |                                         |   |                                              |   |   | 2,897  
|Accelerated vesting of options                |                                                                                   |                |   |              |     |   |       |                                         |   |                                              |   |   | 3,897  
|Comprehensive income (loss):                  |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        
|                                              | Translation loss                                                                  |                 |  |              |      |  |        |                                        |   |                                               |  |   |        
|                                              | Cumulative effect of change in accounting principle (net of tax)                  |                 |  |              |      |  |        |                                        |   |                                               |  |   |        
|                                              | Change in fair value of derivative hedging instruments                            |                 |  |              |      |  |        |                                        |   |                                               |  |   |        
|                                              | Settlements of derivative hedging instruments reclassified to income (net of tax) |                 |  |              |      |  |        |                                        |   |                                               |  |   |        
|                                              | Unrealized loss on marketable securities                                          |                 |  |              |      |  |        |                                        |   |                                               |  |   |        
|                                              |                                                                                   | Net income      |   |             |      |   |       |                                         |  |                                               |   |  |        
|                                              |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        
|Total comprehensive income                    |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        
|                                              |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        
|Balance as of December 31, 2001               |                                                                                   |                |   |              |     |   | 39,128 |                                         |   | 3,913                                         |   |   | 534,790
|Stock options exercised                       |                                                                                   |                |   |              |     |   | 133    |                                         |   | 13                                            |   |   | 2,145  
|Income tax benefit of stock options exercised |                                                                                   |                |   |              |     |   |       |                                         |   |                                              |   |   | 514    
|Comprehensive income (loss):                  |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        
|                                              | Translation loss                                                                  |                 |  |              |      |  |        |                                        |   |                                               |  |   |        
|                                              | Unrealized loss on marketable securities reclassified to income                   |                 |  |              |      |  |        |                                        |   |                                               |  |   |        
|                                              | Change in fair value of derivative hedging instruments (net of tax)               |                 |  |              |      |  |        |                                        |   |                                               |  |   |        
|                                              | Unrealized loss on marketable securities                                          |                 |  |              |      |  |        |                                        |   |                                               |  |   |        
|                                              | Settlements of derivative hedging instruments reclassified to income (net of tax) |                 |  |              |      |  |        |                                        |   |                                               |  |   |        
|                                              |                                                                                   | Net loss        |   |             |      |   |       |                                         |  |                                               |   |  |        
|                                              |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        
|Total comprehensive loss                      |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        
|                                              |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        
|Balance as of December 31, 2002               |                                                                                   |                |   | $            |     |   | 39,261 |                                         | $ | 3,926                                         |   | $ | 537,449
|                                              |                                                                                   |                 |   |              |      |   |        |                                         |   |                                               |   |   |        

See accompanying notes to consolidated financial statements.



TOM BROWN, INC. AND SUBSIDIARIES        CONSOLIDATED STATEMENTS OF CASH FLOWS

|                                                                     |                                                                                          | Years Ended December 31,                                                                         |                                                            
|-------------------------------------------------------------------- | ---------------------------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------ | -----------------------------------------------------------
|
|
|CASH FLOWS FROM OPERATING ACTIVITIES:                                |                                                                                          |                                                                                                  |                                                            
|                                                                     | Net (loss) income                                                                        |                                                                                                  | $                                                          
|                                                                     | Adjustments to reconcile net (loss) income to net cash provided by operating activities: |                                                                                                  |                                                            
|                                                                     |                                                                                          | Depreciation, depletion and amortization                                                         |                                                            
|                                                                     |                                                                                          | Unrealized loss on derivatives                                                                   |                                                            
|                                                                     |                                                                                          | Loss on marketable security                                                                      |                                                            
|                                                                     |                                                                                          | Gain on sales of assets                                                                          |                                                            
|                                                                     |                                                                                          | Accelerated vesting of options                                                                   |                                                            
|                                                                     |                                                                                          | Cumulative effect of change in accounting principle                                              |                                                            
|                                                                     |                                                                                          | Deferred tax provision                                                                           |                                                            
|                                                                     |                                                                                          | Dry hole costs                                                                                   |                                                            
|                                                                     |                                                                                          | Impairments of leasehold costs                                                                   |                                                            
|                                                                     |                                                                                          | Changes in operating assets and liabilities, net of the effects from the purchase of Stellarton: |                                                            
|                                                                     |                                                                                          |                                                                                                  | Decrease (increase) in accounts receivable                 
|                                                                     |                                                                                          |                                                                                                  | (Increase) decrease in inventories                         
|                                                                     |                                                                                          |                                                                                                  | (Increase) decrease in other current assets                
|                                                                     |                                                                                          |                                                                                                  | (Decrease)increase in accounts payable and accrued expenses
|                                                                     |                                                                                          |                                                                                                  | (Increase) decrease in other assets, net                   
|                                                                     |                                                                                          |                                                                                                  |                                                            
|                                                                     |                                                                                          |                                                                                                  |                                                            
|                                                                     |                                                                                          |                                                                                                  |                                                            
|CASH FLOWS FROM INVESTING ACTIVITIES:                                |                                                                                          |                                                                                                  |                                                            
|                                                                     |                                                                                          | Proceeds from sales of assets                                                                    |                                                            
|                                                                     |                                                                                          | Capital expenditures                                                                             |                                                            
|                                                                     |                                                                                          | Acquisition of Stellarton stock                                                                  |                                                            
|                                                                     |                                                                                          | Direct costs of Stellarton acquisition                                                           |                                                            
|                                                                     |                                                                                          | Changes in accounts payable and accrued expenses for capital expenditures                        |                                                            
|                                                                     |                                                                                          |                                                                                                  |                                                            
|                                                                     |                                                                                          |                                                                                                  |                                                            
|                                                                     |                                                                                          |                                                                                                  |                                                            
|CASH FLOWS FROM FINANCING ACTIVITIES:                                |                                                                                          |                                                                                                  |                                                            
|                                                                     |                                                                                          | Borrowings of long-term bank debt                                                                |                                                            
|                                                                     |                                                                                          | Repayments of long-term bank debt                                                                |                                                            
|                                                                     |                                                                                          | Preferred stock dividends                                                                        |                                                            
|                                                                     |                                                                                          | Proceeds from exercise of stock options                                                          |                                                            
|                                                                     |                                                                                          |                                                                                                  |                                                            
|                                                                     |                                                                                          |                                                                                                  |                                                            
|                                                                     |                                                                                          |                                                                                                  |                                                            
|Effect of exchange rate changes on cash                              |                                                                                          |                                                                                                  | (4                                                         
|NET CHANGE IN CASH AND CASH EQUIVALENTS                              |                                                                                          |                                                                                                  | (1,641                                                     
|CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR                       |                                                                                          |                                                                                                  | 15,196                                                     
|                                                                     |                                                                                          |                                                                                                  |                                                            
|CASH AND CASH EQUIVALENTS AT END OF YEAR                             |                                                                                          | $                                                                                                | 13,555                                                     
|                                                                     |                                                                                          |                                                                                                  |                                                            
|Supplemental disclosures of cash flow information:                   |                                                                                          |                                                                                                  |                                                            
|Cash paid during the year for:                                       |                                                                                          |                                                                                                  |                                                            
|                                                                     |                                                                                          |                                                                                                  | Interest                                                   
|                                                                     |                                                                                          |                                                                                                  | Income taxes                                               
|Refund received of income tax deposit                                |                                                                                          |                                                                                                  | 6,000                                                      
|Supplemental schedule of noncash investing and financing activities: |                                                                                          |                                                                                                  |                                                            
|                                                                     |                                                                                          |                                                                                                  |                                                            

See accompanying notes to consolidated financial statements.





TOM BROWN, INC. AND SUBSIDIARIES        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS        For the Years Ended December 31, 2002, 2001 and 2000

(1) Nature of Operations

Tom Brown, Inc. and its wholly-owned subsidiaries (the "Company") is an independent energy company engaged in the exploration for, and the acquisition,
development, marketing, production and sale of, natural gas and crude oil. The Company's industry segments are (i) the exploration for, and the acquisition, development, production, and sale
of, natural gas and crude oil, (ii) the marketing, gathering and processing of natural gas and (iii) drilling gas and oil wells. The Company's marketing activities are primarily
conducted through Retex, Inc. ("Retex") and contract drilling is conducted through Sauer Drilling Company ("Sauer"). The Company's operations are conducted in the United States and Canada. The
Company's United States operations are presently focused in the Wind River and Green River Basins of Wyoming, the Piceance Basin of Colorado, the Paradox Basin of eastern Utah and western Colorado,
the Val Verde and Permian Basins of west Texas and southeastern New Mexico, and the east Texas Basin. The Company also, to a lesser extent, conducts exploration and development activities in other
areas of the continental United States. The Company expanded its operations into Canada in 2001, establishing western Canada as a core area through the acquisition of Stellarton Energy Corporation
("Stellarton"). This transaction was completed in January 2001. The Canadian operations are focused in the Carrot Creek, Edson and Davey Lake areas of the western sedimentary basin of Alberta.

Wildhorse
was originally formed by KN Energy, Inc. ("KNE") and the Company in January 1996. KNE was subsequently acquired by Kinder Morgan Inc. ("KM"). Initially,
Wildhorse was owned fifty-five percent (55%) by KNE and forty-five percent (45%) by the Company. The Company dedicated a significant amount of its Rocky Mountain gas reserves
to Wildhorse and KNE contributed substantial gas marketing contracts. The Company also transferred a natural gas storage facility in western Colorado to Wildhorse. The principal purpose of Wildhorse
was to provide services related to natural gas, natural gas liquids and other natural gas products, including
gathering, processing and storage services. In September 1999, Wildhorse assigned 100% of its marketing operations to Retex. Firm transportation contracts were also assigned 55% to KM and 45%
to Retex at that time. In November 2000, the remaining gathering and processing assets were distributed to the Company in anticipation of the dissolution of Wildhorse. KM received the storage
facility and a cash payment of $14.7 million. TBIFS was formed as a wholly-owned subsidiary of Tom Brown, Inc. to administer the gathering and processing assets received in the Wildhorse
distribution. In 2001, TBIFS selectively sold many of the gathering and processing facilities received in the Wildhorse asset distribution, retaining only those gathering systems considered integral
to the Company's operations. The Wind River gathering system was the main system retained. In 2002, the Company liquidated TBIFS to transfer the remaining gathering and processing assets to the parent
company, Tom Brown, Inc.

Substantially
all of the Company's production is sold under market-sensitive contracts. The Company's revenue, profitability and future rate of growth are substantially dependent upon
the price of, and demand for, oil, natural gas and natural gas liquids. Prices for natural gas, crude oil and natural gas liquids are subject to wide fluctuation in response to relatively minor
changes in their supply and demand as well as market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include the level of consumer product
demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions in foreign countries, the foreign supply of natural gas
and oil and the price of foreign imports and overall economic conditions. The Company is affected more by fluctuations in natural gas


prices than oil prices because a majority of its production (84 percent in 2002 and 2001 on a volumetric equivalent basis) is natural gas.

(2) Summary of Significant Accounting Policies



The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. The Company's proportionate share of
revenues and expenses associated with certain interests in a gas and oil partnership were consolidated in the accompanying financial statements for the periods prior to Wildhorse asset distribution.
All significant intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to amounts reported in previous years to conform to the 2002 presentation.



Inventories consist of pipe, other production equipment and natural gas placed in storage. Inventories are stated at the lower of cost (principally
first-in, first-out) or estimated net realizable value.



The Company accounts for its natural gas and crude oil exploration and development activities under the successful efforts method of accounting. Under such
method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Gas and oil lease acquisition costs are also capitalized. Exploration
costs, including personnel costs, certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially
capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a
cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized
for all other sales of producing properties.

Maintenance
and repairs are charged to expense; renewals and betterments are capitalized to the appropriate property and equipment accounts. Upon retirement or disposition of assets, the
costs and related accumulated depreciation are removed from the accounts with the resulting gains or losses, if any, reflected in results of operations.

Unproved
properties with significant acquisition costs are assessed quarterly on a property-by-property basis and any impairment in value is charged to expense.
Unproved properties whose acquisition costs are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized
over the average holding period. If the unproved properties are determined to be productive, the related costs are transferred to proved gas and oil properties. Proceeds from sales of partial
interests in unproved leases are accounted for as a recovery of cost without recognizing any gain or loss.

The
Company reviews its gas and oil properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. The Company estimates
the expected future cash flows of its gas and oil properties and compares such future cash flows to the carrying amount of the gas and oil properties to determine if the carrying amount is
recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to
determine fair value include estimates of proved reserves, future commodity prices, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk
associated with realizing the expected cash flows projected. There were no impairments of producing gas and oil properties in 2002, 2001 or 2000.

The
provision for depreciation, depletion and amortization of oil and gas properties is calculated on a basin-by-basin basis using the
unit-of-production method. Included in such calculations are estimated future dismantlement, restoration and abandonment costs, net of estimated salvage values.

Other
property and equipment is recorded at cost or estimated fair value upon acquisition and depreciated using the straight-line method over their estimated useful lives.
Gas gathering, processing and other plant equipment is generally depreciated using the straight-line method over estimated useful lives that range from 10 to 20 years.



The Company utilizes the accrual method of accounting for natural gas revenues whereby revenues are recognized as the Company's entitlement share of gas is
produced based on its working interests in the properties. The Company records a receivable (payable) to the extent it receives less (more) than its proportionate share of gas revenues. At
December 31, 2002 and 2001, the net imbalance positions were not significant.



The functional currency of the Company's Canadian subsidiary is the Canadian dollar. For purposes of consolidation, substantially all assets and liabilities of
the Canadian operations are translated into U.S. dollars at exchange rates in effect at the balance sheet dates. Unrealized currency translation adjustments are accumulated as a separate component of
accumulated other comprehensive income within stockholders' equity. Income and expense items are translated at average exchange rates during the year. As a result of the change in the Canadian dollar
relative to the U.S. dollar, the Company reported translation losses of $80,000 in 2002 and $790,000 in 2001.



In order to increase financial flexibility and to protect the Company against commodity price fluctuations, the Company may, from time to time in the ordinary
course of business, enter into non-speculative hedge transactions, including, commodity swap agreements, forward sale contracts, commodity futures, options and other similar agreements
relating to natural gas and crude oil expected to be produced.

In
June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments
and Hedging Activities." SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. It also requires that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement,
and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS 133 is effective for all fiscal quarters of
fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities". This
pronouncement amended portions of SFAS 133 and was adopted by the Company with SFAS 133 effective January 1, 2001.

SFAS 133,
in part, allows special hedge accounting for cash flow hedges and provides that the effective portion of the gain or loss on a derivative instrument designated and
qualifying as a cash flow hedging instrument be reported as a component of Other Comprehensive Income and be reclassified into earnings in the same period or periods during which the hedged forecasted
transaction affects earnings.



In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets," which addresses, among other things, the financial accounting
and reporting for goodwill subsequent to an acquisition. The new standard eliminates the requirement to amortize acquired goodwill; instead, such goodwill is reviewed at least annually for impairment.
The Company adopted SFAS No. 142 on January 1, 2002, designating its reporting units as (i) gas and oil exploration and development in the United States, (ii) gas and oil
exploration and development in Canada, (iii) marketing, gathering and processing and (iv) drilling. The first two reporting units are included in the gas and oil exploration and
development segment. A fair value based test was conducted effective January 1, 2002 to evaluate the goodwill originally recorded in conjunction with the January 2001 Stellarton Energy
Corporation acquisition. The fair value of the reporting unit was determined with reference to the estimated discounted future net revenues of the underlying gas and oil reserves as of the date of the
test and other financial considerations, including going-concern value. This test resulted in the Company recording a non-cash charge of $18.1 million in the quarter ended
March 31, 2002. This expense has been reflected in the consolidated statements of operations as a cumulative effect of a change in accounting principle. After this write down, the Company has
no goodwill recorded on its consolidated balance sheet or associated amortization expense recorded on its consolidated statements of operations. To the extent that goodwill is recognized in
conjunction with future transactions, the Company would expect to perform its annual impairment test on December 31. Had SFAS No. 142 been effective for


the years ended December 31, 2001 and 2000, the Company's net income would have been as follows (in thousands, except per share amounts):

|                                            |                                              | Years Ended December 31,
|------------------------------------------- | -------------------------------------------- | ------------------------
|
|Net (loss) income                           |                                              |                         
|                                            | As reported                                  |                         
|                                            | Amortization of goodwill (net of tax effect) |                         
|                                            |                                              |                         
|                                            | Pro forma                                    |                         
|                                            |                                              |                         
|Basic net (loss) income per common share:   |                                              |                         
|                                            | As reported                                  |                         
|                                            | Pro forma                                    |                         
|Diluted net (loss) income per common share: |                                              |                         
|                                            | As reported                                  |                         
|                                            | Pro forma                                    |                         

In
connection with a review of the Company's financial statements by the staff of the Securities and Exchange Commission, the Company has been made aware that an issue has arisen within
the industry regarding the application of provisions of SFAS No. 142 and SFAS No. 141, "Business Combinations," to companies in the extractive industries, including gas and oil
companies. The issue is whether SFAS No. 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as
intangible assets in the balance sheet, apart from other capitalized gas and oil property costs. Historically, the Company and other gas and oil companies have included the cost of these gas and oil
leasehold interests as part of gas and oil properties. Also under consideration is whether SFAS No. 142 requires registrants to provide the additional disclosures prescribed by SFAS
No. 142 for intangible assets for costs associated with mineral rights.

If
it is ultimately determined that SFAS No. 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the
amounts that would be reclassified are as follows:

|                                     |                                   | December 31,
|------------------------------------ | --------------------------------- | ------------
|
|
|INTANGIBLE ASSETS:                   |                                   |             
|Proved leasehold acquisition costs   |                                   | $           
|Unproved leasehold acquisition costs |                                   |             
|                                     |                                   |             
|                                     | Total leasehold acquisition costs |             
|Less: Accumulated depletion          |                                   |             
|                                     |                                   |             
|                                     | Net leasehold acquisition costs   |             
|                                     |                                   |             



The
reclassification of these amounts would not effect the method in which such costs are amortized or the manner in which the Company assesses impairment of capitalized costs. As a
result, net income would not be affected by the reclassification.

In
July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for
an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related
long-lived asset. Over time, the liability is accreted each period toward its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity reports a gain or loss upon settlement to the extent the actual costs differ from the recorded liability. SFAS No. 143 is effective for
fiscal years beginning after June 15, 2002. The Company will adopt SFAS No. 143 on January 1, 2003. Upon adoption of SFAS No. 143, the Company will record a
discounted liability of $14.5 million for the future retirement obligation, increase net property and equipment by $13.0 million and record a charge of $1.0 million (net of a
deferred tax benefit of $.5 million) as the cumulative effect of the change in accounting principle. The majority of the asset retirement obligation to be recognized will relate to the
projected cost to plug and abandon gas and oil wells. Liabilities will also be recorded for processing plants, compressors and other field facilities.

In
August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 supersedes SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS No. 121 did not address the accounting for a
segment of a business accounted for as a discontinued operation which resulted in two accounting models for long-lived assets to be disposed of. SFAS No. 144 establishes a single
accounting model for long-lived assets to be disposed of by sale and requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost
to sell, whether reported in continuing operations or in discontinued operations. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The Company adopted
SFAS No. 144 on January 1, 2002. There was no impact on the Company's financial position or results of operations upon adoption of SFAS No. 144.

In
June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS 146 nullifies the guidance of the Emerging
Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." SFAS 146 requires that a liability for a cost that is associated with an exit or disposal activity be recognized when the liability is incurred. SFAS 146 also
establishes that fair value is the objective for the initial measurement of the liability. The provisions of SFAS 146 are required for exit or disposal activities that are initiated after
December 31, 2002. The adoption of this statement did not impact the Company's financial position or results of operations.

In
October 2002, the Emerging Issues Task Force reached a consensus on EITF Issue No. 02-03,Recognition and Reporting of Gains and
Losses on Energy Trading Contracts.The consensus rescinded EITF Issue No. 98-10,Accounting for Contracts Involved in Energy Trading
and Risk Management Activities.Under the consensus, effective January 1, 2003, all energy related contracts that qualify as derivatives under Statement of Financial Accounting Standards
No. 133are required to be recorded at fair value and the purchase and sale amounts are reported net
in the statement of income. All other


contracts are accounted for as executory contracts using the accrual method of accounting and the purchases and sales amounts are reported gross in the statement of income. Substantially all of the
contracts entered into in connection with the Company's marketing and trading activities do not qualify as derivatives, and as a result will be reported on a gross basis in the statement of income.
Prior period financial statements will be reclassified to present these purchase and sales amounts on a gross basis. The reclassifications will not impact the amount of reported marketing and trading
margins, or the amount of reported net income.

In
November 2002, the FASB issued Financial Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantee of
Indebtedness of Others" (FIN 45). FIN 45 requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. FIN
45's provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The guarantor's previous accounting
for guarantees that were issued before the date of FIN 45's initial application may not be revised or restated to reflect the effect of the recognition and measurement provisions of the
Interpretation. The disclosure requirements are effective for financial statements of both interim and annual periods that end after December 15, 2002. The Company is not a guarantor under any
significant guarantees and thus this interpretation is not expected to have a significant effect on its financial position or results of operations.

In
December 2002, the FASB issued SFAS 148, "Accounting for Stock-Based CompensationTransition and Disclosure." SFAS No. 148 amends FASB Statement
No. 123, "Accounting for Stock-Based Compensation" to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee
compensation. In addition, this Statement amends the disclosure for stock-based employee compensation and the
effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements with fiscal years ending after December 15, 2002. The adoption
of this statement did not impact the Company's financial position or results of operations because the Company has not adopted the fair value method of accounting for stock-based compensation.

In
January 2003, the FASB issued Financial Interpretation No. 46, "Consolidation of Variable Interest Entitiesan interpretation of ARB No. 51" (FIN 46).
FIN 46 is an interpretation of Accounting Research Bulletin 51, "Consolidated Financial Statements," and addresses consolidation by business enterprises of variable interest entities (VIEs). The
primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities
are known as VIEs. FIN 46 requires an enterprise to consolidate a variable interest entity if that enterprise has a variable interest that will absorb a majority of the entity's expected losses if
they occur, receive a majority of the entity's expected residual return if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making
this determination. This guidance applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest
after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to variable interest entities in which an enterprise holds a variable interest that it
acquired before February 1, 2003. The Company does not hold any interest in VIEs that would be impacted by FIN 46.


Therefore, the adoption of this interpretation will not impact the Company's financial position or results of operations.



The Company provides for income taxes using the liability method under which deferred income taxes are recognized for the tax consequences of "temporary
differences" by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and
liabilities. The effect on deferred taxes of a change in tax laws or tax rates is recognized in income in the period such changes are enacted.



The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board (APB) Opinion No. 25
"Accounting for Stock Issued to Employees" and related interpretations under which no compensation cost is generally recognized for grants of options under the Company's stock option plans unless
there is a modification to the original terms of the option grant. In January 2001, the Company's Chairman and Chief Executive Officer resigned to become the United States Secretary of
Commerce. The Company accelerated the vesting of 228,300 of his outstanding stock options upon his resignation and, as a result of this modification to the initial terms of these stock options, a new
measurement date was established. Based upon the difference between the market price of the Company's stock on the date the stock options were amended and the exercise price of the stock options, a
non-cash pre-tax charge to earnings of $3.8 million ($2.4 million after tax) was recognized. If compensation costs for these plans had been


determined in accordance with SFAS No. 123, the Company's net income and net income per common share would approximate the following pro forma amounts:

|                                            |             | Years Ended December 31,                                                                                               |  
|------------------------------------------- | ----------- | ---------------------------------------------------------------------------------------------------------------------- | -
|
|
|Net (loss) income                           |             |                                                                                                                        |  
|                                            | As reported |                                                                                                                        | $
|                                            |             | Add: Compensation cost included in reported net (loss) income (net of tax) (1)                                         |  
|                                            |             | Deduct: Stock-based employee compensation expense determined under fair value based method for all awards (net of tax) |  
|                                            |             |                                                                                                                        |  
|                                            | Pro forma   |                                                                                                                        | $
|                                            |             |                                                                                                                        |  
|Basic net (loss) income per common share:   |             |                                                                                                                        |  
|                                            | As reported |                                                                                                                        | $
|                                            | Pro forma   |                                                                                                                        | $
|Diluted net (loss) income per common share: |             |                                                                                                                        |  
|                                            | As reported |                                                                                                                        | $
|                                            | Pro forma   |                                                                                                                        | $

---



The preparation of financial statements in conformity with generally accepted accounting principles require management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the
reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates affecting these financial statements include the estimate
of proved oil and gas reserve volumes and the related present value of estimated future net revenues to be received therefrom.



Basic earnings per share ("EPS") is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding
during the period including the weighted average impact of the shares of common stock issued during the year from the date of issuance. Diluted EPS calculations also give effect to all dilutive
potential common shares outstanding during the period.

The
following is a reconciliation of the numerators and denominators used in the calculation of basic and diluted EPS for the years ended December 31, 2002, 2001 and 2000:

|                                                                         |                                                                  | 2002 |        | 2001   |        | 2000  
|------------------------------------------------------------------------ | ---------------------------------------------------------------- | ---- | ------ | ------ | ------ | ------
|
|
|Basic EPS:                                                               |                                                                  |      |        |        |        |       
|                                                                         | Net (Loss) Income Attributable to Common Stock and Share Amounts |      | $      | (8,177 | )      | 39,217
|Dilutive Securities:                                                     |                                                                  |      |        |        |        |       
|                                                                         | Stock Options                                                    |      |        |       |        | 1,110 
|                                                                         | Convertible preferred stock                                      |      |        |       |        |      
|                                                                         |                                                                  |      |        |        |        |       
|Diluted EPS:                                                             |                                                                  |      |        |        |        |       
|Net (Loss) Income Attributable to Common Stock and Diluted Share Amounts |                                                                  | $    | (8,177 | )      | 40,327 |       
|                                                                         |                                                                  |      |        |        |        |       

Options to purchase 1,688,000 and 1,180,000 shares of common stock in 2002 and 2001 were excluded in the computation of diluted earnings per share
because the option exercise price was greater than the average market price of the Company's common stock. No options were excluded in 2000.



The Company considers investments with an original maturity of three months or less when purchased to be cash equivalents.



Comprehensive income represents all non-shareholder related changes in equity of an entity during the reporting period, including net income and
charges directly to equity which are
excluded from net income. At December 31, 2002 and 2001, the reconciling items between net income as reflected in the statement of operations and comprehensive income were an unrealized loss on
marketable securities, a translation loss, and an unrealized loss on derivatives. The only reconciling items between net income as reflected in the statement of operations and comprehensive income for
the year ended December 31, 2000 was an unrealized loss on marketable securities.

(3) Acquisitions and Divestitures



On January 12, 2001, the Company completed an acquisition of 97.2% of the outstanding common shares of Stellarton. The remaining shares of Stellarton were
then subsequently acquired pursuant to the compulsory acquisition provisions of the Business Corporation Act (Alberta). Including assumed debt of approximately $16.8 million, this business
combination had a value of approximately $95 million and was accounted for as a purchase. The purchase price exceeded the fair value of the net assets of Stellarton by $20 million which
was recorded as goodwill, a portion of which was amortized in 2001 on a straight-line basis utilizing a twenty year life. Effective January 1, 2002 the Company adopted SFAS


No. 142, "Goodwill and Other Intangible Assets" and expensed the unamortized goodwill of $18.1 million associated with this change in accounting principle. The net proved reserves
associated with the Stellarton properties were estimated to be 75.8 billion cubic feet equivalent of gas (Bcfe) (unaudited) as of the closing date. The results of operations of Stellarton are
included with the results of the Company from January 12, 2001 (closing date) forward.

The
purchase price was allocated as follows (in thousands):

Cash paid for acquisition:Long-term debt incurred

$
74,500Long-term debt assumed


16,800Direct acquisition costs


3,107Total cash paid


94,407Allocation of acquisition costs:Oil and gas propertiesproved


(117,000
)Unproved properties


(9,975
)Deferred income taxes


36,375Gas sales contracts assumed


10,825Net working capital deficit assumed


5,368Goodwill

$
20,000


In
the acquisition costs identified above, the Company recorded a deferred income tax liability of $36.4 million to recognize the difference between the historical tax basis of
the Stellarton assets and the acquisition costs recorded for book purposes. The recorded book value of the proved oil and gas properties was increased and goodwill was recorded to recognize this tax
basis differential.

The
gas sales contracts assumed in conjunction with the acquisition represented contractual obligations associated with the sale of natural gas at fixed prices below the then current
market prices. These contracts were subsequently purchased (for an amount approximately equal to the original liability recorded) and cancelled in the quarter ended June 30, 2001.







The following table reflects the unaudited pro forma results of operations for the twelve months ended December 31, 2001 and 2000 as though the
Stellarton Acquisition had occurred on January 1 of each period presented. The pro forma amounts are not necessarily representative of the results that may be reported in the future.

|                             |  | Years Ended
December 31,
|---------------------------- |  | ------------------------
|
|
|Revenues                     |  | $                       
|Net Income                   |  |                         
|Basic net income per share   |  |                         
|Diluted net income per share |  |                         



In June 2002, the Company purchased Rocky Mountain gas and oil properties located within the Greater Green River Basin of Wyoming for approximately
$8.1 million from an unrelated third party. In December 2002, the Company acquired additional assets within this basin from this seller for $6.8 million. The acquisition cost of
both of these transactions was net of normal closing adjustments. The acquired interests from these two transactions included an estimated 12.7 Bcfe of proved reserves (unaudited).

In
June 2000, the Company purchased an additional working interest in a field operated by the Company in the Wind River Basin in Wyoming. The Company acquired the additional
interest from State Farm Mutual Automobile Insurance Company, a stockholder of the Company. The acquired interests included an estimated 24.0 Bcfe of proved reserves (unaudited) purchased for total
consideration of $15.2 million net of normal closing adjustments.



During May 2001, the Company sold its interest in oil and gas properties primarily located in Oklahoma to an unrelated third party, with a net book value
of $14.4 million, for net cash proceeds of $24.5 million. The resulting gain of $10.1 million is reflected in the Consolidated Statement of Operations.

In
June and October 2001, the Company sold certain of the gathering and processing assets originally received in the Wildhorse distribution completed in 2000 for net cash
proceeds of $24.0 million. The systems sold were considered non-strategic to the Company's operations.

In
April 2002, the Company sold its interest in oil and gas properties, located in the Powder River Basin of Wyoming, to an unrelated third party for net cash proceeds of
$7.2 million. These properties had a net book value of $3.1 million which resulted in a $4.l million gain on the sale.

In
April 2002, the Company sold certain oil and gas properties located primarily in Louisiana to an unrelated third party for $2.0 million and in November 2002,
certain oil and gas properties located primarily in Colorado were sold to an unrelated third party for $1.6 million. As these sales represented partial interests in these proved properties, the
proceeds were recorded as a reduction to the recorded cost of the oil and gas properties.

(4) Debt

On June 30, 2000, the Company entered into a $125 million credit facility (the "Credit Facility") that was to mature in June 2003. Under the
terms of the Credit Facility, the borrowing base was established at $225 million.

On
March 20, 2001, as part of the final financing of the Stellarton acquisition, the Company repaid and cancelled its previous $125 million Credit Facility and entered into
a new $225 million credit facility (the "Global Credit Facility"). The Global Credit Facility is comprised of: a $75 million line of credit in the U.S. and a $55 million line of
credit in Canada which both mature in March 2004, and a $95 million five-year term loan in Canada. The borrowing base under the Global Credit Facility was set at
$300 million. The Global Credit Facility allows the lenders one scheduled redetermination of the borrowing base each December. In addition, the lenders may elect to require one unscheduled
redetermination in the event the borrowing base utilization exceeds 50% of the borrowing base at any time for a period of 15 consecutive business days. At December 31, 2002, the Company
had borrowings outstanding under the Global Credit Facility totaling $133.2 million or 44% of the borrowing base at an average interest rate of 3.9%. The amount available for borrowing under
the Global Credit Facility at December 31, 2002 was $91.8 million.

Borrowings
under the Global Credit Facility are unsecured and bear interest, at the election of the Company, at a rate equal to (i) the greater of the global administrative agents
prime rate or the federal funds effective rate plus an applicable margin, (ii) adjusted LIBOR for Eurodollar loans plus applicable margin, or (iii) Bankers' Acceptances plus applicable
margin for Canadian dollar loans. Interest on amounts outstanding under the Global Credit Facility is due on the last day of each quarter for prime based loans, and in the case of Eurodollar loans
with an interest period of more than three months', interest is due at the end of each three month interval.

The
Global Credit Facility contains certain financial covenants and other restrictions that require the Company to maintain a minimum consolidated tangible net worth of not less than
$350 million (adjusted upward by 50% of quarterly net income subsequent to March 31, 2001 and 50% of the net cash proceeds of any stock offering). The Company must also maintain a ratio
of indebtedness to earnings before interest expense, state and federal taxes and depreciation, depletion and amortization expense and exploration expense of not more than 3.0 to 1.0 as calculated at
the end of each fiscal quarter. The Company was in compliance with all covenants in 2002 and at December 31, 2002.

(5) Taxes

The income tax (expense) benefit was different from amounts computed by applying the statutory Federal and State income tax rates to income before income taxes
for the following reasons:

|                                                                                            |  | 2002 |        | 2001 |   | 2000    |  
|------------------------------------------------------------------------------------------- |  | ---- | ------ | ---- | - | ------- | -
|
|Tax expense at 35% of income before income taxes and change in accounting principle         |  | $    | (4,598 | )    | $ | (36,961 | )
|State tax expense net of federal benefit                                                    |  |      | (263   | )    |   | (2,112  | )
|Franchise and other taxes                                                                   |  |      | (614   | )    |   | (486    | )
|Canadian Crown payments (net of Alberta Royalty Tax Credit) not deductible for tax purposes |  |      | (2,879 | )    |   | (4,136  | )
|Canadian resource allowance                                                                 |  |      | 2,699  |      |   | 3,556   |  
|Canadian expenses deductible in the United States                                           |  |      | 1,578  |      |   | 1,845   |  
|Canadian Large Corporation Tax                                                              |  |      | (285   | )    |   | (335    | )
|Adjustments to prior periods due to filed returns                                           |  |      | 397    |      |   | 502     |  
|Valuation allowance adjustment                                                              |  |      |       |      |   |        |  
|Enterprise zone tax credits                                                                 |  |      | 1,018  |      |   |        |  
|Other                                                                                       |  |      | (263   | )    |   |        |  
|                                                                                            |  |      |        |      |   |         |  
|Total income tax expense                                                                    |  | $    | (3,210 | )    | $ | (38,127 | )
|                                                                                            |  |      |        |      |   |         |  

Deferred
income taxes result from recognizing income and expenses at different times for financial and tax reporting. In the United States, the largest differences are created by the tax
effect of the capitalization of certain development, exploration and other costs under the successful efforts method of accounting for book purposes. In Canada, differences result in part from
accelerated cost recovery of oil and gas capital expenditures for tax purposes.

The
components of the net deferred tax liability by geographical segment at December 31, 2002 and 2001 were as follows:

|                          |                                                       | December 31, 2002                    |  
|------------------------- | ----------------------------------------------------- | ------------------------------------ | -
|
|
|Deferred tax assets:      |                                                       |                                      |  
|                          | Net operating loss carryforward                       |                                      | $
|                          | Percentage depletion carryforward                     |                                      |  
|                          | Alternative minimum tax credit carryforward           |                                      |  
|                          | Derivative contracts to be settled in a future period |                                      |  
|                          | Other                                                 |                                      |  
|                          |                                                       |                                      |  
|                          |                                                       | Total gross deferred tax assets      |  
|Deferred tax liabilities: |                                                       |                                      |  
|                          | Property and equipment                                |                                      |  
|                          | Other                                                 |                                      |  
|                          |                                                       |                                      |  
|                          |                                                       | Total gross deferred tax liabilities |  
|                          |                                                       |                                      |  
|                          |                                                       | Net deferred tax liabilities         |  
|                          |                                                       |                                      |  

|                          |                                             | December 31, 2001                    |  
|------------------------- | ------------------------------------------- | ------------------------------------ | -
|
|
|Deferred tax assets:      |                                             |                                      |  
|                          | Net operating loss carryforward             |                                      | $
|                          | Percentage depletion carryforward           |                                      |  
|                          | Alternative minimum tax credit carryforward |                                      |  
|                          | Other                                       |                                      |  
|                          |                                             |                                      |  
|                          |                                             | Total gross deferred tax assets      |  
|Deferred tax liabilities: |                                             |                                      |  
|                          | Property and equipment                      |                                      |  
|                          | Other                                       |                                      |  
|                          |                                             |                                      |  
|                          |                                             | Total gross deferred tax liabilities |  
|                          |                                             |                                      |  
|                          |                                             | Net deferred tax liabilities         |  
|                          |                                             |                                      |  

The
Alternative Minimum Tax (AMT) credit carryforward available to reduce future U.S. Federal regular taxes aggregated $4.8 million at December 31, 2002. This amount may be
carried forward indefinitely. U.S. Federal regular and AMT net operating loss carryforwards at December 31, 2002 were approximately $25.9 and $19.0 million, respectively, and will expire
in 2019. AMT net operating loss carryforwards can be used to offset 90% of AMT income in future years (the Job Creation and Worker Assistance Act of 2002 allowed for 100% of the AMT net operating loss
carryforwards to be offset against AMT income for 2001 and 2002.) Realization of the benefit of these carryforwards is dependent upon the Company's ability to generate taxable earnings in future
periods.

Percentage
depletion carryforwards available to reduce future U.S. Federal taxable income aggregated $7.2 million at December 31, 2002. This amount may be carried forward
indefinitely.

Canadian
net operating losses available to reduce future Canadian Federal income taxes were $6.0 million ($9.4 million CDN) at December 31, 2002 and expire in 2008.

Canadian
tax pools relating to the exploration, development and production of oil and natural gas available to reduce future Canadian Federal income taxes aggregate approximately
$47.0 million ($74.3 million CDN) at December 31, 2002. These pool balances are deductible on a declining balance basis ranging from 10% to 100% of the balance annually. The
amounts may be carried forward indefinitely.

In
conjunction with the acquisition of Stellarton in January 2001, the purchase price allocation resulted in a difference between the book and tax basis of approximately U.S.
$63 million. Based upon Stellarton's historical tax rate of 43%, a deferred tax liability of approximately $36.4 million was recognized.

(6) Trading Activities

The Company engages in natural gas trading activities which involve purchasing natural gas from third parties and selling natural gas to other parties. These
transactions are typically short-term in nature and involve positions whereby the underlying quantities generally offset. The Company also markets a significant portion of its own
production. Marketing and trading income associated with these activities is presented on a net basis in the financial statements. The Company's gross trading activities are summarized below.

|                                             |  | Years Ended December 31,
|-------------------------------------------- |  | ------------------------
|
|
|Revenues                                     |  | $                       
|Operating expenses                           |  |                         
|                                             |  |                         
|Net trading margin                           |  |                         
|Marketing margin on the Company's production |  |                         
|                                             |  |                         
|Marketing and trading revenuesnet           |  | $                       
|                                             |  |                         

(7) Stockholders' Equity



The Company's Common Stock is $.10 par value per share. There were 55,000,000 authorized shares of Common Stock at December 31, 2002 of which 39,261,191
shares and 39,127,649 shares were outstanding at December 31, 2002 and 2001, respectively.



On March 1, 1991, the Board of Directors adopted a Rights Plan designed to help assure that all stockholders receive fair and equal treatment in the event
of a hostile attempt to take over the Company, and to help guard against abusive takeover tactics. The Board of Directors declared a dividend of one preferred share purchase right (a "Right") for each
outstanding share of Common Stock. The dividend was distributed on March 15, 1991 to the stockholders of record on that date. As of March 1, 2001, the Board of Directors amended and
restated the Rights Plan. Each Right entitles the registered holder to purchase, for the $120 per share exercise price, shares of Common Stock or


other securities of the Company (or, under certain circumstances, of the acquiring person) worth twice the per share exercise price of the Right.

The
Rights will be exercisable only if a person or group acquires 15% or more of the Company's Common Stock or announces a tender offer which would result in ownership by a person or
group of 15% or more of the Common Stock. The date on which the above occurs is to be known as the "Distribution Date". The Rights will expire on March 1, 2011, unless extended or redeemed
earlier by the Company.

At
the time the Rights dividend was declared, the Board of Directors further authorized the issuance of one Right with respect to each share of the Company's Common Stock that shall
become outstanding between March 15, 1991 and the earlier of the Distribution Date or the expiration or redemption of the Rights. Until the Distribution Date occurs, the certificates
representing shares of the Company's
Common Stock also evidence the Rights. Following the Distribution Date, the Rights will be evidenced by separate certificates.

The
provisions described above may tend to deter any potential unsolicited tender offers or other efforts to obtain control of the Company that are not approved by the Board of Directors
and thereby deprive the stockholders of opportunities to sell shares of the Company's Common Stock at prices higher than the prevailing market price. On the other hand, these provisions will tend to
assure continuity of management and corporate policies and to induce any person seeking control of the Company or a business combination with the Company to negotiate on terms acceptable to the then
elected Board of Directors.



In January 1996, in connection with the KNPC acquisition, the Company issued 1,000,000 shares of its $1.75 Convertible Preferred Stock, Series A
(the "Preferred Stock") to the seller. There are 2,500,000 shares of Preferred Stock authorized. The holder of the Preferred Stock was entitled to receive cumulative dividends at the annual rate of
$1.75 per share, payable in cash quarterly on the fifteenth day of March, June, September and December in each year.

The
Preferred Stock was exchangeable, in whole or in part, at the option of the Company on any dividend payment date at any time on or after March 15, 1999, and prior to
March 15, 2001, for shares of Common Stock at the exchange rate of 1.666 shares of Common Stock for each share of Preferred Stock; provided that on or prior to the date of exchange, the Company
shall have declared and paid or set apart for payment to the holders of Preferred Stock all accumulated and unpaid dividends to the date of exchange, and the current market price of the Common Stock
was above $18.375 (the "Threshold Price").

On
June 15, 2000, the Company elected to exchange 1,666,000 shares of its Common Stock for all 1,000,000 outstanding shares of the Preferred Stock as the Common Stock had traded
above the Threshold Price. Dividends on the Preferred Stock were paid through June 14, 2000 and did not accrue after the June 15, 2000 exchange date. The Preferred Stock is no longer
outstanding.

(8) Benefit Plans



The Company's 1989 Stock Option Plan expired in December 1999. As of December 31, 2002, options to purchase 336,200 shares of the Company's common
stock were outstanding under the 1989 Plan. These options will expire between 2003 and 2008 if not previously exercised.



In February 1993, the Board of Directors adopted the Company's 1993 Stock Option Plan (the "1993 Plan"). The 1993 Plan provides for issuance of options to
certain employees and directors to purchase shares of Common Stock. In November 1999, the aggregate number of shares of Common Stock that may be issued under the 1993 Plan was increased from
2,700,000 shares to 3,200,000 shares. The aggregate number of shares was subsequently increased to 4,100,000 in January 2001. The exercise price, vesting and duration of the options may vary
and will be determined at the time of issuance. Options to purchase 2,779,000 shares of the Company's Common Stock were outstanding under this plan as of December 31, 2002.



The 1999 Long Term Incentive Plan (the "1999 Plan") was adopted by the Board of Directors on February 17, 1999, and approved by the stockholders on
May 20, 1999. The 1999 Plan provides for the grant of stock options, restricted stock awards, performance awards and incentive awards. There were option grants made to purchase 447,400, 378,700
and 490,000 shares of the Company's Common Stock in 2002, 2001 and 2000, respectively. The aggregate number of shares of common stock, which may be issued under the 1999 Plan, may not exceed 2,000,000
shares. The maximum value of any performance award granted to any one individual during any calendar year may not exceed $500,000. The exercise price, vesting and duration of any grants may vary and
will be determined at the time of issuance. Options to purchase 1,197,500 shares of the Company's Common Stock were outstanding under this plan as of December 31, 2002.

A
summary of the status of the plans described above, as of the dates indicated, and the changes during the years then ended, is presented in the table and narrative below:

|                                 |  | Years Ended December 31,
|-------------------------------- |  | ------------------------
|
|
|
|Outstanding, beginning of year   |  | 3,919                   
|Granted                          |  | 700                     
|Exercised                        |  | (152                    
|Cancellations                    |  | (154                    
|                                 |  |                         
|Outstanding, end of year         |  | 4,313                   
|                                 |  |                         
|Exercisable, end of year         |  | 1,941                   
|                                 |  |                         
|Available for grant, end of year |  | 759                     
|                                 |  |                         

The
weighted average fair value of options granted during the years ended December 31, 2002, 2001, and 2000 was $24.33, $18.12, and $9.78, respectively. The fair value of
each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 2002, 2001, and 2000, respectively:
(i) risk-free interest rates of 3.47, 4.46 and 6.25 percent; (ii) expected lives of 7.0, 7.0 and 7.0 years, (iii) expected volatility of 126.0, 56.0 and
53.7 percent, and (iv) no dividend yields.

The
following table summarizes information about stock options outstanding at December 31, 2002:

|                   |  | OPTIONS OUTSTANDING |  | OPTIONS EXERCISABLE
|------------------ |  | ------------------- |  | -------------------
|
|
|$3.81 to $12.625   |  | 531                 |  | 5.50               
|$12.6875 to $15.25 |  | 931                 |  | 4.62               
|$15.6875 to $23.75 |  | 1,099               |  | 6.34               
|$23.89 to $30.13   |  | 935                 |  | 8.88               
|$31.00 to $34.00   |  | 817                 |  | 8.09               
|                   |  |                     |  |                    
|                   |  | 4,313               |  | 6.75               
|                   |  |                     |  |                    

In
January 2001, the Company's Chairman and Chief Executive Officer resigned to become the United States Secretary of Commerce. The Company accelerated the vesting of 228,300 of
his outstanding stock options upon his resignation and as a result of this modification to the initial terms of these stock options, a new measurement date was established. Based upon the difference
between the market price of the Company's stock on the date the stock options were amended and the exercise price of the stock options, a non-cash pre-tax charge to earnings of
$3.8 million was recognized.



Effective January 1, 2000, the Company adopted a 401(k) retirement plan that superseded a profit sharing plan and KSOP plan previously in existence.
The Company has a policy to match employee contributions to the plan, at its discretion. As of December 31, 2002, the Company's policy was to match 100% of the employee contribution up to a
total match of seven percent of the employee's salary. The match for the years ended December 31, 2002, 2001 and 2000, was approximately $1,403,000, $864,000 and $492,000, respectively.

(9) Financial Instruments

The carrying values of trade receivables and trade payables approximated market value. The carrying amounts of cash and cash equivalents approximated fair value
due to the short maturity of these instruments. The carrying value of debt approximated fair value because the interest rate is variable and is reflective of current market conditions.



The Company periodically enters into natural gas and crude oil futures contracts with counter parties to hedge the price risk associated with a portion of its
production. These derivatives are not held for trading purposes. To the extent that changes occur in the market prices of natural gas and oil, the Company is exposed to market risk on these open
contracts. This market risk exposure is generally offset by the gain or loss recognized upon the ultimate sale of the commodity hedged.

At
December 31, 2002 the Company had a current derivative liability of $10.9 million, a tax deferred tax asset of $4.0 million and accumulated other comprehensive
loss of approximately $6.5 million. As of December 31, 2001, the Company had no open derivative contracts.



In April and May 2002, the Company entered into several natural gas costless collars (put and call options) that were based on separate regional price indexes where the
Company physically delivers its natural gas. The collars are designated as hedges of production from May through December 2003. In July and August 2002, the Company entered into
several natural gas price swaps and corresponding basis swap transactions that together fixed the price the Company will receive for a portion of its natural gas production. These swaps were designed
as hedges of production from September 2002 through October 2003 in certain of the regions where the Company physically delivers its gas. A derivative loss of $0.4 million was
recognized on the basis portion of these transactions prior to designating the basis contracts as hedges when the corresponding natural gas price swap contracts were executed. In December 2002,
the Company entered into additional costless collar arrangements (put and call options) that were based on several of the regional price indexes where the Company physically delivers its natural gas.
The collars are designed as hedges of production from January 2003 through October 2003.

As
a result of the above transactions, the Company has natural gas hedges, in the form of costless collars and swaps (including related basis swaps) as follows as of December 31,
2002:

|                    |  | Natural Gas Collars |  | Natural Gas Swaps
|------------------- |  | ------------------- |  | -----------------
|
|First Quarter 2003  |  | 37,500              |  | $3.82/5.01       
|Second Quarter 2003 |  | 40,000              |  | $3.37/4.65       
|Third Quarter 2003  |  | 40,000              |  | $3.37/4.65       
|Fourth Quarter 2003 |  | 23,500              |  | $3.27/4.61       

The
Company also entered into certain financial instruments to lock the basis differential on 15,000 Mmbtu/day of firm transportation volumes during the June through October 2002
contract periods. These contracts effectively fixed a price differential into the Mid Continent market at a weighted average price $0.78 above the price index for a delivery point in the Rocky
Mountain area where the Company markets a significant portion of its natural gas production. Under SFAS 133, these basis swaps did not qualify for hedge accounting. Accordingly, these basis
swaps resulted in the recognition of derivative gains and losses directly to earnings. As of December 31, 2002, the Company recognized derivative losses of $2.1 million on these
contracts all of which were settled.

The
Company recognized an increase in gas and oil sales of $17.4 million in 2001 as a result of cash flow hedges. In 2002, cash flow hedges had no impact on gas and oil sales. The
Company recognized a net loss of $2.4 million in 2002 and a gain of $.9 million in 2001 as a result of derivatives that did not qualify as hedges in those years.

In
December 2000, the Company entered into natural gas basis swaps covering essentially the same time period of natural gas costless collars also entered into in
December 2000. Under SFAS 133, these basis swaps did not qualify for hedge accounting. Accordingly, upon adoption of SFAS 133, these basis swaps resulted in the recognition of
derivative gains of $2.0 million, recorded as cumulative effect of a change in accounting principle, (net of the deferred tax liability of $1.2 million) and a derivative asset of
$3.2 million. During the year ended December 31, 2001, a $.9 million gain was recognized in conjunction with the change in the value of these contracts and cash receipts of
$4.1 million were received upon settlement of the swaps.

(10) Related Parties and Significant Customers



One of the Company's directors, Mr. James B. Wallace, participates, both directly as an individual holding minor interests in six producing wells
and indirectly through a partnership, with the Company and other unrelated investors in the drilling, development and operation of gas and oil properties. During the years ended December 31,
2002, 2001 and 2000, the Company billed $111,000, $621,000 and $612,000, respectively, to this partnership for its share of certain leasehold and drilling costs. Receivables and payables arising from
these related party transactions are non-interest bearing and are settled in the normal course of business with terms that, in management's opinion, are similar to those with other joint
owners.

The
Company paid approximately $38,000, $41,000 and $44,000 during the years ended December 31, 2002, 2001 and 2000, respectively, to the consulting firm of Groppe,
Long & Littell of which Mr. Henry Groppe, a director of the Company, is a partner.

In
addition, Mr. Thomas C. Brown, who serves as a director of the Company, is also a director of a drilling contractor that has performed drilling services on wells
operated by the Company. The fees charged for these services were $787,000 for the year ended December 31, 2000. No fees were paid in 2002 or 2001.

In
management's opinion, the above described transactions and services were provided on the same terms as could be obtained from non-related sources.



Gas and oil sales to ConocoPhillips, Inc. accounted for 17%, 11% and 11% of gas and oil sales for the years ended December 31, 2002, 2001 and
2000, respectively. Because there are numerous other parties available to purchase the Company's production, the Company believes the loss of this purchaser would not materially affect its ability to
sell natural gas or crude oil.



The Company's revenues are derived principally from uncollateralized sales to customers in the gas and oil industry. The concentration of credit risk in a single
industry affects the Company's overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. As discussed in the preceding paragraph, the
Company has only one customer that accounted for 10% or more of the Company's total gas and oil revenue during 2002. However, as described in the following paragraph, the Company did have a purchaser
default on payments owed the Company totaling $6.2 million. The Company does attempt to obtain credit protections such as letters of credit, guarantees and prepayments from certain of its
purchasers.



The Company's previous purchaser of its natural gas liquids in the Paradox Basin of Colorado and Utah defaulted on payments owed the Company totaling
$6.2 million in 2002. An allowance for this entire receivable was recorded in the third quarter of 2002 given the uncertainty of collection at that time. The Company continued to aggressively
pursue recovery of the amount owed and in the fourth quarter of 2002, a $1.4 million settlement was received in cash. The collection of this settlement was treated as an adjustment to the
allowance originally recorded. As of December 31, 2002, the Company does not anticipate that any future settlements will be received that will materially reduce the loss recognized as a result
of this purchaser's default.

(11) Allowance for Doubtful Accounts

The allowance for doubtful accounts is recorded as a reduction of accounts receivable in the Consolidated Balance Sheets. Changes in the allowance for doubtful
accounts are as follows (in thousands):

|                                |  | Years Ended December 31, |       
|------------------------------- |  | ------------------------ | ------
|
|Balance January 1               |  | $                        | 710   
|Charged to bad debt expense     |  |                          | 5,222 
|Acquisition of Stellarton       |  |                          |      
|Accounts receivable written off |  |                          | (4,954
|                                |  |                          |       
|Balance December 31             |  | $                        | 978   
|                                |  |                          |       

(12) Segment Information

The Company operates in three reportable segments: (i) gas and oil exploration and development in the United States and Canada, (ii) marketing,
gathering and processing and (iii) drilling. The long-term financial performance of each of the reportable segments is affected by similar economic conditions.

The
Company's gas and oil exploration and development segment operates primarily in the Wind River and Green River Basins of Wyoming, the Piceance Basin of Colorado, the Paradox Basin of
Utah and Colorado, the Val Verde Basin of west Texas, the Permian Basin of west Texas and southwestern New Mexico, the east Texas basin and the western sedimentary basin of Canada. The marketing,
gathering and processing activities of the Company are conducted primarily in the Rocky Mountain region. The drilling segment operates under the name of Sauer Drilling Company and serves the drilling
needs of operators in the central Rocky Mountain region in addition to drilling for the Company.

The
accounting policies of the segments are the same as those described in Note 2 of the Notes to Consolidated Financial Statements. The Company evaluates performance based on
profit or loss from operations before income taxes, accounting changes, nonrecurring items and interest income and expense.

The
Company accounts for intersegment sales transfers as if the sales or transfers were to third parties, that is, at current prices.

The
following tables present information related to the Company's reportable segments (in thousands):

|                                                                                    |                                 | As of or Year Ended December 31, 2002 |        
|----------------------------------------------------------------------------------- | ------------------------------- | ------------------------------------- | -------
|
|Revenues from external purchasers                                                   |                                 | $                                     | 114,039
|Intersegment revenues                                                               |                                 |                                       | 52,463 
|                                                                                    |                                 |                                       |        
|                                                                                    | Total revenues                  |                                       |        
|Marketing and trading expenses offset against related revenues for net presentation |                                 |                                       |       
|Intersegment eliminations                                                           |                                 |                                       |       
|                                                                                    |                                 |                                       |        
|                                                                                    | Total segment revenue           |                                       |        
|Cash paid on derivatives                                                            |                                 |                                       |       
|Gain on sale of property                                                            |                                 |                                       | 4,114  
|Loss on marketable security                                                         |                                 |                                       | (600   
|Change in derivative fair value                                                     |                                 |                                       | (345   
|Interest income and other                                                           |                                 |                                       | 70     
|                                                                                    |                                 |                                       |        
|                                                                                    | Total consolidated revenues     |                                       | $      
|                                                                                    |                                 |                                       |        
|Profit                                                                              |                                 |                                       |        
|                                                                                    | Total reportable segment profit |                                       | $      
|                                                                                    | Interest expense and other      |                                       |        
|                                                                                    | Gain on sale of property        |                                       |        
|                                                                                    | Loss on marketable security     |                                       |        
|                                                                                    | Eliminations                    |                                       |        
|                                                                                    |                                 |                                       |        
|Income before income taxes and cumulative effect of change in accounting principle  |                                 | $                                     | 3,479  
|                                                                                    |                                 |                                       |        
|Depreciation, depletion and amortization                                            |                                 | $                                     | 72,788 
|                                                                                    |                                 |                                       |        
|Assets                                                                              |                                 |                                       |        
|                                                                                    | Total reportable segment assets |                                       | $      
|                                                                                    | Intersegment eliminations       |                                       |        
|                                                                                    |                                 |                                       |        
|                                                                                    | Total consolidated assets       |                                       | $      
|                                                                                    |                                 |                                       |        
|Capital and exploration expenditures                                                |                                 | $                                     | 144,882
|                                                                                    |                                 |                                       |        



|                                                                                    |                                 | As of or Year Ended December 31, 2001 |        
|----------------------------------------------------------------------------------- | ------------------------------- | ------------------------------------- | -------
|
|Revenues from external purchasers                                                   |                                 | $                                     | 173,422
|Intersegment revenues                                                               |                                 |                                       | 70,476 
|                                                                                    |                                 |                                       |        
|                                                                                    | Total revenues                  |                                       |        
|Marketing and trading expenses offset against related revenues for net presentation |                                 |                                       |       
|Intersegment eliminations                                                           |                                 |                                       |       
|                                                                                    |                                 |                                       |        
|                                                                                    | Total segment revenue           |                                       |        
|Cash paid on derivatives                                                            |                                 |                                       |       
|Gain on sale of property                                                            |                                 |                                       | 10,078 
|Change in derivative fair value                                                     |                                 |                                       | (3,224 
|Interest income and other                                                           |                                 |                                       | 1,369  
|                                                                                    |                                 |                                       |        
|                                                                                    | Total consolidated revenues     |                                       | $      
|                                                                                    |                                 |                                       |        
|Profit                                                                              |                                 |                                       |        
|                                                                                    | Total reportable segment profit |                                       | $      
|                                                                                    | Interest expense and other      |                                       |        
|                                                                                    | Gain on sale of property        |                                       |        
|                                                                                    | Eliminations                    |                                       |        
|                                                                                    |                                 |                                       |        
|Income before income taxes and cumulative effect of change in accounting principle  |                                 | $                                     | 96,723 
|                                                                                    |                                 |                                       |        
|Depreciation, depletion and amortization                                            |                                 | $                                     | 55,692 
|                                                                                    |                                 |                                       |        
|Assets                                                                              |                                 |                                       |        
|                                                                                    | Total reportable segment assets |                                       | $      
|                                                                                    | Intersegment eliminations       |                                       |        
|                                                                                    |                                 |                                       |        
|                                                                                    | Total consolidated assets       |                                       | $      
|                                                                                    |                                 |                                       |        
|Capital and exploration expenditures                                                |                                 | $                                     | 316,934
|                                                                                    |                                 |                                       |        



|                                                                                    |                                 | As of or Year Ended December 31, 2000 |        
|----------------------------------------------------------------------------------- | ------------------------------- | ------------------------------------- | -------
|
|Revenues from external purchasers                                                   |                                 | $                                     | 170,617
|Intersegment revenues                                                               |                                 |                                       | 46,351 
|                                                                                    |                                 |                                       |        
|                                                                                    | Total revenues                  |                                       |        
|Marketing and trading expenses offset against related revenues for net presentation |                                 |                                       |       
|Intersegment eliminations                                                           |                                 |                                       |       
|                                                                                    |                                 |                                       |        
|                                                                                    | Total segment revenue           |                                       |        
|Interest income and other                                                           |                                 |                                       | 1,076  
|                                                                                    |                                 |                                       |        
|                                                                                    | Total consolidated revenues     |                                       | $      
|                                                                                    |                                 |                                       |        
|Profit                                                                              |                                 |                                       |        
|                                                                                    | Total reportable segment profit |                                       | $      
|                                                                                    | Interest expense and other      |                                       |        
|                                                                                    | Eliminations                    |                                       |        
|                                                                                    |                                 |                                       |        
|Income before income taxes and cumulative effect of change in accounting principle  |                                 | $                                     | 93,350 
|                                                                                    |                                 |                                       |        
|Depreciation, depletion and amortization                                            |                                 |                                       |        
|Total reportable segment depreciation, depletion and amortization                   |                                 | $                                     | 46,853 
|Elimination                                                                         |                                 |                                       | (1,102 
|                                                                                    |                                 |                                       |        
|                                                                                    | Total consolidated depreciation |                                       | $      
|                                                                                    |                                 |                                       |        
|Assets                                                                              |                                 |                                       |        
|                                                                                    | Total reportable segment assets |                                       | $      
|                                                                                    | Intersegment eliminations       |                                       |        
|                                                                                    |                                 |                                       |        
|                                                                                    | Total consolidated assets       |                                       | $      
|                                                                                    |                                 |                                       |        
|Capital and exploration expenditures                                                |                                 | $                                     | 132,117
|                                                                                    |                                 |                                       |        

(13) Commitments and Contingencies

The Company's operations are subject to numerous governmental regulations that may give rise to claims against the Company. In addition, the Company is a
defendant in various lawsuits generally incidental to its business. The Company does not believe that the ultimate resolution of such litigation will have a material adverse effect on the Company's
financial position, results of operations or cash flows.

The
Company is a party to an action brought in Sweetwater County, Wyoming by three overriding royalty interest owners seeking certification as a class of all non-governmental
entities which are paid royalties or overriding royalties by the Company in Wyoming. This action is one of more than a dozen virtually identical class action lawsuits filed in various Wyoming courts
against producers and operators in Wyoming. The complaint alleges that the Company violated the Wyoming Royalty Payment Act (the "Act") by improperly deducting gas transportation costs in calculating
royalties and overriding royalties


on Wyoming production and by failing to properly itemize all deductions taken on its payee reports. The complaint does not allege specific money damages. The issue in the case is whether
transportation of natural gas off the lease to market is deductible transportation or nondeductible gathering within the meaning of the Act. In January 2003, the Wyoming Supreme Court agreed to
answer two certified questions in a separate lawsuit which are (1) what is meant by the term "gathering" as that term is employed in the Act in defining nondeductible "costs of production," and
(2) when do the causes of action for recovery of the reporting penalty and for improper deductions under the Act accrue. Because of the preliminary nature of the proceedings, it is not possible
to fully determine the ultimate loss exposure or probable outcome of this litigation.



At December 31, 2002, the Company had long-term leases through 2004 covering certain of its facilities and equipment. The minimum rental
commitments under non-cancelable operating leases with lease terms in excess of one year are as follows:

Years Ending
December 31,

Commitment
Amount(In thousands)2003

$
1,6392004


3482005


1462006


272007


11Thereafter


11$
2,182


Total
rental expense incurred for the years ended December 31, 2002, 2001 and 2000, was approximately $1,648,000, $1,558,000 and $1,447,000, respectively, all of which
represented minimum rentals under non-cancelable operating leases.



The Company's obligation for firm transportation commitments in effect at December 31, 2002 for the next five years and thereafter is as follows:

Years Ending
December 31,

Commitment
Amount(In thousands)2003

$
5,2742004


3,5762005


2,8102006


1,0522007


368Thereafter


228$
13,308




Subsequent
to December 31, 2002, the Company entered into additional firm transportation agreements to market its production in the Rocky Mountain region. The additional
commitments for the next five years and thereafter are as follows:

Years Ending
December 31,

Commitment
Amount(In thousands)2003

$
1,4682004


2,7192005


2,7192006


2,7192007


2,719Thereafter


7,216$
19,560




In March 2001, the Company entered into a new gas processing agreement to expand available capacity for its gas production from the White River Dome coal
bed methane project in the Piceance Basin. The plant commenced operations in October 2001. The Company is obligated to pay processing fees for certain variable expenses of the plant associated
with the processed volumes and compression made available during the ten-year term of this agreement. Additionally, the fixed operating costs and capital recovery obligations to the plant
contractor total approximately $220,000 per month over the term of this agreement.



To assure the availability of a drilling rig in conjunction with the continuing exploration program at the Deep Valley prospect in west Texas, the Company entered
into a two-year commitment with a drilling contractor in 2001. The rig became available on March 1, 2002 after which a 90-day period was allowed under the terms of the
agreement to mobilize the rig and commence the two-year drilling obligation. On May 29, 2002, the Company commenced drilling operations with this rig which was the start of the
two-year obligation. Under the terms of this arrangement, the Company is obligated to ultimately pay a day rate of $20,100 per day during drilling operations, $16,700 per day for rig moves
and a special standby fee of $6,000 per day during the initial 90-day commencement period. The special standby fees paid between March 1, 2002 and May 29, 2002 of
$.5 million were expensed. The Company also expensed standby fees incurred when the rig was idle between drilling operations of $1.1 million in 2002.



Rocno Corporation, a wholly-owned subsidiary of the Company, is a party to a trust agreement in connection with the environmental clean-up plan for
the Sheridan Superfund Site in Waller County, Texas. Rocno's share of the estimated cleanup costs was accrued in the consolidated financial statements at December 31, 2002. Based on the amount
of remediation costs estimated for this site and the Company'sde minimiscontribution, if any, the Company believes that the outcome of this site
restoration project will not have a material adverse effect on its financial position or results of operations.



(14) Quarterly Financial Data (Unaudited)

|                                                                    |         | First
Quarter |         | Second
Quarter |   | Third
Quarter |     | Fourth
Quarter |        | Total |  
|------------------------------------------------------------------- | ------- | ------------- | ------- | -------------- | - | ------------- | --- | -------------- | ------ | ----- | -
|
|Year ended December 31, 2002                                        |         |               |         |                |   |               |     |                |        |       |  
|Revenues                                                            |         | $             | 48,294  |                | $ | 63,975        |     | $              | 52,165 |       | $
|Net (loss) income attributable to common stock                      |         |               | (18,474 | )              |   | 4,755         |     |                | (1,831 | )     |  
|Net (loss) income attributable to common stock per common share (1) |         |               |         |                |   |               |     |                |        |       |  
|                                                                    | Basic   |               |         | (.47           | ) |               | .12 |                |        | (.05  | )
|                                                                    | Diluted |               |         | (.47           | ) |               | .12 |                |        | (.05  | )
|Year ended December 31, 2001                                        |         |               |         |                |   |               |     |                |        |       |  
|Revenues                                                            |         | $             | 118,684 |                | $ | 95,386        |     | $              | 59,252 |       | $
|Net income attributable to common stock                             |         |               | 37,466  |                |   | 26,234        |     |                | 5,770  |       |  
|Net income attributable to common stock per common share (1)        |         |               |         |                |   |               |     |                |        |       |  
|                                                                    | Basic   |               |         | .97            |   |               | .67 |                |        | .15   |  
|                                                                    | Diluted |               |         | .93            |   |               | .65 |                |        | .14   |  

---

(15) Supplemental Information Related to Gas and Oil Activities

The following tables set forth certain historical costs and operating information related to the Company's gas and oil producing activities:



|                                |                                                            | December 31, |        
|------------------------------- | ---------------------------------------------------------- | ------------ | -------
|
|Capitalized costs               |                                                            |              |        
|Proved gas and oil properties   |                                                            | $            | 907,006
|Unproved gas and oil properties |                                                            |              | 52,801 
|                                |                                                            |              |        
|Total gas and oil properties    |                                                            |              | 959,807
|                                | Less: Accumulated depreciation, depletion and Amortization |              |        
|                                |                                                            |              |        
|Net capitalized costs           |                                                            | $            | 668,824
|                                |                                                            |              |        



|     |                                     | United
States |   | Canada  |         | Total
|---- | ----------------------------------- | ------------- | - | ------- | ------- | -----
|2002 |                                     |               |   |         |         |      
|     | Costs incurred                      |               |   |         |         |      
|     | Proved property acquisition costs   |               | $ | 15,878  |         | $    
|     | Unproved property acquisition costs |               |   | 7,601   |         |      
|     | Exploration costs                   |               |   | 32,482  |         |      
|     | Development costs                   |               |   | 85,319  |         |      
|     |                                     |               |   |         |         |      
|     |                                     | Total         |   | $       | 141,280 |      
|     |                                     |               |   |         |         |      
|2001 |                                     |               |   |         |         |      
|     | Costs incurred                      |               |   |         |         |      
|     | Proved property acquisition costs   |               | $ | 3,649   |         | $    
|     | Unproved property acquisition costs |               |   | 16,496  |         |      
|     | Exploration costs                   |               |   | 55,357  |         |      
|     | Development costs                   |               |   | 138,815 |         |      
|     |                                     |               |   |         |         |      
|     |                                     | Total         |   | $       | 214,317 |      
|     |                                     |               |   |         |         |      
|2000 |                                     |               |   |         |         |      
|     | Costs incurred                      |               |   |         |         |      
|     | Proved property acquisition costs   |               | $ | 17,111  |         | $    
|     | Unproved property acquisition costs |               |   | 16,831  |         |      
|     | Exploration costs                   |               |   | 18,362  |         |      
|     | Development costs                   |               |   | 74,406  |         |      
|     |                                     |               |   |         |         |      
|     |                                     | Total         |   | $       | 126,710 |      
|     |                                     |               |   |         |         |      



The following summarizes the policies used by the Company in preparing the accompanying gas and oil reserve disclosures, Standardized Measure of Discounted Future
Net Cash Flows Relating to Proved Gas and Oil Reserves and reconciliation of such standardized measure between years.

Estimates
of proved and proved developed reserves were prepared by the Company's petroleum engineering staff and reviewed by the independent petroleum consultants. The Company's gas, oil
and natural gas liquids reserves are located in the United States and Canada.

Reserves
have been classified as proved, proved developed and proved undeveloped pursuant to the following definitions:

Proved gas and oil reserves.Proved gas and oil reserves are the estimated quantities of natural gas, crude oil and natural
gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e.,
prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the
immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of


information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Estimates
of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves";
(B) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors;
(C) crude oil, natural gas and natural gas liquids that may occur in undrilled prospects; and (D) crude oil, natural gas and natural gas liquids that may be recovered from oil shales,
coal, gilsonite and other such sources.

Proved developed gas and oil reserves.Proved developed gas and oil reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.

Proved undeveloped reserves.Proved undeveloped gas and oil reserves are reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting
productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity
of production from the existing productive formation.

The
standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:



The
standardized measure of discounted future net cash flows does not purport to present, nor should it be interpreted to present, the fair value of the Company's gas, oil and natural
gas liquids reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and
costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The
Company estimates future development costs utilizing current costs in the oilfield service sector for the planned operations. The actual costs will vary based upon the service sector
costs at the time the work is performed and may be higher than the estimates due to difficulties encountered during the drilling operations.



The following table presents estimates of the Company's net proved and proved developed natural gas, oil and natural gas liquids.

|                                        |                                 | Reserve Quantities |        
|--------------------------------------- | ------------------------------- | ------------------ | -------
|
|
|Proved reserves:                        |                                 |                    |        
|Estimated reserves at December 31, 1999 |                                 | 445,933            |        
|                                        | Revisions of previous estimates |                    | 50,852 
|                                        | Purchases of minerals in place  |                    | 28,960 
|                                        | Extensions and discoveries      |                    | 60,827 
|                                        | Sales of minerals in place      |                    |       
|                                        | Production                      |                    | (51,199
|                                        |                                 |                    |        
|Estimated reserves at December 31, 2000 |                                 | 535,373            |        
|                                        | Revisions of previous estimates |                    | (47,647
|                                        | Purchases of minerals in place  |                    | 3,000  
|                                        | Extensions and discoveries      |                    | 164,561
|                                        | Sales of minerals in place      |                    | (16,072
|                                        | Production                      |                    | (57,163
|                                        |                                 |                    |        
|Estimated reserves at December 31, 2001 |                                 | 582,052            |        
|                                        | Revisions of previous estimates |                    | 8,304  
|                                        | Purchases of minerals in place  |                    | 15,661 
|                                        | Extensions and discoveries      |                    | 79,582 
|                                        | Sales of minerals in place      |                    | (6,322 
|                                        | Production                      |                    | (65,781
|                                        |                                 |                    |        
|Estimated reserves at December 31, 2002 |                                 | 613,496            |        
|                                        |                                 |                    |        
|Proved developed reserves:              |                                 |                    |        
|                                        | December 31, 1999               |                    | 333,858
|                                        | December 31, 2000               |                    | 431,824
|                                        | December 31, 2001               |                    | 428,719
|                                        | December 31, 2002               |                    | 451,183



|                                        |                                 | Reserve Quantities |       
|--------------------------------------- | ------------------------------- | ------------------ | ------
|
|
|Proved reserves:                        |                                 |                    |       
|Estimated reserves at December 31, 1999 |                                 | 6,266              |       
|                                        | Revisions of previous estimates |                    | (115  
|                                        | Purchases of minerals in place  |                    |      
|                                        | Extensions and discoveries      |                    |      
|                                        | Sales of minerals in place      |                    |      
|                                        | Production                      |                    | (1,074
|                                        |                                 |                    |       
|Estimated reserves at December 31, 2000 |                                 | 5,077              |       
|                                        | Revisions of previous estimates |                    | 529   
|                                        | Purchases of minerals in place  |                    |      
|                                        | Extensions and discoveries      |                    | 2,102 
|                                        | Sales of minerals in place      |                    |      
|                                        | Production                      |                    | (1,074
|                                        |                                 |                    |       
|Estimated reserves at December 31, 2001 |                                 | 6,634              |       
|                                        | Revisions of previous estimates |                    | (956  
|                                        | Purchases of minerals in place  |                    |      
|                                        | Extensions and discoveries      |                    | 186   
|                                        | Sales of minerals in place      |                    |      
|                                        | Production                      |                    | (1,189
|                                        |                                 |                    |       
|Estimated reserves at December 31, 2002 |                                 | 4,675              |       
|                                        |                                 |                    |       
|Proved developed reserves:              |                                 |                    |       
|                                        | December 31, 1999               |                    | 5,979 
|                                        | December 31, 2000               |                    | 5,077 
|                                        | December 31, 2001               |                    | 5,577 
|                                        | December 31, 2002               |                    | 4,002 

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas and Oil Reserves (Unaudited) (in thousands):

|                                                         |  | December 31, 2002 |          
|-------------------------------------------------------- |  | ----------------- | ---------
|
|Future cash flows                                        |  | $                 | 2,243,751
|Future production costs                                  |  |                   | (732,739 
|Future development costs (1)                             |  |                   | (175,085 
|                                                         |  |                   |          
|Future net cash flows before tax                         |  |                   | 1,335,927
|Future income taxes                                      |  |                   | (367,271 
|                                                         |  |                   |          
|Future net cash flows after tax                          |  |                   | 968,656  
|Annual discount at 10%                                   |  |                   | (405,487 
|                                                         |  |                   |          
|Standardized measure of discounted future net cash flows |  | $                 | 563,169  
|                                                         |  |                   |          
|Discounted future net cash flows before income taxes     |  | $                 | 744,608  
|                                                         |  |                   |          



|                                                         |  | December 31, 2001 |          
|-------------------------------------------------------- |  | ----------------- | ---------
|
|Future cash flows                                        |  | $                 | 1,448,747
|Future production costs                                  |  |                   | (530,791 
|Future development costs                                 |  |                   | (164,226 
|                                                         |  |                   |          
|Future net cash flows before tax                         |  |                   | 753,730  
|Future income taxes                                      |  |                   | (89,389  
|                                                         |  |                   |          
|Future net cash flows after tax                          |  |                   | 664,341  
|Annual discount at 10%                                   |  |                   | (275,838 
|                                                         |  |                   |          
|Standardized measure of discounted future net cash flows |  | $                 | 388,503  
|                                                         |  |                   |          
|Discounted future net cash flows before income taxes     |  | $                 | 429,906  
|                                                         |  |                   |          

|                                                         |  | December 31, 2000 |           
|-------------------------------------------------------- |  | ----------------- | ----------
|
|Future cash flows                                        |  | $                 | 5,028,357 
|Future production costs                                  |  |                   | (857,767  
|Future development costs                                 |  |                   | (89,216   
|                                                         |  |                   |           
|Future net cash flows before tax                         |  |                   | 4,081,374 
|Future income taxes                                      |  |                   | (1,409,295
|                                                         |  |                   |           
|Future net cash flows after tax                          |  |                   | 2,672,079 
|Annual discount at 10%                                   |  |                   | (1,196,324
|                                                         |  |                   |           
|Standardized measure of discounted future net cash flows |  | $                 | 1,475,755 
|                                                         |  |                   |           
|Discounted future net cash flows before income taxes     |  | $                 | 2,187,925 
|                                                         |  |                   |           

---

|     |  | United
States |         | Canada |   | Total
|---- |  | ------------- | ------- | ------ | - | -----
|2003 |  | $             | 61,707  |        | $ | 6,718
|2004 |  |               | 49,796  |        |   |     
|2005 |  |               | 41,444  |        |   |     
|     |  |               |         |        |   |      
|     |  | $             | 152,947 |        | $ | 6,718
|     |  |               |         |        |   |      



The
costs estimated to develop proved developed non-producing reserves over the next three years are as follows (in thousands):

|     |  | United
States |       | Canada |   | Total
|---- |  | ------------- | ----- | ------ | - | -----
|2003 |  | $             | 6,198 |        | $ | 2,607
|2004 |  |               | 2,108 |        |   | 1,305
|2005 |  |               | 1,172 |        |   |     
|     |  |               |       |        |   |      
|     |  | $             | 9,478 |        | $ | 3,912
|     |  |               |       |        |   |      



|                                                      |  | Year Ended December 31, 2002 |         
|----------------------------------------------------- |  | ---------------------------- | --------
|
|Gas and oil sales, net of production costs (1)        |  | $                            | (122,574
|Net changes in anticipated prices and production cost |  |                              | 265,587 
|Extensions and discoveries, less related costs        |  |                              | 95,798  
|Changes in estimated future development costs         |  |                              | 2,752   
|Previously estimated development costs incurred (2)   |  |                              | 37,124  
|Net change in income taxes                            |  |                              | (140,036
|Purchase of minerals in place                         |  |                              | 16,970  
|Sales of minerals in place                            |  |                              | (11,383 
|Accretion of discount                                 |  |                              | 42,990  
|Revision of quantity estimates                        |  |                              | 7,586   
|Changes in production rates and other                 |  |                              | (20,148 
|                                                      |  |                              |         
|Change in Standardized Measure                        |  | $                            | 174,666 
|                                                      |  |                              |         

---



|                                                      |  | Year Ended December 31, 2001 |           
|----------------------------------------------------- |  | ---------------------------- | ----------
|
|Gas and oil sales, net of production costs (3)        |  | $                            | (180,218  
|Net changes in anticipated prices and production cost |  |                              | (1,821,163
|Extensions and discoveries, less related costs        |  |                              | 92,376    
|Changes in estimated future development costs         |  |                              | (868      
|Previously estimated development costs incurred (4)   |  |                              | 36,691    
|Net change in income taxes                            |  |                              | 670,767   
|Purchase of minerals in place                         |  |                              | 3,500     
|Sales of minerals in place                            |  |                              | (61,623   
|Accretion of discount                                 |  |                              | 218,793   
|Revision of quantity estimates                        |  |                              | (34,549   
|Changes in production rates and other                 |  |                              | (10,957   
|                                                      |  |                              |           
|Change in Standardized Measure                        |  | $                            | (1,087,251
|                                                      |  |                              |           

---

|                                                      |  | Year Ended December 31, 2000 |          
|----------------------------------------------------- |  | ---------------------------- | ---------
|
|Gas and oil sales, net of production costs            |  | $                            | (169,375 
|Net changes in anticipated prices and production cost |  |                              | 1,535,058
|Extensions and discoveries, less related costs        |  |                              | 251,410  
|Changes in estimated future development costs         |  |                              | 8,831    
|Previously estimated development costs incurred (5)   |  |                              | 26,084   
|Net change in income taxes                            |  |                              | (652,306 
|Purchase of minerals in place                         |  |                              | 18,917   
|Sales of minerals in place                            |  |                              | (679     
|Accretion of discount                                 |  |                              | 39,343   
|Revision of quantity estimates                        |  |                              | 198,625  
|Changes in production rates and other                 |  |                              | (113,712 
|                                                      |  |                              |          
|Change in Standardized Measure                        |  | $                            | 1,142,196
|                                                      |  |                              |          

---



Results of Operations from Producing Activities

Results of operations from producing activities are presented below (in thousands). Income taxes as calculated are based upon the statutory income tax rates in
the United States and Canada adjusted for any permanent tax differences and tax credits relating to producing activities:

|                                                |                | December 31, 2002
|----------------------------------------------- | -------------- | -----------------
|
|Gas, oil and natural gas liquid sales           |                | $                
|Gas and oil production expense                  |                |                  
|Taxes on gas and oil production                 |                |                  
|Depreciation and depletion                      |                |                  
|Exploration costs                               |                |                  
|Income tax expense                              |                |                  
|                                                |                |                  
|                                                | Total expenses |                  
|                                                |                |                  
|Results of operations from producing activities |                | $                
|                                                |                |                  

|                                                |                | December 31, 2001
|----------------------------------------------- | -------------- | -----------------
|
|Gas, oil and natural gas liquid sales           |                | $                
|Gas and oil production expense                  |                |                  
|Taxes on gas and oil production                 |                |                  
|Depreciation and depletion                      |                |                  
|Exploration costs                               |                |                  
|Income tax expense                              |                |                  
|                                                |                |                  
|                                                | Total expenses |                  
|                                                |                |                  
|Results of operations from producing activities |                | $                
|                                                |                |                  

|                                                |                | December 31, 2000
|----------------------------------------------- | -------------- | -----------------
|
|Gas, oil and natural gas liquid sales           |                | $                
|Gas and oil production expense                  |                |                  
|Taxes on gas and oil production                 |                |                  
|Depreciation and depletion                      |                |                  
|Exploration costs                               |                |                  
|Income tax expense                              |                |                  
|                                                |                |                  
|                                                | Total expenses |                  
|                                                |                |                  
|Results of operations from producing activities |                | $                
|                                                |                |                  





ITEM 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

On March 19, 2002, Arthur Andersen LLP ("Andersen") was dismissed as independent accountant for Tom Brown, Inc. (the "Company") effective upon
completion of its audit of the Company's financial statements for the year ended December 31, 2001, and KPMG LLP ("KPMG") was appointed as the new independent accountant for the Company to
replace Andersen for the year ending December 31, 2002. The decision to dismiss Andersen and to appoint KPMG was recommended by the Audit Committee of the Board of Directors and was approved by
the Board of Directors at its meeting on March 19, 2002.

Andersen's
reports on the Company's financial statements for the two fiscal years ended December 31, 2000 and December 31, 2001, did not contain an adverse opinion
or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles.

During
the Company's two most recent fiscal years and the period from January 1, 2002 through March 19, 2002, there were no disagreements between the Company and
Andersen on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Andersen,
would have caused it to make reference to the subject matter of the disagreements in connection with its report.

PART III

ITEM 10.Directors and Executive Officers of the Registrant

Certain information regarding Directors of the Company will be included in the Company's definitive proxy statement (under the captions "Election of Directors"
and "Section 16(a) Beneficial Ownership Reporting Compliance") to be filed with the Securities and Exchange Commission not later than
120 days after the end of the Company's fiscal year covered by this Form 10-K and such information is incorporated by reference to the Company's definitive proxy statement.
Information concerning the Executive Officers of the Company appears under Part IItem 4A of this Annual Report on Form 10-K.

ITEM 11.Executive Compensation

Certain information regarding compensation of executive officers of the Company will be included in the Company's definitive proxy statement (under the caption
"Executive Compensation") to be filed with the Securities and Exchange Commission not later than 120 days after the end of the Company's fiscal year covered by this Form 10-K
and such information is incorporated by reference to the Company's definitive proxy statement.

ITEM 12.Security Ownership of Certain Beneficial Owners and Management

Certain information regarding security ownership of certain beneficial owners and management will be included in the Company's definitive proxy statement (under
the caption "Security Ownership of Certain Beneficial Owners and Management") to be filed with the Securities and Exchange Commission not later than 120 days after the end of the Company's
fiscal year covered by this Form 10-K and such information is incorporated by reference to the Company's definitive proxy statement.



The following table provides information as of December 31, 2002 regarding the number of shares of Common Stock that may be issued under the Company's
equity compensation plans.

|Plan Category                                              |               | Number of shares
to be issued upon
exercise of
outstanding
options, warrants
and rights
as of December 31, 2002 |           | Weighted-average
exercise price of
outstanding
options, warrants
and rights
as of December 31, 2002 |       | Number of shares
remaining available
for future issuance
under equity
compensation plans
as of December 31, 2002 |         |        
|---------------------------------------------------------- | ------------- | --------------------------------------------------------------------------------------------------------------- | --------- | --------------------------------------------------------------------------------------------------- | ----- | ---------------------------------------------------------------------------------------------------------------- | ------- | -------
|Equity compensation plans approved by security holders     |               |                                                                                                                 |           |                                                                                                     |       |                                                                                                                  |         |        
|                                                           | 1989 Plan (1) |                                                                                                                 | 336,216   |                                                                                                     | $     | 14.99                                                                                                            |         |       
|                                                           | 1999 Plan     |                                                                                                                 | 1,197,513 |                                                                                                     | $     | 22.20                                                                                                            |         | 680,000
|Equity compensation plans not approved by security holders |               |                                                                                                                 |           |                                                                                                     |       |                                                                                                                  |         |        
|                                                           | 1993 Plan (2) |                                                                                                                 | 2,778,960 |                                                                                                     | $     | 20.91                                                                                                            |         | 79,184 
|                                                           |               |                                                                                                                 |           |                                                                                                     |       |                                                                                                                  |         |        
|TOTAL                                                      |               | 4,312,689                                                                                                       |           | $                                                                                                   | 20.81 |                                                                                                                  | 759,184 |        
|                                                           |               |                                                                                                                 |           |                                                                                                     |       |                                                                                                                  |         |        

---

ITEM 13.Certain Relationships and Related Transactions

Certain information regarding transactions with management and other related parties can be found in Note 10Related Parties and Significant
Customers in the Notes to the Company's Consolidated Financial Statements. Additional information will be included in the Company's definitive proxy statement (under the caption "Certain Relationships
and Related Transactions") to be filed with the Securities and Exchange Commission not later than 120 days after the end of the Company's fiscal year covered by this
Form 10-K and such information is incorporated by reference to the Company's definitive proxy statement.

ITEM 14.Controls and Procedures

The Company's management, including the Chief Executive Officer and Chief Financial Officer, have conducted an evaluation of the effectiveness of disclosure
controls and procedures pursuant to Exchange Act Rule 13a-14. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure
controls and procedures are effective in ensuring that all material information required to be filed in this annual report has been made known to them in a timely fashion. There have been no
significant changes in internal controls, or in factors that could significantly affect internal controls, subsequent to the date the Chief Executive Officer and Chief Financial Officer completed
their evaluation.





PART IV

ITEM 15.Exhibits, Consolidated Financial Statement Schedules and Reports on Form 8-K

(1) See Index to Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

(2) None

(3) Exhibits:

|2.1  |  |  |  | Purchase and Sale Agreement, dated June 8, 1999, between Union Oil Company of California and the Registrant. (Incorporated by reference to Exhibit 10.1 in the Registrant's Form 8-K Report dated July 19,
 1999 and filed with the Securities and Exchange Commission on July 19, 1999) (File No. 000-03880)                                     
|---- |  | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.2  |  |  |  | Pre-Acquisition Agreement, dated December 13, 2000, between Stellarton Energy Corporation and the Registrant. (Incorporated by reference to Exhibit 2.2 in the Registrant's Form 10-K Report for the fiscal year ended December 31,
2000, and filed with the Securities and Exchange Commission on March 13, 2001) (File No. 000-03880)           
|3.1  |  |  |  | Certificate of Incorporation, as amended, of the Registrant. (Incorporated by reference to Exhibit 3.1 in the Registrant's Form S-8 Report filed with the Securities and Exchange Commission on December 6, 2000) (Registration No.
333-51320)                                                                                                    
|3.2  |  |  |  | Amended and Restated Bylaws, dated May 10, 2001. (Incorporated by reference to Exhibit 3.1 in the Registrant's Form 10-Q, for the quarterly period ended March 31, 2001, and filed with the Securities and Exchange Commission on
May 15, 2001) (File No. 000-03880)                                                                              
|4.1  |  |  |  | First Amended and Restated Rights Agreement dated March 1, 2001 between the Registrant and EquiServe Trust Company, N.A. (Incorporated by reference to Exhibit 4.2 in the Registrant's Form 10-K Report for the fiscal year ended
December 31, 2000, and filed with the Securities and Exchange Commission on March 13, 2001) (File No. 000-03880)
|10.1 |  |  |  | Stock Ownership and Registration Rights Agreement dated June 29, 1999 between Union Oil Company of California and the Registrant. (Incorporated by reference to Exhibit 10.2 in the Registrant's Form 8-K Report dated July 19, 1999,
and filed with the Securities and Exchange Commission on July 19, 1999) (File No. 000-03880)                
|10.2 |  |  |  | U.S. Revolving Credit Agreement dated March 20, 2001. (Incorporated by reference to Exhibit 10.2 in the Registrant's Form 10-Q Report for the quarterly period ended March 31, 2001 and filed with the Securities and Exchange
Commission on May 14, 2001) (File No. 000-03880)                                                                   
|10.3 |  |  |  | Canadian Revolving Credit Agreement dated March 20, 2001. (Incorporated by reference to Exhibit 10.3 in the Registrant's Form 10-Q Report for the quarterly period ended March 31, 2001 and filed with the Securities and Exchange
Commission on May 14, 2001) (File No. 000-03880)                                                               
|10.4 |  |  |  | Canadian Term Credit Agreement dated March 20, 2001. (Incorporated by reference to Exhibit 10.4 in the Registrant's Form 10-Q Report for the quarterly period ended March 31, 2001 and filed with the Securities and Exchange
Commission on May 14, 2001) (File No. 000-03880)                                                                    
|     |  |   |  |                                                                                                                                                                                                                                                                                                                                                   

|10.5    |  |  |  | Credit Agreement dated June 30, 2000, among the Registrant, The Chase Manhattan Bank and the other lenders parties thereto. (Incorporated by reference to Exhibit 10.1 in the Registrant's Form 10-Q Report for the quarterly period ended
June 30, 2000, and filed with the Securities and Exchange Commission on August 14, 2000) (File No. 000-03880)
|------- |  | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.6    |  |  |  | Credit Agreement, dated as of April 17, 1998, among the Registrant, The Chase Manhattan Bank and the other lenders parties thereto. (Incorporated by reference to Exhibit 10.1 in the Registrant's Form 10-Q for the quarterly period ended
March 31, 1998, and filed with the Securities and Exchange Commission on May 14, 1998) (File No. 000-03880) 
|10.7    |  |  |  | First Amendment, dated October 19, 1998, to the Credit Agreement, dated April 17, 1998. (Incorporated by referenceto Exhibit 10.1 in the Registrant's Form 10-Q Report for the quarterly period ended September 30, 1998, and
filed with the Securities and Exchange Commission on November 13, 1998) (File No. 000-03880)                              
|10.8    |  |  |  | Second Amendment and Waiver, dated March 15, 1999, to the Credit Agreement, dated April 17, 1998. (Incorporated by reference to Exhibit 10.7 in the Registrant's Form 10-K Report for the fiscal year ended December 31, 1998 and
filed with the Securities and Exchange Commission on March 19, 1999) (File No. 000-03880)                             
|10.9    |  |  |  | Third Amendment, dated June 25, 1999, to the Credit Agreement, dated April 17, 1998. (Incorporated by reference to Exhibit 10.1 in the Registrant's Form 10-Q Report for the quarterly period ended June 30, 1999, and filed with
the Securities and Exchange Commission on August 13, 1999) (File No. 000-03880)                                       
|        |  |   |  | Executive Compensation Plans and Arrangements (Exhibits 10.10 through 10.24):                                                                                                                                                                                                                                                                           
|10.10   |  |  |  | Second Amendment and Restated Employment Agreement dated January 1, 1997, between the Registrant and Donald L. Evans. (Incorporated by reference to Exhibit 10.15 in the Registrant's Form 10-K Report for the fiscal year ended
December 31, 1996, and filed with the Securities and Exchange Commission on March 27, 1997) (File No. 000-03880)       
|10.11   |  |  |  | First Amendment to Employment Agreement dated as of July 1, 1998, between the Registrant and Donald L. Evans. (Incorporated by reference to Exhibit 10.3 in the Registrant's Form 10-Q Report for the quarterly period ended June 30, 1998,
and filed with the Securities and Exchange Commission on August 10, 1998) (File No. 000-03880)              
|10.12   |  |  |  | Employment Agreement dated May 3, 1999 between the Registrant and James D. Lightner. (Incorporated by reference to Exhibit 10.3 in the Registrant's Form 8-K Report dated July 19, 1999, and filed with the Securities and Exchange
Commission on July 19, 1999) (File No. 000-03880)                                                                   
|10.13** |  |  |  | Employment Agreement dated January 1, 2003 between the Registrant and James D. Lightner                                                                                                                                                                                                                                                                 
|10.14   |  |  |  | The Registrant's Severance Plan dated as of July 1, 1998. (Incorporated by reference to Exhibit 10.2 in the Registrant's Form 10-Q Report for the quarterly period ended June 30, 1998, and filed with the Securities and Exchange
Commission on August 12, 1998) (File No. 000-03880)                                                                  
|        |  |   |  |                                                                                                                                                                                                                                                                                                                                                         

|10.15  |  |  |  | First Amendment to Tom Brown, Inc. Severance Plan dated May 10, 2001. (Incorporated by reference to Exhibit 10.5 in the Registrant's Form 10-Q Report for the quarterly period ended March 31, 2001 and filed with the Securities and
Exchange Commission on May 14, 2001) (File No. 000-03880)                                                                                                                                                                                          
|------ |  | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.16  |  |  |  | Severance Agreement dated as of July 1, 1998, together with a schedule identifying officers of the Registrant who are parties thereto and the multiple of earnings payable to each officer upon termination resulting from certain change in control
events. (Incorporated by reference to Exhibit 10.1 in the Registrant's Form 10-Q Report for the quarterly period ended June 30, 1998, and filed with the Securities and Exchange Commission on August 12, 1998) (File No.
000-03880)
|10.17  |  |  |  | First Amendment to Severance Agreement dated May 10, 2001. (Incorporated by reference to Exhibit 10.8 in the Registrant's Form 10-Q Report for the quarterly period ended March 31, 2001 and filed with the Securities and Exchange
Commission on May 14, 2001) (File No. 000-03880)                                                                                                                                                                                                     
|10.18  |  |  |  | Amended Schedule to Severance Agreement identifying officers and executives of the Registrant who are parties thereto and the multiple of earnings payable to each officer or executive upon termination resulting from certain change in control events.
(Incorporated by reference to Exhibit 10.17 in the Registrant's Form 10-K Report for the fiscal year ended December 31, 2001, and Filed with the Securities and Exchange Commission on March 19, 2002) (File No. 000-03880)    
|10.19  |  |  |  | Deferred Compensation Plan dated March 1, 2001. (Incorporated by reference to Exhibit 10.22 in the Registrant's Form 10-K Report for the fiscal year ended December 31, 2000, and filed with the Securities and Exchange Commission on
March 13, 2001) (File No. 000-03880)                                                                                                                                                                                                              
|10.20  |  |  |  | 1999 Long-Term Incentive Plan effective as of February 17, 1999. (Incorporated by reference to Exhibit 10.11 in the Registrant's Form 10-K Report for the fiscal year ended December 31, 1999, and filed with the Securities and
Exchange Commission on March 22, 2000) (File No. 000-03880)                                                                                                                                                                                             
|10.21  |  |  |  | Amendment to Tom Brown, Inc. 1999 Long-Term Incentive Plan dated May 10, 2001. (Incorporated by reference to Exhibit 10.6 in the Registrant's Form 10-Q Report for the quarterly period ended March 31, 2001 and filed with the
Securities and Exchange Commission on May 14, 2001) (File No. 000-03880)                                                                                                                                                                                 
|10.22  |  |  |  | Amended and Restated 1993 Stock Option Plan. (Incorporated by reference to Exhibit 10.1 in the Registrant's Form 10-Q Report for the quarterly period ended March 31, 2001 and filed with the Securities and Exchange Commission on
May 14, 2001) (File No. 000-03880)                                                                                                                                                                                                                   
|10.23  |  |  |  | Amendment to Tom Brown, Inc. Amended and Restated 1993 Stock Option Plan dated May 10, 2001. (Incorporated by reference to Exhibit 10.7 in the Registrant's Form 10-Q Report for the quarterly period ended March 31, 2001 and
filed with the Securities and Exchange Commission on May 14, 2001) (File No. 000-03880)                                                                                                                                                                   
|10.24  |  |  |  | 1989 Stock Option Plan. (Incorporated by reference to Exhibit 10.17 in the Registrant's Form S-1 Registration Statement dated February 14, 1990, and filed with the Securities and Exchange Commission on February 13, 1990) (Registration
No. 33-32774)                                                                                                                                                                                                                                 
|21.1** |  |  |  | Subsidiaries of the Registrant                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|23.1*  |  |  |  | Consent of KPMG LLP                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|       |  |   |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          

|23.2** |  |  |  | Information Regarding Consent of Arthur Andersen LLP                                                                      
|------ |  | - |  | --------------------------------------------------------------------------------------------------------------------------
|23.3*  |  |  |  | Consent of Ryder Scott Company                                                                                            
|31.1*  |  |  |  | CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                               
|31.2*  |  |  |  | CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                               
|32.1*  |  |  |  | CEO Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|32.2*  |  |  |  | CFO Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

---

(4)Reports on Form 8-K:

| |  | Form 8-K Item 5. |  | Press release dated February 20, 2003, entitled "Tom Brown, Inc. Reports Fourth Quarter and Full Year 2002 Earnings and Operating Results; Provides 2003 Guidance" filed on February 25, 2003
| |  | ---------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | Form 8-K Item 5. |  | Press release dated February 20, 2003, entitled "Tom Brown, Inc. Announces Year-End Reserves" filed on February 25, 2003                                                                     





SIGNATURES

Pursuant
to the requirements of Section 13 or 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.

| |  | TOM BROWN, INC.
| |  | ---------------
| |  | By             

Date:
August 5, 2003

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/JAMES D. LIGHTNERJames D. Lightner           |  | Chairman, Chief Executive Officer
and President                 |  | August 5, 2003
|/s/DANIEL G. BLANCHARDDaniel G. Blanchard       |  | Executive Vice President, Chief
Financial Officer and Treasurer |  | August 5, 2003
|/s/RICHARD L. SATRERichard L. Satre             |  | Controller                                                      |  | August 5, 2003
|/s/DAVID M. CARMICHAELDavid M. Carmichael       |  | Director                                                        |  | August 5, 2003
|/s/HENRY GROPPEHenry Groppe                     |  | Director                                                        |  | August 5, 2003
|/s/EDWARD S. LEBARON, JR.Edward S. LeBaron, Jr. |  | Director                                                        |  | August 5, 2003
|/s/ROBERT H. WHILDEN, JR.Robert H. Whilden, Jr. |  | Director                                                        |  | August 5, 2003
|/s/WAYNE W. MURDYWayne W. Murdy                 |  | Director                                                        |  | August 5, 2003
|/s/JAMES B. WALLACEJames B. Wallace             |  | Director                                                        |  | August 5, 2003
|/s/JOHN C. LINEHANJohn C. Linehan               |  | Director                                                        |  | August 5, 2003