**UNITED STATES**

**SECURITIES AND EXCHANGECOMMISSION**

###### **Washington, D.C. 20549**

 

**FORM 10-K/A**

**(AmendmentNo. 1)**

 

**(Mark One)**

 
| **ý**                          | ** ** | **ANNUAL  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE  ACT 0F 1934**                                                                                                                                                                                                                                     |
|-------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **                          | ** ** | ** **                                                                                                                                                                                                                                                                                                                               |
| ** **                          | ** ** | **FOR THE FISCAL YEAR ENDED DECEMBER 31,  2004**                                                                                                                                                                                                                                                                                    |
| ** **                          | ** ** | ** **                                                                                                                                                                                                                                                                                                                               |
| ** **                          | ** ** | **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 1-10389** |

 

**WESTERN GAS RESOURCES,INC.**

(Exact name of registrant as specified in its charter)

 
| **Delaware**                                             | ** ** | **84-1127613**       |
|----------------------------------------------------------|------------|----------------------|
| (State or  other jurisdiction of                         |       | (I.R.S.  Employer    |
| incorporation  or organization)                          |       | Identification  No.) |
|                                                     |       |                 |
| **1099 18th  Street, Suite 1200, Denver, Colorado** | ** ** | **80202**            |
| (Address of  principal executive offices)                |       | (Zip Code)           |
|                                                     |       |                 |
| **(303)  452-5603**                                      |
| Registrant’s  telephone number, including area code |

 

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

 
| **Title of each class**       | ** ** | **Name of exchange on which registered** |
|-------------------------------|------------|------------------------------------------|
| Common Stock, $0.10 par value |       | New York Stock Exchange                  |

 

Securities registered pursuant to Section 12(g) of theAct:  **None**

 

Indicate by check mark whether the registrant (1) has filed allreports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter periodthat the registrant was required to file such reports), and (2) has beensubject to such filing requirements for the past 90 days. Yes ýNo o

 

Indicate by check mark if disclosure of delinquent filers pursuant toItem 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 informationstatements incorporated by reference in Part III of this Form 10-K orany 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 voting common stock held bynon-affiliates of the registrant on June 30, 2004 was $1,972,814,219.

 

The number of shares outstanding of the only class of the registrant’scommon stock, as of March 3, 2005, was 74,183,197.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Information required by Part III of this Report (Items 10, 11, 12and 13) is incorporated by reference from the registrant’s proxy statement tobe filed pursuant to Regulation 14A with respect to the annual meeting ofstockholders to be held on May 6, 2005.

 

 

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###### **Explanatory Note**

###### ** **

Our Annual Report on Form 10-K for the yearended December 31, 2004, initially filed with the Securities andExchange Commission, or the SEC, on March 14, 2005, or the OriginalFiling, is being amended by this Form 10-K/A to reflect restatements ofour Consolidated Financial Statements for each of the three years in the periodended December 31, 2004, and the notes thereto.  We are also restating our unaudited quarterlyinformation disclosed in Note 12 to the consolidated financial statements foreach of the quarters in the two year period ended December 31, 2004 andeach of the quarters ended March 31, 2005 and June 30, 2005.

 

Upon adoption of FASB Statement No. 133,“Accounting for Derivative Instruments and Hedging Activities” (“FAS 133”) in2001, we analyzed our gas storage and gas transportation contracts in detail,and determined that these contracts had the characteristics of a derivative asdescribed in FAS 133.  The treatment ofthese contracts as derivatives has been consistently applied since adoption ofFAS 133 as reflected in our consolidated financial statements.  Historically, we recorded these contracts atfair value with the changes in fair value reflected in earnings. On November 8,2005, after the release of our third quarter 2005 results and prior to thefiling of the Form 10-Q for the quarter ended September 30, 2005, it came toour attention that these contracts may not meet the definition of aderivative.  On November 21, 2005, weannounced that our management and our audit committee had completed a review ofthe accounting treatment of our gas storage and gas transportation contractsand determined that these contracts do not meet the definition of a derivativeunder generally accepted accounting principles. Specifically, after a detailedreview of the contracts and the market for those contracts, we determined thatthese contracts do not meet the definition of a derivative as: (i) the marketfor these types of contracts is not sufficiently liquid for us to receive fairvalue in a ready market and (ii) if any contract is assigned, there is noassurance that we will be relieved of our rights and obligations under thatcontract.

 

For a more detailed description of theserestatements, see Note 2, “Restatement of Consolidated FinancialStatements” to the accompanying Consolidated Financial Statements and the section entitled“Restatement” in Management’s Discussion and Analysis of Financial Conditionand Results of Operations contained in this Form 10-K/A.

 

The Company has also restated its previously filed Management’s Reporton Internal Control Over Financial Reporting as of December 31, 2004 includedin Item 8 of this Form 10-K/A.

 

Except for the foregoingamended information, this Form 10-K/A continues to describe conditions asof the date of the Original Filing, including our expectations with respect toour 2005 capital budget and other forward-looking information, and we have notupdated the disclosures contained herein to reflect events that occurred at alater date. Other events occurring after the filing of the Original Filing orother disclosures necessary to reflect subsequent events have been or will beaddressed in either our restated Quarterly Reports on Form 10-Q/A for thequarterly periods ended March 31, 2005 or June 30, 2005 or ourQuarterly Report on Form 10-Q for the quarterly period ended September 30,2005, all of which are being filed concurrently with the filing of this Form 10-K/A,or in other reports filed with the SEC subsequent to the date of this filing.

 

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Western Gas Resources, Inc.

Form 10-K/A

Table of Contents

 
| **Part** | ** ** | **Item(s)** | ** ** | ** **                                                                                                             | ** ** |
|----------|------------|-------------|------------|------------------------------------------------------------------------------------------------------------------------|------------|
|     |       |        |       | Explanatory  Note                                                                                                      |       |
| I.       |       | 1 and 2.    |       | Business and Properties                                                                                                |       |
|     |       |        |       | General                                                                                                                |       |
|     |       |        |       | Business  Strategy                                                                                                     |       |
|     |       |        |       | 2005 Capital  Budget                                                                                                   |       |
|     |       |        |       | Upstream  Operations                                                                                                   |       |
|     |       |        |       | Powder River  Basin Coal Bed Methane                                                                                   |       |
|     |       |        |       | Jonah/Pinedale  Fields                                                                                                 |       |
|     |       |        |       | San Juan Basin                                                                                                         |       |
|     |       |        |       | Sand Wash  Basin                                                                                                       |       |
|     |       |        |       | Exploration                                                                                                            |       |
|     |       |        |       | Drilling  Results                                                                                                      |       |
|     |       |        |       | Production  Information                                                                                                |       |
|     |       |        |       | Midstream  Operations                                                                                                  |       |
|     |       |        |       | Gas Gathering,  Processing and Treating                                                                                |       |
|     |       |        |       | Midstream  Operating Areas                                                                                             |       |
|     |       |        |       | Powder River Basin                                                                                                     |       |
|     |       |        |       | Greater Green River Basin                                                                                              |       |
|     |       |        |       | West Texas                                                                                                             |       |
|     |       |        |       | Oklahoma                                                                                                               |       |
|     |       |        |       | San Juan                                                                                                               |       |
|     |       |        |       | Principal Gathering and Processing  Facilities Table                                                                   |       |
|     |       |        |       | Transportation Operations                                                                                              |       |
|     |       |        |       | Marketing                                                                                                              |       |
|     |       |        |       | Environmental                                                                                                          |       |
|     |       |        |       | Competition                                                                                                            |       |
|     |       |        |       | Regulation                                                                                                             |       |
|     |       |        |       | Employees                                                                                                              |       |
|     |       | 3.          |       | Legal Proceedings                                                                                                      |       |
|     |       | 4.          |       | Submission of Matters to a Vote of Security  Holders                                                                   |       |
| II.      |       | 5.          |       | Market for the Registrant’s Common Equity,  Related Stockholder Matters and Issuer Purchases of Equity Securities |       |
|     |       | 6.          |       | Selected Financial Data                                                                                                |       |
|     |       | 7.          |       | Management’s Discussion and Analysis of  Financial Condition and Results of Operations                            |       |
|     |       | 7A.         |       | Quantitative and Qualitative Disclosures  About Market Risk                                                            |       |
|     |       | 8.          |       | Financial Statements and Supplementary Data                                                                            |       |
|     |       | 9.          |       | Changes in and Disagreements with  Accountants on Accounting and Financial Disclosure                                  |       |
|     |       | 9A.         |       | Controls and Procedures                                                                                                |       |
|     |       | 9B.         |       | Other Information                                                                                                      |       |
| III.     |       | 10.         |       | Directors and Executive Officers of the  Registrant                                                                    |       |
|     |       | 11.         |       | Executive Compensation                                                                                                 |       |
|     |       | 12.         |       | Security Ownership of Certain Beneficial  Owners and Management and Related Stockholder Matters                        |       |
|     |       | 13.         |       | Certain Relationships and Related  Transactions                                                                        |       |
|     |       | 14.         |       | Principal Accountant Fees and Services                                                                                 |       |
|     |       | 15.         |       | Exhibits, Financial Statement Schedules                                                                                |       |

 

2

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**PART I**

 

**ITEMS 1 AND 2.  BUSINESS AND PROPERTIES**

 

*The terms Western, we, us and our as used inthis Form 10-K/A refer to Western Gas Resources, Inc. and itssubsidiaries as a consolidated entity, except where it is clear that theseterms mean only Western Gas Resources, Inc.*

 

***General***

 

Western explores for, develops and produces, gathers,processes and treats, transports and markets natural gas and natural gasliquids, or NGLs.  In our upstreamoperations, we explore for, develop and produce natural gas reserves primarilyin the Rocky Mountain region.  In ourmidstream operations, which are comprised of three segments, we design,construct, own and operate natural gas gathering, processing and treatingfacilities; we own and operate regulated transportation facilities; and weoffer marketing services in order to provide our customers with a broad rangeof services from the wellhead to the sales delivery point.  Our midstream operations are conducted inmajor gas-producing basins in the Rocky Mountain, Mid-Continent and West Texasregions of the United States.

 

Our operationsare conducted through the following four business segments:

 

**•*****                     Upstream***—We explore for,develop and produce natural gas reserves independently and to enhance and supportour existing gathering and processing operations. We sell the natural gas thatwe produce to third parties. Our producing properties are primarily located inthe Powder River and Greater Green River Basins of Wyoming, and the Sand WashBasin in Colorado.  In addition, in October 2004,we acquired properties in the San Juan Basin of New Mexico.  Our strategy is to seek new gas prospects inthe Rocky Mountain region by utilizing our expertise in exploration andlow-risk development of unconventional gas reservoirs including tight-gassands, coal bed methane, biogenic, and shale gas plays to evaluate acquisitionsof either additional leaseholds, proven and undeveloped reserves or companieswith operations primarily focused in the Rockies.  The development or acquisition of new gasprospects may provide additional opportunities for our other businesssegments.  In January 2005, weopened an office in Calgary, Alberta to evaluate acquisitions of additionalleaseholds, proven and undeveloped reserves or companies with operations in theWestern Canadian Sedimentary Basin.

 

**•*****                     Gathering, Processing and Treating***—Ourcore operations are in well-established areas such as the Permian, Anadarko,Powder River, Greater Green River, and San Juan Basins.  We connect natural gas from gas and oil wellsto our gathering systems for delivery to our processing or treating plants. Atour plants we process natural gas to extract NGLs and we treat natural gas inorder to meet pipeline specifications. We provide these services to major oiland gas companies, to independent producers of various sizes and for our ownproduction.

 

**•*****                     Transportation***— In thePowder River Basin, we own one interstate pipeline and one intrastate pipelinethat transport natural gas for producers and energy marketers under feeschedules regulated by state or federal agencies.

 

**•*****                     Marketing***—Our gasmarketing segment is an outgrowth of our upstream and gathering, processing andtreating activities.  One of the primarygoals of our gas marketing operations is the preservation and enhancement ofthe value received for our equity volumes of natural gas.  This goal is achieved through the use ofhedges on the production of our equity natural gas and NGLs and through the useof firm transportation capacity.  We alsobuy and sell natural gas and NGLs in the wholesale market in the United Statesand in Canada.  These third-party sales,our firm transportation capacity on interstate pipelines and our gas storagecapacity, combined with the stable supply of gas from our facilities andproduction, enable us to respond quickly to changing market conditions and totake advantage of seasonal price variations and peak demand periods.

 

Historically, we have derived approximately97% of our revenues from the sale of gas and NGLs. Our revenues by type ofoperation are as follows (dollars in thousands):

 
| ** **                                        | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------|------------|----------------------------------|------------|
| ** **                                        | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                        | ** ** | **Restated**                     | ** ** | **%** | ** ** | **Restated** | ** ** | **%** | ** ** | **Restated** | ** ** | **%** | ** ** |
|                                              |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Sale of gas                                       |       | $                                | 2,518,281  |   | 81.7 |   | $ | 2,463,757 |   | 85.5 |   | $ | 2,119,196 |   | 86.0 |   |
| Sale of natural gas liquids                       |       | 450,761                          |       | 14.6 |   | 346,109 |   | 12.0 |   | 309,514 |   | 12.6 |   |
| Gathering, processing and transportation  revenue |       | 90,874                           |       | 2.9 |   | 83,672 |   | 2.9 |   | 65,601 |   | 2.7 |   |
| Price risk management activities (restated)       |       | 20,051                           |       | 0.7 |   | (16,386 | ) | (0.5 | ) | (35,285 | ) | (1.4 | ) |
| Other                                             |       | 3,201                            |       | 0.1 |   | 2,599 |   | 0.1 |   | 4,720 |   | 0.1 |   |
|                                              |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Total revenues (restated)                         |       | $                                | 3,083,168  |   | 100.0 |   | $ | 2,879,751 |   | 100.0 |   | $ | 2,463,746 |   | 100.0 |   |

 

3

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***Business Strategy***

 

Maximizing the value of our existing coreassets and locating new growth projects in the Rocky Mountain region are thefocal points of our business strategy.  Our core assets are our fully integrated upstream and midstreamproperties in the Powder River, Greater Green River and San Juan Basins and ourmidstream operations in west Texas and Oklahoma.  Since 2001, our long-term business plan hasbeen to increase stockholder value by:  (i) doublingproven reserves and equity production of natural gas from the level at December 31,2001 over a five-year period; (ii) meeting or exceeding throughputprojections in our midstream operations; and (iii) optimizing annualreturns.

 

***Double Proven Natural GasReserves and Equity Production of Natural Gas from the level at December 31,2001**over a five-yearperiod.  ***In order toachieve this goal, we will focus on continued development of ourleasehold positions in the Powder River Basin coal bed methane play, or CBM,and development in the Greater Green River and San Juan Basins, and activelyseek to add other core natural gas development projects.  Overall, at February 15, 2005, we holddrilling rights on approximately 1.6 million net acres in these and other RockyMountain basins.  At December 31,2004, we had proved developed and undeveloped reserves of approximately 812billion cubic feet equivalent, or Bcfe, of which 40% are proved developedproducing and proved developed non-producing reserves.  In total, we have increased our proveddeveloped and undeveloped reserves by approximately 71% from December 31,2001.  During 2004, our production ofnatural gas as compared to 2003 increased by 5% to 55.5 Bcfe.  In total, this represents an increase ofapproximately 55% in our average equity production of natural gas from 2001levels.  We currently anticipate a 10% to15% growth in our equity production of natural gas in 2005.  Inthe Powder River Basin, our future growth lies in over 10,000 potential welllocations in the Big George, Wyodak and related coals if the play is fullysuccessful.  In the Greater Green RiverBasin, our reserve potential is in the development of 40-acre and 20-acrelocations on our leasehold on the Pinedale Anticline, which target sandstonereservoirs in the Lance and Mesa Verde formations and on 20-acre and 10-acrelocations on our leasehold in the Jonah Field.

 

We continue to seek to add additionalupstream core projects that are focused on Rocky Mountain natural gas.  We will utilize our expertise in explorationand low-risk development of unconventional gas reservoirs including tight-gassands, coal bed methane, biogenic, and shale gas plays to evaluate acquisitionsof either additional leaseholds, proven and undeveloped reserves or companieswith operations primarily focused in the Rockies.  We may also evaluate unconventional gasreservoirs in areas outside the Rockies, including western Canada, where we canleverage our related exploration, production and gathering expertise.

 

***Meetor Exceed Throughput Projections in our Midstream Operations.***   To achieve this goal, we must continue ourefforts to add to natural gas throughput levels through new well connections,expansion or acquisition of gathering or processing systems and theconsolidation of existing facilities.  Wealso seek growth opportunities for gathering and processing through ourdevelopment of new gas reserves.  Ourmidstream operations provide us with steady throughput volumes and significantcash flow that we can in turn re-invest in new growth opportunities in this orother segments of our operations.  In2004, the throughput volume at our gathering and processing facilities averaged1.4 billion cubic feet, or Bcf, per day and operating profit contributed bythese facilities was $168.9 million.  Wecurrently anticipate an 8% to 10% growth in our throughput volumes at ourgathering and processing facilities in 2005.

 

Our gathering and processing operations arelocated in some of the most actively drilled oil and gas producing basins inthe United States.  We enter intoagreements under which we gather, process or treat natural gas produced onacreage dedicated by third parties to us or acreage which we aredeveloping.  We contract for productionfrom newly developed acreage in order to replace declines in existing reservesor increase reserves that are dedicated for gathering, processing or treatingat our facilities.  Although some of ourplants have experienced natural declines in dedicated reserves, overall we havebeen successful in connecting additional reserves to more than offset thesedeclines.  At December 31, 2004, theestimated future natural gas production connected to our gathering, processingand treating facilities totaled approximately 4.3 trillion cubic feet, orTcf.  This is based on an internal reviewof historical facility throughput gas volumes, our interpretation of expecteddeclines from existing connections, and assumes that there are no new wellconnections to our facilities. We will also evaluate investments in expansionsor acquisitions of assets that complement and extend our core natural gasgathering, processing, treating and marketing businesses and new growthprojects in the Rocky Mountain region. For example, in November 2004, we signed a purchase and saleagreement to acquire certain natural gas gathering and processing assetslocated in the Greater Green River Basin, for a total purchase price ofapproximately $28.0 million, before adjustments.  This acquisition closed in February 2005.  These systems are comprised of processingcapacity of 150 million cubic feet, or MMcf per day, and a total of 140 milesof gathering lines, which, during January 2005, were gathering a total of31 MMcf, per day.

 

4

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***OptimizeAnnual Returns.*** To optimize our annual returns, we will focus our efforts in our primaryoperating areas in the Powder River and Greater Green River Basins, theAnadarko Basin in Oklahoma, the Permian Basin in west Texas, and the San JuanBasin.  We review the economicperformance and growth opportunities of each of our assets to ensure that asatisfactory rate of return is achievable. If an asset is not generating targeted returns or is outside our coreoperating areas, we explore various options, such as integration with otherWestern-owned facilities or consolidation with third-party-owned facilities,dismantlement, asset trades or sale. Consolidations and joint ventures allow us to increase the throughput ofone facility while reducing the capital invested in, and the operating costsof, the consolidated assets.  Weroutinely evaluate our business for methods to reduce our operating andadministrative costs, including the implementation of automation and the use ofinformation technology.

 

Western Gas Resources, Inc. wasincorporated in Delaware in 1989.  Ourprincipal offices are located at 1099 18th Street, Suite 1200,Denver, Colorado 80202.  Our telephonenumber is (303) 452-5603.

 

 Ourwebsite address is http://www.westerngas.com. We make available free of chargethrough our website our annual report on Form 10-K, quarterly reports on Form 10-Q,current reports on Form 8-K, and all amendments to those reports as soonas reasonably practicable after such material is electronically filed with orfurnished to the SEC, at http://www.sec.gov.  Additionally, our Code of Business Conduct and Ethics, Code of Ethicsfor Senior Financial Management, Corporate Governance Guidelines and thecharters of our Audit Committee, Compensation Committee and Nominating andCorporate Governance Committee are posted on our website and are available inprint free of charge to any stockholder who requests them.

 

***2005 Capital Budget***

 

In order tomaintain a strong balance sheet, our general goal is to limit our capitalexpenditures, excluding acquisitions, in any single year to 110% of theprojected cash flow generated by our operations for that year.  In some years, however, we expect that wewill exceed this limitation based on the growth opportunities available to us.  In 2005, we anticipate capital expendituresof approximately $338.8 million.  Weexpect that the Rocky Mountain region will utilize approximately 87% or $295.6million of the 2005 capital budget.  The2005 capital budget is presented in the following table (dollars in thousands).

 

| **Type of Capital Expenditure**                                                             | ** ** | **2005 Capital  Budget** | ** ** |
|---------------------------------------------------------------------------------------------|------------|--------------------------|------------|
| Gathering,  processing, treating and pipeline assets                                        |       | $                        | 112.8      |   |
| February 2005  acquisition of gathering and processing assets in the Green River Basin |       | 28.0                     |       |
| Exploration  and production and lease acquisition activities                                |       | 186.7                    |       |
| Information  technology and other items                                                     |       | 3.0                      |       |
| Capitalized  interest and overhead                                                          |       | 8.3                      |       |
| Total                                                                                       |       | $                        | 338.8      |   |

 

The majority ofour capital expenditures are expected to be in the Powder River Basin CBMdevelopment and in the Greater Green River Basin.  In the Powder River Basin CBM development, weplan to invest $118.4 million, or 35% of our total capital program.  Of this amount, $81.2 million is planned tobe spent on our share of drilling 850 gross wells and for production equipmentand undeveloped acreage and $37.2 million is planned to be spent for gatheringlines and installation of additional compression units.

 

In the GreaterGreen River Basin we expect to invest $126.5 million, or 37% of the total 2005capital expenditure program.  We plan tospend $59.0 million to participate in 85 gross wells, 68 of which are in therapidly developing Pinedale Anticline area, and $67.5 million to expandgathering and compression services.

 

The remaining$93.9 million of our 2005 capital spending program is expected to be spent asfollows: $55.3 million for well connections, expansions, exploration,maintenance and upgrade projects in our other operating areas, $27.3 forexploration activities including lease acquisition and exploratory drilling,$8.3 million for capitalized interest and overhead and $3.0 million forinformation technology and other items. Overall, we expect to spend $13.7 million on maintenance and upgradeprojects for existing midstream facilities. Due to drilling, regulatory, commodity pricing and other uncertaintiesthat are beyond our control, we can make no assurance that our capital budgetfor 2005 will not change or that we will actually incur this level of capitalexpenditure.

 

5

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***Upstream Operations***

 

A vital aspect of our long-term business planis to double proven natural gas reserves and equity production of natural gasfrom the level at December 31, 2001 over a five-year period.  In order to achieve this goal, we will focuson continued development of our leasehold positions in the Powder River BasinCBM development, the Greater Green River Basin, and the San Juan Basin.  Each of our existing upstream projects isfully integrated with our midstream operations. In other words, in each of these areas, we provide the gathering,compression, processing, marketing or transportation services for both our ownproduction and for third-party operators. Additionally, we are actively pursuing new exploration, development andproducing property acquisition opportunities.

 

#### ***Our principal upstream operations are summarized in the followingtable:***

 
| **Production Area**     | ** ** | **Gross Acres  Under Lease  at  December 31,  2004** | ** ** | **Net Acres  Under Lease  at  December 31,  2004** | ** ** | **Proven Reserves  at  December 31,  2004 (Bcfe)** | ** ** | **Average Net  Production for  the Year Ended  December 31,  2004* (MMcfe/day)** | ** ** | **Gross  Productive  Gas Wells at  December 31,  2004** | ** ** | **Net Productive  Gas Wells at  December 31,  2004** | ** ** |
|-------------------------|------------|-----------------------------------------------------------|------------|---------------------------------------------------------|------------|---------------------------------------------------------|------------|---------------------------------------------------------------------------------------|------------|--------------------------------------------------------------|------------|-----------------------------------------------------------|------------|
| Powder River  Basin CBM |       | 1,045,000                                                 |       | 533,000                                                 |       | 310                                                     |       | 114                                                                                   |       | 4,219                                                        |       | 1,999                                                     |       |
| Jonah/Pinedale  Field   |       | 161,000                                                   |       | 28,000                                                  |       | 446                                                     |       | 29                                                                                    |       | 240                                                          |       | 26                                                        |       |
| San Juan  Basin         |       | 34,000                                                    |       | 26,000                                                  |       | 26                                                      |       | 3                                                                                     |       | 124                                                          |       | 117                                                       |       |
| Sand Wash  Basin        |       | 151,000                                                   |       | 137,000                                                 |       | 29                                                      |       | 6                                                                                     |       | 19                                                           |       | 19                                                        |       |
| Denver-Julesburg  Basin |       | 395,000                                                   |       | 340,000                                                 |       | —                                                  |       | —                                                                                |       | —                                                       |       | —                                                    |       |
| Other                   |       | 473,000                                                   |       | 385,000                                                 |       | 1                                                       |       | 1                                                                                     |       | 12                                                           |       | 3                                                         |       |
| Total                   |       | 2,259,000                                                 |       | 1,449,000                                               |       | 812                                                     |       | 153                                                                                   |       | 4,614                                                        |       | 2,164                                                     |       |

 

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* Represents netproduction sold.

 

***Powder River BasinCoal Bed Methane. ***Wecontinue to develop our Powder River Basin CBM reserves and expand theassociated gathering system in northeast Wyoming.  Our net production sold from the Powder RiverBasin CBM averaged 114 MMcf per day in 2004.

 

At December 31, 2004, we had establishedproven developed and undeveloped reserves totaling 310 Bcfe, net, on a portionof this acreage, 50% of which are proven and developed.  Overall, this represented a 5% decrease inproven reserves as compared to December 31, 2003.  Reserves in total increased by a net 34 Bcfebefore production of 42 Bcfe and sales of reserves in place of 9 Bcfe.  We experienced additions to reserves fromdrilling new wells and added new proved undeveloped locations as a result ofdrilling, which were partially offset by downward revisions in reserveestimates in certain areas in the basin. The downward revisions were mainly inthe Wyodak coal and were the result of further pressure draw down in the HoeCreek area and in the multiple coal area to the north where coals are generallythinner and split into several seams. Our model for reserves conservatively assumes that each well iscompleted in only one coal seam, and based on the cost to drill and complete awell, these locations were uneconomic and removed from the reserve base.  As we proceed with our development, some ofthe revisions to the thin coals may be recaptured in multiple coal seamcompletions, which are more economic than historic single zone completions inthe thinner coals.

 

Proved reserves at December 31, 2004included 179 Bcf from the Big George and related coals, a 25% increase fromyear-end 2003.  Our production from theBig George coal continues to increase and averaged 73 MMcf per day gross, or 30MMcf per day net, in December 2004 from the All Night Creek Unit,Pleasantville, SG Palo, Bullwhacker, Schoonover and Kingsbury Unit areas.  In these development areas and our areas ofexploration, as of January 31, 2005, we had 583 Big George wellsdewatering and producing gas, 248 Big George wells dewatering and 335 BigGeorge wells drilled and in various stages of completion and hook-up in preparation for dewateringand production.

 

In 2005, we plan to participate in thedrilling of 730 gross wells, or 365 net wells, in the Big George and relatedcoals and an additional 120 gross wells, or 60 net wells, in the Wyodak andrelated coals.  An estimated 640 wells ofthe 850-well program will be on federal leaseholds and require drilling permitsfrom the Bureau of Land Management, or BLM. The remaining 210 well locations are on fee or state leaseholds.  Together with our co-developer, we havedrilling permits approved for 120 of the federal wells planned for 2005.  Federal drilling permit applications foranother 812 locations were submitted to

 

6

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the BLM in 2004.  Timely receipt of these permits would allowus to complete our planned 2005-drilling program, and a portion of our 2006-drillingprogram, on federal leaseholds.

 

Drilling in the Powder River Basin isdependent on the receipt of various regulatory permits, including BLM drillingpermits, Wyoming Department of Environmental Quality, or DEQ, water dischargepermits, and the Wyoming State Engineer’s Office reservoir permits.  Most of our undeveloped prospects from theBig George formation are located in the Powder River drainage area.  Water management techniques utilized by us,and approved by the DEQ on a site specific basis, have included containment ortreating.  In order to facilitate theprocessing of our water discharge permit applications on the west side of thebasin, and in advance of the final requirements of the DEQ, we have installedand tested various types of water treatment facilities and are treating thewater produced in some areas of the basin and, with the approval of the DEQ,discharging into the Powder River.  Webelieve many of the future developments in the Big George coal will likelyrequire water treatment facilities. These treating operations have added and will add to the cost ofdevelopment and operations in these areas. We continue to evaluate several options for water treatment and areworking with the governmental agencies to identify the most effective and costefficient methods.

 

Approximately 300 gross wells in our 2005-drillingprogram will require permits to treat produced water.  The remainder of the wells to be drilled in2005 will require more conventional types of water discharge permits, such asreservoir containment or surface discharge. To date, we, together with our co-developer in this area, have receivedwater discharge permits from the DEQ for approximately 34% of the wells we planto drill in 2005.  We anticipate that allremaining permits necessary to complete our 2005-drilling program will besubmitted by the end of the first quarter of 2005.  Historically, the DEQ permit process hasrequired approximately 120 to 150 days from initial submittal to finalapproval.  There is, however, noassurance as to the future timing of the receipt of drilling and waterdischarge permits, the success of our drilling program, or the dewatering timeas our development progresses into the western and northern parts of the PowderRiver Basin.

 

On April 30, 2003, the BLM,issued the final Record of Decision, or ROD, for the Powder River Basin Oil &Gas Environmental Impact Statement, or EIS. The ROD requires additional surveys for plant and animal species,cultural surveys and noxious weed mitigation prior to the BLM granting adrilling permit.  A number of cases havebeen filed by environmental groups against the BLM in Wyoming disputing thevalidity of the environmental impact statement and ROD.  Due to our interests in developing federalleases in the Powder River Basin, we are an intervenor defendant in each of theforegoing cases.  In the event of anadverse ruling, the BLM may be required to perform further environmentalanalysis and, in addition, could be ordered to cease issuing drilling permitsuntil it has completed such further analysis.  Consequently, our ability to receive permits and develop our leases maybe delayed or restricted by the outcome of these cases.

 

On August 10, 2004, the Tenth CircuitCourt of Appeals issued its decision in Pennaco Energy, Inc. v. UnitedStates Department of the Interior. The court upheld a decision by the Interior Board of Land Appeals, orIBLA, that the BLM had not complied with the National Environmental Policy Actin issuing three federal leases to Pennaco Energy, Inc. in the PowderRiver Basin for coalbed methane development. We are not a party to the case, and the IBLA and Tenth Circuit decisionsdo not directly address any federal leases held by us.  However, we hold approximately 70,000 netacres of federal leasehold in the Powder River Basin, which may potentially beaffected by the response to the Pennaco case. In order to resolve the issues raised in the Pennaco decision andrelated issues, the BLM filed for and received public comment on two proposedenvironmental assessments.  Aftercompletion of the environmental assessments, the BLM believes the issues raisedin the Pennaco decision will be resolved. We cannot predict what other actions the Department of Interior or thirdparties might take in response to this matter, or how the decision and actionstaken by the BLM in response to the decision may affect the pace of federalleasing or permitting and development in the Powder River Basin.

 

During 2004, we expended approximately $75.5million in the Powder River Basin coal bed project for drilling costs,production equipment and lease acquisitions. Our 2005 capital budget for the Powder River Basin coal bed project isestimated at $81.2 million; however, due to regulatory uncertainties, which arebeyond our control, we can make no assurance that we will incur this level ofcapital expenditure during 2005.

 

***Jonah/PinedaleFields.***  Ourexploration and production assets in the Green River Basin of southwest Wyomingare located in the Pinedale Anticline and Jonah Field areas.  During 2004, we participated in the drillingof 80 gross wells, or approximately eight net wells, on the Pinedale Anticlineand experienced a success rate of 100%. During 2004, we expended a total of $33.7 million for drilling costs andproduction equipment.  During 2005, weexpect to participate in the drilling of 80 gross wells, or approximately ninenet wells, on the Pinedale Anticline. Our capital budget for 2005 in the Pinedale Anticline area provides forexpenditures of approximately $40.6 million for drilling costs and productionequipment.  Due to drilling and

 

7

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regulatory uncertainties, whichare beyond our control, there can be no assurance that we will incur this levelof capital expenditure during 2005.

 

At December 31, 2004, we had establishedproven developed and undeveloped reserves totaling 446 Bcfe, net, 43% of whichare proved developed producing and proved developed non-producing reserves.This represented an overall 35% increase in proven reserves as compared to December 31,2003.  In total, as a result of ourdrilling, proved undeveloped locations resulting from drilling, and theincreased drilling density discussed below, our proven reserves increased by anet 127 Bcfe in this play in 2004. Partially offsetting this increase was production of 11Bcfe during theyear.  There can be no assurance,however, as to the ultimate recovery of these reserves.

 

Historically, drillingon the Pinedale Anticline has been allowed on one well per 40-acre tract.  In the third quarter of 2004, the State ofWyoming approved the drilling of two wells per 40-acre tract on approximatelyhalf of the Pinedale Anticline.  If thisspacing were approved along the expanse of the Pinedale Anticline and provessuccessful, we would significantly increase our number of drillinglocations.  The timing of the drilling ofthese additional locations would be subject to the completion of any requiredregulatory and environmental reviews.  In2004, the state of Wyoming approved 10-acre spacing that significantlyincreases our number of drilling locations in the Jonah Field.

 

***San Juan Basin.***  * *In October 2004, we acquiredoil and gas assets in the San Juan Basin of New Mexico for approximately $82.2million, plus assumed liabilities. The purchase included 32,000 gross acres, or24,000 net acres, with production of approximately 15 MMcf per day gross, or 11MMcf per day, net, of coal bed methane.  Proved developed and undeveloped reserves as of December 31, 2004totaled approximately 26 Bcfe.  Thepurchase also included approximately 130 miles of related gathering systems,which are currently connected to our existing San Juan River plant.  Our 2005 capital budget in this area providesfor expenditures of approximately $21.0 million for our participation in thedrilling of 64 gross and net development wells and workovers of the previouslydrilled wells.

 

***Sand Wash Basin.***   We continue to explore and develop ouracreage position in the Sand Wash Basin in northwest Colorado, located in theGreater Green River Basin.  During 2004,we produced and sold 6 MMcfe per day from this acreage.  At December 31, 2004, we had establishedproven developed and undeveloped reserves totaling 29 Bcfe on a portion of thisacreage.

 

At December 31, 2004, we ownedapproximately 137,000 net oil and gas leasehold acres****in this basin.  Themajority of this acreage is in the exploration phase and will be evaluated infuture years.  In 2004, approximately$8.2 million was spent in this area.  Our2005 capital budget in this area provides for expenditures of approximately$9.2 million for our participation in the drilling of seven gross and netdevelopment wells and one exploratory well.

 

***Exploration. *** Wecontinue to seek to add additional upstream core projects that are focused onRocky Mountain natural gas.  We willutilize our expertise in exploration and low-risk development of unconventionalgas reservoirs including tight-gas sands and coal bed methane to evaluateacquisitions of additional leaseholds, proven and undeveloped reserves, orcompanies with operations primarily focused in the Rockies.  We may also evaluate unconventional gasreservoirs in areas outside the Rockies, including Canada, where we canleverage our related exploration, production and gathering expertise.  Through February 15, 2005, we haveacquired the drilling rights on approximately 874,000 net acres in other RockyMountain basins and continue to expand our leasehold positions.

 

*Denver-JulesburgBasin.*  ThisNiobrara gas play is located in the northeastern area of the Denver-JulesburgBasin in northeast Colorado and southwest Nebraska.  In this play, as of January 31, 2005, wehave acquired the drilling rights on approximately 395,000 gross acres, orapproximately 340,000 net acres.  We arecurrently constructing a 12-mile gathering line and expect production from ourinitial six wells to commence in the second quarter of 2005.  We have identified 50 to 65 additionalprospective drilling locations on our existing 59 square miles of 3-D seismicdata, which will be contingent on the extended production results of theinitial wells.

 

*Washakie and RedDesert Basins.*  The Washakie and Red Desert Basins are located in the eastern portion ofthe Greater Green River Basin.   In theseareas, as of February 15, 2005, we have acquired the drilling rights onapproximately 41,000 gross acres, or approximately 28,000 net acres.  We have drilled two wells through December 31,2004 in these areas and plan to drill nine exploration wells in these areas in2005.

 

8

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During 2004, our capital expenditures in theexploration areas totaled $11.3 million. Our capital expenditure budget for 2005 in the exploration areas totals$32.3 million, primarily for our participation in drilling activities, seismicsurveys and leasehold acquisition.

 

***Drilling Results.***** **The following table sets forth the number of wells we drilled duringeach of the last three years in each of our major producing areas.  This information should not be consideredindicative of future performance, nor should it be assumed that there isnecessarily any correlation between the number of productive wells drilled,quantities of reserves found or economic value. Productive wells are defined as those that produce commercial quantitiesof hydrocarbons whether or not they produce a reasonable rate of return.

 

| ** **                             | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------|------------|----------------------------------|------------|
| ** **                             | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| **Productive Area**                    | ** ** | **Gross**                        | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Powder  River Basin CBM**            |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Productive  wells drilled:             |       | 745                              |       | 377 |   | 536 |   | 257 |   | 909 |   | 436 |   |
| Dry  development wells drilled:        |       | 3                                |       | 1 |   | 0 |   | 0 |   | 0 |   | 0 |   |
| Dry  exploratory wells drilled:        |       | 4                                |       | 2 |   | 0 |   | 0 |   | 0 |   | 0 |   |
|                                   |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| **Jonah/Pinedale  Field**              |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Productive  wells drilled:             |       | 79                               |       | 8 |   | 53 |   | 5 |   | 26 |   | 4 |   |
| Dry  exploratory wells drilled:        |       | 1                                |       | 0 |   | 0 |   | 0 |   | 0 |   | 0 |   |
|                                   |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| **San Juan  Basin**                    |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Productive  wells drilled:             |       | 4                                |       | 4 |   | 0 |   | 0 |   | 0 |   | 0 |   |
| Dry  development wells drilled:        |       | 1                                |       | 1 |   | 0 |   | 0 |   | 0 |   | 0 |   |
|                                   |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| **Sand  Wash Basin**                   |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Productive  wells drilled:             |       | 1                                |       | 1 |   | 7 |   | 7 |   | 2 |   | 2 |   |
| Exploratory  productive wells drilled: |       | 1                                |       | 1 |   | 0 |   | 0 |   | 0 |   | 0 |   |
| Dry exploratory  wells drilled:        |       | 1                                |       | 0 |   | 1 |   | 1 |   | 0 |   | 0 |   |
|                                   |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| **Other**                              |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Exploratory  productive wells drilled: |       | 7                                |       | 6 |   | 4 |   | 3 |   | 0 |   | 0 |   |

 

***ProductionInformation.*** Revenues derived from our producing properties comprised approximately9%, 7% and 6% of consolidated revenues for the years ended December 31,2004, 2003 and 2002, respectively.  Thesegment operating profit (revenues and equity earnings from equity investmentsless product purchases and operating expenses) derived from our producingproperties comprised approximately 43%, 40% and 33% of consolidated operatingprofit for the years ended December 31, 2004, 2003 and 2002,respectively.  We expect both therevenues and segment operating profit derived from our producing properties tocontinue to increase commensurately with our production growth.

 

The followingtable provides a summary of our net annual production volumes:

 
| ** **                       | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------|------------|----------------------------------|------------|
| ** **                       | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                       | ** ** | **Gas**                          | ** ** | **Oil** | ** ** | **Gas** | ** ** | **Oil** | ** ** | **Gas** | ** ** | **Oil** | ** ** |
| **State/Basin**                  | ** ** | **(MMcf)**                       | ** ** | **(MBbl)** | ** ** | **(MMcf)** | ** ** | **(MBbl)** | ** ** | **(MMcf)** | ** ** | **(MBbl)** | ** ** |
|                             |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Colorado –  Sand Wash Basin |       | 2,153                            |       | 9 |   | 1,340 |   | 6 |   | 900 |   | 6 |   |
| Texas (1)                        |       | 22                               |       | 3 |   | 16 |   | 1 |   | 20 |   | 2 |   |
| Wyoming:                         |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Powder River Basin               |       | 41,715                           |       | — |   | 43,748 |   | — |   | 42,314 |   | — |   |
| Greater Green River Basin        |       | 10,075                           |       | 85 |   | 7,118 |   | 68 |   | 4,167 |   | 45 |   |
| New Mexico                       |       | 927                              |       | — |   | — |   | — |   | — |   | — |   |
| Total                            |       | 54,892                           |       | 97 |   | 52,222 |   | 75 |   | 47,401 |   | 53 |   |

 

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(1)     Representsa small non-operating working interest in several wells in the Austin Chalkarea.

 

The following tableprovides a summary of our proved developed and proved undeveloped net reservesas of the end of the

 

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lastthree years:

 
| ** **                 | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------|------------|----------------------------------|------------|
| ** **                 | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                 | ** ** | **Gas**                          | ** ** | **Oil** | ** ** | **Gas** | ** ** | **Oil** | ** ** | **Gas** | ** ** | **Oil** | ** ** |
| **State/Basin**            | ** ** | **(MMcf)**                       | ** ** | **(MBbl)** | ** ** | **(MMcf)** | ** ** | **(MBbl)** | ** ** | **(MMcf)** | ** ** | **(MBbl)** | ** ** |
| Colorado-Sand  Wash Basin  |       | 28,293                           |       | 111 |   | 28,011 |   | 114 |   | 12,624 |   | 53 |   |
| New  Mexico-San Juan Basin |       | 25,750                           |       | 112 |   | — |   | — |   | — |   | — |   |
| Wyoming:                   |       |                             |       |   |   |   |   |   |   |   |   |   |   |
| Powder River Basin         |       | 309,597                          |       | — |   | 325,966 |   | — |   | 414,143 |   | — |   |
| Greater Green River Basin  |       | 426,796                          |       | 3,418 |   | 314,747 |   | 2,539 |   | 153,897 |   | 1,160 |   |
| Total                      |       | 790,436                          |       | 3,641 |   | 668,724 |   | 2,653 |   | 580,664 |   | 1,213 |   |

 

Netherland, Sewell & Associates,Inc, or NSAI, prepared the reports for proved reserves for 2004 and 2003.  The report for proved reserves in the PowderRiver Basin and other Wyoming assets for 2002 was prepared by us and audited byNSAI.

 

Reserve estimates are subject to numerousuncertainties inherent in the estimation of quantities of proved reserves, theprojection of future rates of production and the timing of developmentexpenditures.  The accuracy of theseestimates is a function of the quality of available data and of engineering andgeological interpretation and judgment. Reserve estimates are imprecise andshould be expected to change as additional information becomes available.  Estimates of economically recoverablereserves and of future discounted net cash flows prepared by differentengineers or by the same engineers at different times may varysubstantially.  Results of subsequentdrilling, testing and production may cause either upward or downward revisionsof previous estimates.  In addition, theestimates of future net revenues from our proved reserves and the present valueof those reserves are based upon assumptions about production levels, pricesand costs, which may not be correct. Further, the volumes considered to be commercially recoverable fluctuatewith changes in prices and operating costs. The meaningfulness of suchestimates is highly dependent upon the accuracy of the assumptions upon whichthey were based. Actual results may differ materially from the resultsestimated.

 

#### ***Midstream Operations***

#### *** ***

Our midstream operations consist of ourgathering, processing, treating, marketing and transportation operations.  An important element of our long-termbusiness plan is to meet or exceed throughput projections in these areas and tooptimize their profitability.  To achievethis goal, we must continue our efforts to add to natural gas throughput levelsthrough new well connections and through the expansion or acquisition ofgathering or processing systems.  We alsoseek to increase the efficiency of our operations by modernization of equipmentand the consolidation of existing facilities.

 

***Gas Gathering, Processing andTreating. ***At December 31,2004, we operated a variety of gathering, processing and treating facilities,or plant operations, with approximately 10,800 miles of gathering lines, aspresented on the Principal Gathering and Processing Facilities Table set forthbelow.  These facilities are primarilylocated in five states and at December 31, 2004, had a combined throughputcapacity of approximately 3.1 Bcf per day of natural gas.  Our operations are located in some of the mostactively drilled oil and gas producing basins in the United States.  Five of our processing plants canfurther separate, or fractionate, the mixed NGL stream into ethane, propane,normal butane and natural gasoline to obtain a higher value for the NGLs, andthree of our plants are capable of processing and treating natural gascontaining hydrogen sulfide or other impurities that require removal prior todelivery to market pipelines.   In addition to our integrated upstreamand midstream operations in the Powder River, Greater Green River, and San JuanBasins, ourcore assets include our plant operations located in west Texas andOklahoma.  We believe that our coreassets have stable production rates, provide a significant operating cash flowand continue to provide us with strategic growth opportunities.

 

We contract with producers to gather rawnatural gas from individual wells located near our plants or gathering systems.Once we have executed a contract, we connect wells to gathering lines throughwhich the natural gas is delivered to a processing plant or treating facility.At a processing plant, we compress the natural gas, extract raw NGLs and treatthe remaining dry gas to meet pipeline quality specifications.

 

We acquire dedicated acreage and natural gassupplies in an effort to maintain or increase throughput levels to offsetnatural production declines of connected wells. We obtain these natural gas supplies by connecting additional wells,purchasing existing systems from third parties and through internally developedprojects or joint ventures. Historically, while individual plants have experienced declines indedicated reserves, overall we have been successful in connecting additionalreserves to more than offset the natural declines.  However, the level of future drilling willdepend upon, among other factors, the prices for

 

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gas and oil, the drillingbudgets of third-party producers, energy and environmental policy andregulation of governmental agencies and the availability of foreign oil andgas, none of which is within our control. At December 31, 2004, the estimated future natural gas productionconnected to our gathering, processing and treating facilities totaledapproximately 4.3 Tcf.  This is based onan internal review of historical facility throughput gas volume, ourinterpretation of expected declines from existing connections, and assumes thatthere are no new well connections to our facilities.

 

Substantially all gas flowing through ourgathering, processing and treating facilities is supplied under three types ofcontracts providing for the purchase, treating or processing of natural gas forperiods ranging from one month to twenty years or in some cases for the life ofthe oil and gas lease.  Approximately 70%of our plant facilities’ gross margin, or revenues at the plant less productpurchases, for the month of December 2004 was under percentage-of-proceedsagreements where we are typically responsible for the marketing of the gas andNGLs.  Under these agreements, we payproducers a specified percentage of the net proceeds received from the sale ofthe gas and the NGLs.

 

Approximately 20% of our plant facilities’gross margin for the month of December 2004 was under contracts that areprimarily fee-based from which we receive a set fee for each Mcf of gasgathered and/or processed. This type of contract provides us with a steadyrevenue stream that is not dependent on commodity prices, except to the extentthat low prices may cause a producer to delay drilling or shut in production.

 

Approximately 10% of our plant facilities’gross margin for the month of December 2004 was under contracts with ‘‘keepwhole’’arrangements or wellhead purchase contracts. We retain the NGLs recovered by the processing facility and keep theproducers whole by returning to the producers at the tailgate of the plant anamount of residue gas equal on a Btu basis to the natural gas received at theplant inlet.  The ‘‘keepwhole’’ componentof the contracts permits us to benefit when the value of the NGLs is greater asa liquid than as a portion of the residue gas stream.  However, we are adversely affected when thevalue of the NGLs is lower as a liquid than as a portion of the residue gasstream.

 

***Midstream OperatingAreas***

 

#### ***Powder RiverBasin.***  Our midstream operations in the Powder RiverBasin are fully integrated with our upstream operations as we provide thegathering, compression and processing services for our own production.  Additionally we provide the same types ofservices for third-parties.  As of December 31,2004, our assets in the Powder River Basin were primarily comprised of our coalbed methane gathering system with a capacity of 548 Mcf per day, several gasprocessing facilities with a combined capacity of 146 MMcf per day, and our 13%equity interest in Fort Union Gas Gathering, L.L.C., or Fort Union.   We averaged 396 MMcf per day of CBMgathering volumes, including third-party gas, during the fourth quarter of2004. Of that volume, approximately 96 MMcf per day was transported through ourMIGC pipeline.

 

We are theconstruction manager and field operator of the Fort Union gathering system andheader.  The Fort Union system deliverscoal bed methane gas to its treating facility near Glenrock, Wyoming andaccesses interstate pipelines serving gas markets in the Rocky Mountain andMidwest regions of the United States. The gathering pipeline has a capacity of 635 MMcf per day.  We have a long-term gathering agreement withFort Union for 83 MMcf per day of this capacity at $0.14 per Mcf.

 

We spent approximately $32.2 million in the Powder River Basin for midstreamactivities during 2004.  Our capital budget in thePowder River Basin for midstream activities provides for expenditures of $37.2million during 2005.  Depending upon our future drilling success,we may need to make additional capital expenditures or leasing commitments tocontinue expansion in this basin.  Due todrilling, regulatory, commodity pricing and other uncertainties, which arebeyond our control, there can be no assurance that we will incur this level ofcapital expenditure during 2005.

 

***Greater Green RiverBasin*.**  Our midstream operations in theGreater Green River Basin of southwest Wyoming are also fully integrated withour upstream operations in this area. Our midstream assets in this basin are comprised of the Granger andLincoln Road facilities, or collectively the Granger complex, our 50% equityinterest in Rendezvous Gas Services, L.L.C., or Rendezvous, our Red Desertfacility and our Table Rock, Wamsutter and Desert Springs gatheringsystems.  These facilities have acombined gathering capacity of 664 MMcf per day, and in the year ended December 31,2004, these facilities averaged throughput of 547 MMcf per day.   Additionally, these systems have a combinedprocessing capacity of 370 MMcf per day and in the year ended December 31,2004, processed an average of 278 MMcf per day.   These capacity and processing volumes do notinclude volumes committed to our straddle facility described below.

 

In December 2004, a new 200 MMcf per dayprocessing facility adjacent to the Granger Complex was placed intoservice.  This facility straddles athird-party regulated pipeline and processes its gas to meet pipelinespecifications.  The facility’s

 

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capacity is contractuallycommitted to this service, and the contract for processing this gas requires amonthly demand charge to be paid by the pipeline regardless of the amount ofgas processed.  These demand fees totalapproximately $2.2 million per year and the contract has a term of ten years.

 

In November 2004, we signed a purchaseand sale agreement to purchase certain natural gas gathering and processingassets in the eastern Greater Green River Basin for approximately $28.0million, before adjustments.  Thisacquisition closed in February 2005. The acquisition included the Patrick Draw processing plant with 150 MMcfper day of capacity and approximately 140 miles of related gatheringsystems.  At December 31, 2004,Patrick Draw was processing approximately 35 MMcf per day of gas.  Patrick Draw will be integrated into ourexisting Red Desert facility and our Table Rock, Wamsutter and Desert Springsgathering systems.

 

During 2004, we spent approximately $22.7 million in capitalexpenditures for midstream activities in this basin.  Our 2005 capital budget formidstream activities in this basin provides for expenditures of $67.5million.  This capital budget includes$37.3 million for gathering lines and installation of compression to expand thecapacity of our Granger Complex, our Wamsutter gathering system and our RedDesert facility, $28.0 million for the acquisition of several gathering andprocessing assets and $2.2 million for additional contributions to Rendezvousfor the expansion of its systems.   Dueto drilling, commodity pricing and regulatory uncertainties, which are beyondour control, there can be no assurance that we will incur this level of capitalexpenditure during 2005.

 

In 2001, we, together with an unrelatedthird-party, formed Rendezvous. Rendezvous gathers gas along the Pinedale Anticline for blending orprocessing at either our Granger Complex or at the third-party owned and operatedBlacks Fork processing facility.   We owna 50% interest in Rendezvous, and we serve as field operator of itssystems.   At December 31, 2004, thecapacity of Rendezvous was 275 MMcf per day and the facility gathered anaverage of 253 MMcf per day in 2004. During 2004, we implemented an upgrade of our 100 MMcf per dayrefrigeration unit at our Granger plant at a cost of approximately $3.0million, in part to process gas delivered off the Rendezvous system.

 

***West Texas******.*****  **Our primary assets in west Texas are the Midkiff/Benedum complex and theGomez and Mitchell Puckett treating facilities. These facilities process gas produced by third-parties in the PermianBasin, have a combined operational capacity of 565 MMcf per day and processedan average of 280 MMcf per day in the year ended December 31, 2004.  Also for this period, these facilitiesproduced an average of 206 MMcf per day of natural gas for delivery to salesmarkets and produced an average of 831 MGal per day of NGLs.  In 2004, our capital expenditures in thisarea totaled approximately $9.6 million.  Our capital budget in this area provides for expenditures ofapproximately $11.1 million during 2005. This budget includes approximately $7.7 million for additions to thegathering systems and plant facilities and approximately $3.4 million forreplacing and upgrading field and plant equipment.

 

***Oklahoma******.* **Our primary assets in Oklahoma are theChaney Dell and Westana systems.  Thesefacilities gather and process gas produced by third-parties in the Anadarko Basinand have a combined operational capacity of 175 MMcf per day.  During the year ended December 31, 2004,these facilities gathered an average of 182 MMcf per day, produced an averageof 159 MMcf per day of natural gas for delivery to sales markets and producedan average of 308 MGal per day of NGLs. During 2004, our capital expenditures in this area totaled $14.9million.  Our capital budget in this areaprovides for expenditures of approximately $20.8 million during 2005.  This budget includes approximately $17.5million for additions to the gathering systems and plant facilities andapproximately $3.3 million for replacing and upgrading field and plantequipment.

 

***San Juan. ***Our assets inthe San Juan Basin of New Mexico are the San Juan River processing facility andthe Four Corners Gathering system.  Thesefacilities gather and process gas produced by us and third parties in the SanJuan and Paradox Basins and have a combined operational capacity of 75 MMcf perday.  In 2004, these facilities gatheredand processed an average of 29 MMcf per day, produced an average of 23 MMcf perday of natural gas for delivery to sales markets and produced 51 MGal per dayof NGLs.  During 2004, our capitalexpenditures in this area totaled $13.6 million, including $11.8 million forthe acquisition of approximately 130 miles of related gathering systems in October 2004.  Our capital budget in this area provides forexpenditures of $2.4 million during 2005. This budget includes $2.0 million for additions to the gathering systemsand plant facilities and $400,000 for replacing and upgrading field and plantequipment.

 

12

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***Principal Gatheringand Processing Facilities Table.***  The following table provides informationconcerning our principal gathering, processing and treating facilities at December 31,2004.

 
| ** **                    | ** ** | **Year**                | ** ** | **Gas**                      | ** ** | **Gas**                               | ** ** | **Average for the Year Ended  December 31, 2004** | ** ** |
|-------------------------------|------------|-------------------------|------------|------------------------------|------------|---------------------------------------|------------|--------------------------------------------------------|------------|
| **Facilities (1)**            | ** ** | **Placed  in  Service** | ** ** | **Gathering  System  Miles** | ** ** | **Throughput  Capacity  (MMcf/D)(2)** | ** ** | **Gas  Throughput  (MMcf/D) (3)**                      | ** ** | **Gas  Production  (MMcf/D)(4)** | ** ** | **NGL  Production  (MGal/D) (4)** | ** ** |
| Texas                         |       |                    |       |                         |       |                                  |       |                                                   |       |   |   |   |   |
| Gomez Treating (5)            |       | 1971                    |       | 389                          |       | 280                                   |       | 95                                                     |       | 86 |   | — |   |
| Midkiff/Benedum               |       | 1949                    |       | 2,332                        |       | 165                                   |       | 139                                                    |       | 91 |   | 830 |   |
| Mitchell Puckett Treating (5) |       | 1972                    |       | 126                          |       | 120                                   |       | 46                                                     |       | 29 |   | 1 |   |
| Wyoming                       |       |                    |       |                         |       |                                  |       |                                                   |       |   |   |   |   |
| Coal Bed Methane Gathering    |       | 1990                    |       | 1,369                        |       | 548                                   |       | 396                                                    |       | 367 |   | — |   |
| Desert Springs Gathering      |       | 1979                    |       | 65                           |       | 10                                    |       | 6                                                      |       | 6 |   | 23 |   |
| Fort Union Gas Gathering(12)  |       | 1999                    |       | 167                          |       | 635                                   |       | 449                                                    |       | 449 |   | — |   |
| Granger Complex (6)(7)(8)     |       | 1987                    |       | 714                          |       | 325                                   |       | 265                                                    |       | 215 |   | 340 |   |
| Hilight Complex (6)           |       | 1969                    |       | 657                          |       | 124                                   |       | 19                                                     |       | 14 |   | 63 |   |
| Kitty/Amos Draw (6)           |       | 1969                    |       | 321                          |       | 17                                    |       | 6                                                      |       | 4 |   | 26 |   |
| Newcastle (6)                 |       | 1981                    |       | 146                          |       | 5                                     |       | 3                                                      |       | 2 |   | 22 |   |
| Red Desert (6)                |       | 1979                    |       | 125                          |       | 42                                    |       | 41                                                     |       | 29 |   | 53 |   |
| Rendezvous (10)               |       | 2001                    |       | 238                          |       | 275                                   |       | 253                                                    |       | 253 |   | — |   |
| Reno Junction (7)             |       | 1991                    |       | —                       |       | —                                |       | —                                                 |       | — |   | 125 |   |
| Table Rock Gathering          |       | 1979                    |       | 100                          |       | 20                                    |       | 13                                                     |       | 13 |   | — |   |
| Wamsutter Gathering (11)      |       | 1979                    |       | 242                          |       | 50                                    |       | 43                                                     |       | 39 |   | 21 |   |
| Wind River Gathering          |       | 1979                    |       | 137                          |       | 80                                    |       | 52                                                     |       | 51 |   | — |   |
| Granger Straddle Plant(13)    |       | 2004                    |       | —                       |       | 200                                   |       | 5                                                      |       | — |   | — |   |
| Oklahoma                      |       |                    |       |                         |       |                                  |       |                                                   |       |   |   |   |   |
| Chaney Dell/Westana           |       | 1966                    |       | 3,307                        |       | 175                                   |       | 182                                                    |       | 159 |   | 308 |   |
| New Mexico                    |       |                    |       |                         |       |                                  |       |                                                   |       |   |   |   |   |
| San Juan River (5)(9)         |       | 1955                    |       | 277                          |       | 60                                    |       | 27                                                     |       | 21 |   | 40 |   |
| Utah                          |       |                    |       |                         |       |                                  |       |                                                   |       |   |   |   |   |
| Four Corners Gathering        |       | 1988                    |       | 104                          |       | 15                                    |       | 2                                                      |       | 2 |   | 11 |   |
| Total                         |       |                    |       | 10,816                       |       | 3,146                                 |       | 2,042                                                  |       | 1,830 |   | 1,863 |   |

 

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| (1)  | Our interest  in all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%);  Fort Union (13%) and Rendezvous (50%). We operate all facilities, and all  data include our interests and the interests of other joint interest owners  and producers of gas volumes dedicated to the facility. Unless otherwise  indicated, all facilities shown in the table are gathering, processing or  treating facilities. |
|------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (2)  | Gas throughput capacity is as of  December 31, 2004 and represents capacity in accordance with design  specifications unless other constraints exist, including permitting or field  compression limits.                                                                                                                                                                                                                 |
| (3)  | Aggregate natural gas volumes delivered  into our gathering systems.                                                                                                                                                                                                                                                                                                                                                          |
| (4)  | Volumes of gas and NGLs are allocated to a  facility when a well is connected to that facility; volumes exclude NGLs  fractionated for third-parties.                                                                                                                                                                                                                                                                         |
| (5)  | Sour gas facility (capable of processing or  treating gas containing hydrogen sulfide and/or carbon dioxide).                                                                                                                                                                                                                                                                                                                 |
| (6)  | Processing facility that includes  fractionation (capable of fractionating raw NGLs into end-use products).                                                                                                                                                                                                                                                                                                                   |
| (7)  | NGL production includes conversion of  third-party feedstock to iso-butane.                                                                                                                                                                                                                                                                                                                                                   |
| (8)  | The Granger Complex includes the Lincoln  Road facility. As of January 1, 2004, the volume information for this  facility is reported with the volume information for Granger.                                                                                                                                                                                                                                           |
| (9)  | Includes the acquisition of gathering  assets, which closed on October 1, 2004.                                                                                                                                                                                                                                                                                                                                          |
| (10) | The majority of the gas gathered by the  Rendezvous gas gathering system is delivered to our Granger facility and is  included with the volume information reported for Granger.                                                                                                                                                                                                                                              |
| (11) | A portion of the gas gathered by the  Wamsutter gas gathering system is delivered to our Red Desert facility and is  included with the volume information reported for Red Desert.                                                                                                                                                                                                                                            |
| (12) | A portion of the gas gathered by Fort Union  is also reported under Coal Bed Methane Gathering.                                                                                                                                                                                                                                                                                                                               |
| (13) | This facility was placed in service in December 2004.                                                                                                                                                                                                                                                                                                                                                                    |

 

13

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We routinely review the economic performanceof each of our operating facilities to ensure that a satisfactory rate ofreturn is achieved. If an operating facility is not generating targeted returnswe will explore various options, such as consolidation with other Western-ownedor third-party-owned facilities, dismantlement, asset trades or sale.  A description of the significant midstreamacquisitions and dispositions since January 1, 2000, involving assetsother than those that were previously discussed are:

 

***Acquisitionand Disposition of Various Wyoming Gathering Systems.***  Effective February 1, 2003, we acquiredseveral gathering systems in Wyoming, primarily located in the Greater Green RiverBasin with smaller operations in the Powder River and Wind River Basins, for atotal of $37.1 million.  Several of thesystems located in the Powder River and Wind River basins did not integratedirectly into our existing systems, and accordingly we sold these systems inthe third and fourth quarters of 2003.

 

***TocaProcessing Facility.  ***In2002, we sold our Toca processing facility in Louisiana.  The sale price was $32.2 million, andresulted in a pre-tax loss of approximately $230,000.  The sale included a natural gas processingplant with a capacity of 160 MMcf per day and a fractionator that couldseparate 14,200 barrels per day of mixed natural gas liquids into propane,normal butane, iso-butane and natural gasoline. The sale also included NGL storage as well as truck, rail and bargeloading facilities, which support the complex.

 

***Bethel Treating Facility.  ***In December 2000,we signed an agreement for the sale of all the outstanding stock of our thenwholly owned subsidiary, Pinnacle Gas Treating, Inc., or Pinnacle, for$38.0 million.  The only asset of thissubsidiary was a 300 MMcf per day treating facility and 86 miles of associatedgathering assets located in east Texas.  Thesale closed in January 2001 and resulted in a net pre-tax gain for financialreporting purposes of $12.1 million in the first quarter of 2001.

 

***Arkoma.***  In August 2001, we sold our ArkomaGathering System in Oklahoma for gross proceeds of $10.5 million.  This sale resulted in a pre-tax gain of $3.9million.

 

***Westana.  ***In February 2001,we acquired the remaining 50% interest in the Westana Gathering Company for anet purchase price of $9.8 million.

 

***Western Gas Resources-California, Inc.***** In January 2001,we sold all the outstanding stock of our then wholly owned subsidiary, WesternGas Resources-California, Inc., or WGR-California, for $14.9 million.  The only asset of this subsidiary was a 162-milepipeline in the Sacramento Basin of California. WGR-California acquired the pipeline through the exercise of a purchaseoption in a transaction that closed immediately prior to the sale by us ofWGR-California.  We recognized a pre-taxgain on the sale of approximately $5.4 million in 2001.

 

##### ***TransportationOperations***

 

##### ***We own and operate MIGC, Inc.,an interstate pipeline located in the Powder River Basin, and MGTC, Inc.,an intrastate pipeline located in northeast Wyoming.  MIGC charges a Federal Energy RegulatoryCommission, or FERC, approved tariff and is connected to pipelines owned byColorado Interstate Gas Company, Williston Basin Interstate Pipeline Company,Kinder Morgan Interstate Pipeline Co., Wyoming Interstate Company, Ltd. andMGTC.  MIGC earns fees on a monthly basisfrom firm capacity contracts under which the shipper pays for transportcapacity whether or not the capacity is used and from interruptible contractswhere a fee is charged based upon volumes received into the pipeline.  Contracts with third parties for capacity onMIGC range in duration from one month to five years and the fees chargedaveraged $0.35 per Mcf in 2004.  MGTC, apublic utility, provides transportation and gas sales to various cities inWyoming at rates that are subject to the approval of the Wyoming Public ServiceCommission.***

 

The following table provides informationconcerning our principal transportation assets at December 31, 2004.

 
| ** **                        | ** ** | ** **                  | ** ** | ** **                | ** ** | **Average for the Year Ended  December 31, 2004** | ** ** |
|-----------------------------------|------------|-----------------------------|------------|---------------------------|------------|--------------------------------------------------------|------------|
| **Transportation Facilities (1)** | ** ** | **Year Placed  In Service** | ** ** | **Transportation  Miles** | ** ** | **Pipeline Capacity  (MMcf/D) (2)**                    | ** ** | **Gas Throughput  (MMcf/D) (3)** | ** ** |
| MIGC                              |       | 1970                        |       | 263                       |       | 130                                                    |       | 147 |   |
| MGTC                              |       | 1963                        |       | 251                       |       | 18                                                     |       | 8 |   |
| Total                             |       |                        |       | 514                       |       | 148                                                    |       | 155 |   |

 

14

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(1)                    Our interestin both facilities is 100%, and we operate both facilities.

(2)                    Pipelinecapacity represents certificated capacity at the Powder River junction only anddoes not include interruptible capacity or capacity at other delivery points.

(3)                    Aggregatevolumes transported by a pipeline.

 

***Marketing***

 

***Gas*.* ***We market gas produced at ourwells and at our plants and gas purchased from third-parties to end-users,local distribution companies, or LDCs, pipelines and other marketing companiesthroughout the United States and Canada. In addition to our offices in Denver, we have marketing offices inHouston, Texas and Calgary, Alberta. Third-party sales, firm transportation capacity on interstate pipelinesand our gas storage positions, combined with the stable supply of gas from ourfacilities and production, enable us to respond quickly to changing marketconditions and to take advantage of seasonal price variations and peak demandperiods.

 

One of the primary goals of our gas marketingoperations continues to be the preservation and enhancement of the valuereceived for our equity volumes of natural gas. This goal is achieved through the use of hedges on the production of ourequity natural gas and through the use of firm transportation capacity.  Historically, the gas produced in the RockyMountain region has traded at a substantial discount to the Mid-Continent andWest Coast areas as a result of limited pipeline capacity from the region.  We have historically used our firm pipelinetransportation capacity to access higher priced Mid-Continent markets for bothour equity production and for gas purchased from third-parties in the RockyMountain region.  During 2003, additionalpipeline capacity out of the Rocky Mountain region went into service.  This pipeline expansion contributed to areduction in the price difference between the Rocky Mountain region andMid-Continent market center.  Theadditional pipeline capacity from the Rocky Mountain region to theMid-Continent producing region of the country along with increased explorationand production in the Mid-Continent region may increase overall utilization ofthe pipeline systems that are used to move gas out of the Mid-Continent regionto consuming areas in the upper Midwest. Increased throughput on those systems may cause the market price fornatural gas within the Mid-Continent to be reduced relative to othermarkets.  Consistent with our goal topreserve and enhance the value of equity volumes of natural gas, in 2004, wehave acquired approximately 101,000 MMBtu per day of additional firmtransportation capacity out of the Mid-Continent region to market areas in theupper Midwest and the Mississippi River Valley.

 

For the year ended December 31, 2004,our total gas sales volumes averaged 1.2 Bcf per day, of which 344 MMcf per daywas produced at our plants or from our producing properties.  We do not expect our average daily sales volumeto increase in 2005.  The marketing ofgas purchased from third-parties typically results in low profit marginsrelative to the sales price.  We sell gasunder agreements with varying terms and conditions in order to match seasonaland other changes in demand.  As of December 31,2004, the weighted average duration of our sales contracts was 12 months.   During the year ended December 31,2004, we sold gas to approximately 252 end-users, pipelines, LDCs and othercustomers.  No single customer accountedfor more than approximately 9% of our consolidated revenues from the sale ofgas, or 7% of total consolidated revenue, for the year ended December 31,2004.  We continually monitor and reviewthe credit exposure to our gas marketing counterparties.

 

***NGLs*.* ***We market NGLs, or ethane,propane, iso-butane, normal butane, natural gasoline and condensate, producedat our plants and purchased from third-parties, in the Rocky Mountain,Mid-Continent and Southwestern regions of the United States.  A majority of our production of NGLs moves tothe Gulf Coast area, which is the largest NGL market in the United States.  Through the development of end-use marketsand distribution capabilities, we seek to ensure that products from our plantsmove on a reliable basis, avoiding curtailment of production.  For the year ended December 31, 2004,NGL sales averaged 1,641 MGal per day, of which 1,386 MGal per day was producedat our plants.

 

Consumers of NGLs are primarily thepetrochemical industry, the petroleum refining industry and the retail andindustrial fuel markets.  As an example,the petrochemical industry uses ethane, propane, normal butane and naturalgasoline as feedstocks in the production of ethylene, which is used in theproduction of various plastics products. Further, consumers use propane for home heating, transportation andagricultural applications.  Price,seasonality and the economy primarily affect the demand for NGLs.

 

We sell NGLs under agreements with varyingterms and conditions in order to match seasonal and other changes in demand. AtDecember 31, 2004, the terms of our sales contracts range from one monthto three years.  The marketing of NGLspurchased from third-parties typically results in low profit margins relativeto the sales price.  As in the case ofnatural gas, we continually monitor and review the credit exposure to our NGLmarketing counterparties.

 

15

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In 2004, one customer accounted forapproximately 51% of the Company’s consolidated revenues from the sale of NGLs,or 7% of total consolidated revenue. This customer is a large integrated energy company.  We also derive revenues from contractualmarketing fees charged to some producers for NGL marketing services.  For the year ended December 31, 2004,these fees were less than 2% of our total consolidated revenue.

 

#### ***Environmental***

#### *** ***

The construction and operation of ourgathering systems, plants and other facilities used for the gathering,processing, treating or transporting of gas and NGLs are subject to federal,state and local environmental laws and regulations, including those that canimpose obligations to clean up hazardous substances at our facilities or atfacilities to which we send wastes for disposal. In most instances, the applicableregulatory requirements relate to water and air pollution control or wastemanagement. We employ specialists in environmental engineering, safety andregulatory compliance to monitor environmental and safety compliance at ourfacilities.  In addition, ourenvironmental engineers and safety specialists perform in-house audits of ourexisting facilities to ensure on-going compliance. Similarly, prior toconsummating any major acquisition, our environmental engineers perform auditson the facilities to be acquired.  Webelieve that we are in substantial compliance with applicable materialenvironmental laws and regulations. Environmental regulation can increase thecost of planning, designing, constructing and operating our facilities.  We anticipate that the trend in environmentallegislation and regulation will continue to be toward stricter standards.  The costs for compliance with currentenvironmental laws and regulations have not had and, we believe, will not havea material adverse effect on our financial position or results ofoperations.  We however cannot predictthe extent or timing of future regulations or legislation and whether any suchregulations or legislation will have a material adverse effect on the financialresults of our operations, financial position or cash flows.

 

Prior to consummating any major acquisition,our environmental engineers perform audits on the facilities to be acquired. Inconducting this audit on the acquisition of the gathering and processingfacilities acquired in February 2005, we performed phase one environmentalassessments and, where conditions indicated, performed phase twoassessments.  These assessments enabledus to satisfy ourselves that the disclosures by the seller were materiallyaccurate and also to form our own risk assessment of potential environmentalissues.  In relation to the assetspurchased in the February 2005 acquisition, one of the sites was thesubject of an Administrative Order between the former owner, the State ofWyoming and a third party who has contracted to remediate the site inaccordance with the Administrative Order. As a result of the acquisition, we also became a party to theAdministrative Order.  Both that site andanother site are insured under an insurance policy that was put in place by theseller for the costs of all remediation activities.  The obligation to perform and complete thoseremediation activities has been assigned contractually to a third partyenvironmental specialist whose costs will be reimbursed by the insurancepolicy.

 

We are in the process of voluntarily cleaningup substances at several of the facilities that we operate. Our expendituresfor environmental evaluation and remediation at existing facilities have notbeen significant in relation to our results of operations and totaledapproximately $2.1 million for the year ended December 31, 2004.  In addition, in 2004, we paid approximately$467,000 in air emissions fees to the states in which we operate.

 

***Competition***

 

We compete with other companies in the gathering,processing, treating and marketing businesses both for supplies of natural gasand for customers for our natural gas and NGLs, and in our exploration andproduction business for the acquisition of leaseholds and other assets orservices. Competition for natural gas supplies is primarily based on theefficiency and reliability of our services, the availability of transportationand the ability to obtain a satisfactory price for natural gas and NGLs.  Our competitors for obtaining additional gassupplies, for gathering and processing gas and for marketing gas and NGLsinclude national and local gas gatherers and processors, brokers, marketers anddistributors of various sizes and experience. The majority of these competitors have greater financial resources thando we.  For customers that have thecapability of using alternative fuels, such as oil and coal, we also competefor their business based on the price and availability of such alternativefuels. Our competitors for obtaining leaseholds include major and largeindependent oil companies as well as smaller independent oil companies andbrokers.  Competition for oil fieldservices, including drilling rigs, could affect future drilling plans andcosts.  Competition for sales customersis primarily based upon reliability and price of deliverable natural gas andNGLs.  Suppliers in our gas marketingtransactions may request additional financial security such as letters ofcredit that are not required of some of our competitors.

 

16

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#### ***Regulation***

#### *** ***

Our purchase and sale of natural gas and NGLsand the fees we receive for gathering and processing have generally not beensubject to regulation.  However, someaspects of our business are subject to federal, state and local laws andregulations that have a significant impact upon our overall operations.   See additional discussion of regulatoryissues and requirements in Upstream Operations.

 

As a producer, processor and marketer ofnatural gas, we depend on the transportation and storage services offered byvarious interstate and intrastate pipeline companies for the delivery and saleof our own gas supplies as well as those we process and/or market for others.Both the interstate pipelines’ performance of transportation and storageservices, and the rates charged for such services, are subject to thejurisdiction of the FERC, under the Natural Gas Act of 1938 and the Natural GasPolicy Act of 1978. At times, other system users can pre-empt the availabilityof interstate transportation and storage services necessary to enable us tomake deliveries and/or sales of gas in accordance with FERC-approved methodsfor allocating the system capacity of open access pipelines. Moreover, therates the pipelines charge for such services are often subject to negotiationbetween shippers and the pipelines within FERC-established parameters and willperiodically vary depending upon individual system usage and other factors. Aninability to obtain transportation and/or storage services at competitive ratescan hinder our processing and marketing operations and/or adversely affect oursales margins.

 

Generally, neither the FERC nor any stateagency regulates gathering and processing prices. The Oklahoma CorporationCommission has limited authority in some circumstances, after the filing of acomplaint by a producer, to compel a gas gatherer to provide open accessgathering and to set aside unduly discriminatory gathering fees. From time totime, state legislatures have considered, and may do so in the future, adoptinglegislation that would expand the authority of the relevant stateadministrative body to compel a gas gatherer to publish rates, terms andconditions of its service and under some circumstances, to justify thosecharges.  We cannot predict whatadditional legislation or regulations the states may adopt regarding gasgathering.

 

The construction of additional gathering,processing and treating facilities and the development of natural gas reservesrequire permits from several federal, state and local agencies.  In the past we have been successful inreceiving all permits necessary to conduct our operations.  There can be no assurance, however, that permitsin the future will be obtainable or issued timely or that the terms of anypermits will be compatible with our business plans.

 

#### ***Employees***

#### *** ***

At December 31, 2004, we employed 729full-time employees, of which 434 were employed at field locations.  None of our employees is a union member. Weconsider relations with employees to be excellent.

 

**ITEM 3. LEGAL PROCEEDINGS**

 

Reference is made to Note 8 of our ConsolidatedFinancial Statements in Item 8 of this Form 10-K/A.

 

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

 

There were no matters submitted to a vote ofsecurity holders during the quarter ended December 31, 2004.

 

17

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**PART II**

 

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

 

As of March 3, 2005, there were 74,183,197shares of common stock outstanding held by 181 holders of record. The commonstock is traded on the New York Stock Exchange, or NYSE, under the symbol “WGR”.  The following table sets forth quarterly highand low per share sales prices as reported by the NYSE Composite Tape for thequarterly periods indicated.

 

| ** **      | ** ** | **HIGH** | ** ** | **LOW** | ** ** |
|-----------------|------------|----------|------------|---------|------------|
|            |       |     |       |    |       |
| **2004**        |       |     |       |    |       |
| Fourth  Quarter |       | $        | 31.50      |    | $          | 26.38 |   |
| Third  Quarter  |       | 35.25    |       | 27.50   |       |
| Second  Quarter |       | 32.78    |       | 24.97   |       |
| First  Quarter  |       | 25.75    |       | 22.75   |       |
|            |       |     |       |    |       |
| **2003**        |       |     |       |    |       |
| Fourth  Quarter |       | $        | 23.75      |    | $          | 19.20 |   |
| Third  Quarter  |       | 20.03    |       | 18.20   |       |
| Second  Quarter |       | 20.83    |       | 15.96   |       |
| First  Quarter  |       | 18.75    |       | 15.28   |       |

 

We paid dividends on our common stockaggregating $0.05 per share during each of the second, third and fourthquarters of 2004 and $0.025 per share during the first quarter of 2004 and ineach quarter during 2003.  Our board ofdirectors has declared a dividend of $0.05 per share of common stock for thequarter ending March 31, 2005 to holders of record as of that date.  Declarations of dividends on our common stockare within the discretion of the board of directors.  In addition, our ability to pay dividends onour common stock is restricted by covenants in our financing facilities.

 

***Equity Compensation Plan Information***

 

The following table summarizes our equitycompensation plans under which securities may be issued as of December 31,2004.  The only types of equitycompensation plans that we have are plans that authorize the granting ofoptions to purchase shares of our common stock.

 
| **Plan Category**                                           | ** ** | **Number of securities to be  issued upon exercise of  outstanding options  (a)** | ** ** | **Weighted-average per share  exercise price of outstanding  options  (b)** | ** ** | **Number of securities  remaining available for  future issuance under equity  compensation plans  (excluding securities  reflected in column (a))  (c)** | ** ** |
|-------------------------------------------------------------|------------|-----------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| Equity compensation plans approved by  security holders     |       | 3,151,055                                                                         |       | $                                                                           | 21.60      |                                                                                                                                                      | 996,044*   |   |
| Equity compensation plans not approved by  security holders |       | 606,600                                                                           |       | $                                                                           | 12.40      |                                                                                                                                                      | —     |   |
| Total                                                       |       | 3,757,655                                                                         |       | $                                                                           | 20.12      |                                                                                                                                                      | 996,044    |   |

 

----

*  Includes options covering 745,204 shares thatare available to be granted under our 1997 stock option plan.   Our board of directors has determined thatno further options will be granted under this plan.

 

Adescription of the equity compensation plans that were not approved by thesecurity holders is as follows.

 

***1999 Non-Employee Directors StockOption Plan. *** Effective March 1999, our board ofdirectors adopted a stock option plan that authorized the granting of optionsto purchase 30,000 shares of our common stock to non-employee directors.  During 1999, the board of directors approvedgrants of options covering a total of 30,000 shares of our common stock toseveral board members.  The exerciseprice of the stock underlying each option was the average closing price for theten days prior to the

 

18

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grant.  Under this plan, options covering up to 331/3% of the underlying shares are exercisable on each anniversary from the dateof grant and the director must exercise the option within five years of thedate each option vests.  This planterminates on the earlier of March 12, 2009 or the date on which alloptions granted under the plan have been exercised in full.

 

***ChiefExecutive Officer and President’s Plan. ***Pursuant tothe employment agreement, dated October 15, 2001, and the stock optionagreement, dated as of November 1, 2001, between Western and Peter A. Dea,our CEO and President, we granted non-qualified stock options to Mr. Deafor the purchase of 600,000 shares of our common stock.  The exercise price of the options was equalto $2.50 below the closing price per share on the effective date of hisemployment agreement.  The stock optionsare subject to the conditions of the agreements and vest equally over fouryears and must be exercised within five years of the date on which theyvest.  The difference between the closingprice on the effective date and the exercise price is being amortized over fouryears as compensation expense.  Thisoption plan will terminate on the earlier of October 15, 2010 or the dateon which all options granted under the plan have been exercised in full.

 

19

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**ITEM 6.****                    SELECTED FINANCIAL DATA**

 

The following table sets forth selectedconsolidated historical financial and operating data for Western, which hasbeen restated to reflect adjustments to the Original Filing for our accountingfor gas storage and gas transportation contracts.  This is further discussed in “ExplanatoryNote” in the forepart of this Form 10-K/A and in Note 2, “Restatement ofConsolidated Financial Statements”, to our consolidated financial statementsincluded in this Form 10-K/A.  Thedata for the three years ended December 31, 2004, 2003 and 2002 should beread in conjunction with our Consolidated Financial Statements and the Notesthereto included elsewhere in this Form 10-K/A.  The selected consolidated financial data forthe year ended December 31, 2001 is derived from our audited historicalConsolidated Financial Statements and has also been restated as described innote (d) below.  The selectedconsolidated financial data for the year ended December 31, 2000 isderived from our audited historical Consolidated Financial Statements.  See also Item 7 – “Management’s Discussionand Analysis of Financial Condition and Results of Operations.” Amounts inthousands, except per share amounts and operating data.

 
| ** **                                                                                     | ** ** | **Year ended December 31,** | ** ** |
|------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                     | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** | **2000** | ** ** |
| ** **                                                                                     | ** ** | **Restated**                     | ** ** | **Restated** | ** ** | **Restated** | ** ** | **Restated (c)** | ** ** | ** ** | ** ** |
| **Statement of Operations:**                                                                   |       |                             |       |   |   |   |   |   |   |   |   |
| Revenues                                                                                       |       | $                                | 3,083,168  |   | $ | 2,879,751 |   | $ | 2,463,746 |   | $ | 3,364,219 |   | $ | 3,280,091 |   |
| Income before income taxes                                                                     |       | 196,723                          |       | 150,277 |   | 54,751 |   | 163,183 |   | 88,673 |   |
| Provision for income taxes                                                                     |       | 73,678                           |       | 55,618 |   | 20,645 |   | 60,582 |   | 32,565 |   |
| Income before cumulative effect of change  in accounting principle                             |       | 123,045                          |       | 94,659 |   | 34,106 |   | 102,601 |   | 56,108 |   |
| Cumulative effect of change in accounting  principle, net of tax                               |       | 4,714                            | (b)        | (6,724 | )(a) | — |   | — |   | — |   |
| Net income                                                                                     |       | 127,759                          |       | 87,935 |   | 34,106 |   | 102,601 |   | 56,108 |   |
| Earnings per share of common stock before  cumulative effect of change in accounting principle |       | 1.68                             |       | 1.32 |   | 0.38 |   | 1.40 |   | 0.71 |   |
| Earnings per share of common stock                                                             |       | 1.75                             |       | 1.22 |   | 0.38 |   | 1.40 |   | 0.71 |   |
| Earnings per share of common stock -  assuming dilution                                        |       | 1.73                             |       | 1.18 |   | 0.37 |   | 1.33 |   | 0.70 |   |
|                                                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| **Other Financial Data:**                                                                      |       |                             |       |   |   |   |   |   |   |   |   |
| Net cash provided by operating activities                                                      |       | $                                | 209,159    |   | $ | 244,222 |   | $ | 124,401 |   | $ | 170,881 |   | $ | 99,637 |   |
| Net cash (used in) investing activities                                                        |       | (302,455                         | )          | (197,085 | ) | (105,772 | ) | (131,657 | ) | (82,039 | ) |
| Net cash provided by (used in) financing  activities                                           |       | 67,570                           |       | (28,333 | ) | (21,349 | ) | (42,119 | ) | (18,733 | ) |
| Capital expenditures                                                                           |       | 306,266                          |       | 203,068 |   | 140,637 |   | 169,751 |   | 108,536 |   |
|                                                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| **Balance Sheet Data (at year end):**                                                          |       |                             |       |   |   |   |   |   |   |   |   |
| Total assets                                                                                   |       | $                                | 1,837,398  |   | $ | 1,450,232 |   | $ | 1,285,541 |   | $ | 1,264,699 |   | $ | 1,431,422 |   |
| Long-term debt                                                                                 |       | 382,000                          |       | 339,000 |   | 359,933 |   | 366,667 |   | 358,700 |   |
| Stockholders’ equity                                                                      |       | 684,769                          |       | 556,706 |   | 473,549 |   | 480,317 |   | 391,534 |   |
| Dividends on preferred stock                                                                   |       | 835                              |       | 6,841 |   | 9,198 |   | 11,167 |   | 10,416 |   |
| Dividends on common stock                                                                      |       | 12,847                           |       | 6,684 |   | 6,603 |   | 6,524 |   | 6,448 |   |
| Dividends per share of common stock                                                            |       | 0.18                             |       | 0.10 |   | 0.10 |   | 0.10 |   | 0.10 |   |
|                                                                                           |       |                             |       |   |   |   |   |   |   |   |   |
| **Operating Data:**                                                                            |       |                             |       |   |   |   |   |   |   |   |   |
| Average gas sales (MMcf/D)                                                                     |       | 1,225                            |       | 1,361 |   | 1,988 |   | 1,961 |   | 1,835 |   |
| Average NGL sales (Mgal/D)                                                                     |       | 1,641                            |       | 1,634 |   | 2,010 |   | 2,347 |   | 3,085 |   |
| Average gas volumes gathered (MMcf/D)                                                          |       | 1,361                            |       | 1,343 |   | 1,163 |   | 1,161 |   | 1,248 |   |
| Facility capacity (MMcf/D)                                                                     |       | 3,146                            |       | 2,883 |   | 2,581 |   | 2,574 |   | 2,374 |   |
| Net annual production volume (Mmcfe)                                                           |       | 55,474                           |       | 52,672 |   | 47,719 |   | 35,784 |   | 28,187 |   |
| Average gas prices ($/Mcf)                                                                     |       | $                                | 5.59       |   | $ | 4.94 |   | $ | 2.92 |   | $ | 3.97 |   | $ | 3.90 |   |
| Average NGL prices ($/Gal)                                                                     |       | $                                | 0.75       |   | $ | 0.58 |   | $ | 0.42 |   | $ | 0.49 |   | $ | 0.52 |   |

 

20

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(a)                                  We recognized an after-tax loss on the adoption of SFAS No. 143,”Accountingfor Asset Retirement Obligations.”

 

(b)                                 We recognized an after-tax gain upon a change in the methodof depreciation and depletion of our exploration and production assets.

 

(c)                                  As a result of our review of our gas storage and gas transportationcontracts, we determined that these contracts did not meet the definition of aderivative in 2001 as required under FAS 133. Accordingly, we have also restated the results for the year ended December 31,2001 as follows (amounts in thousands, except per share amounts):

 
| ** **                             | ** ** | **As Reported** | ** ** | **As Restated** | ** ** |
|----------------------------------------|------------|-----------------|------------|-----------------|------------|
| Total  revenues                        |       | $               | 3,353,162  |            | $          | 3,364,219 |   |
| Income  before taxes                   |       | 152,126         |       | 163,183         |       |
| Net income                             |       | 95,637          |       | 102,601         |       |
| Earnings per  share- assuming dilution |       | 1.24            |       | 1.33            |       |
| Total assets                           |       | 1,267,942       |       | 1,264,699       |       |
| Stockholders’  equity             |       | $               | 473,352    |            | $          | 480,317 |   |

 

21

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

 

The followingdiscussion and analysis relates to factors that have affected our consolidatedfinancial condition and results of operations for the three years ended December 31,2004, 2003 and 2002.  This informationshould be read in conjunction with our Consolidated Financial Statements andrelated Notes thereto and the Selected Financial Data included Item 8 of this Form 10-K/A.  Herein we make forward-looking statementsthat involve risks, uncertainties, and assumptions.  Actual results may differ materially fromthose anticipated in these forward-looking statements as a result of variousfactors, including, but not limited to, those presented under “CautionaryStatement Regarding Forward-Looking Information” on page 36.

 

***Restatement ofPreviously Issued Financial Statements***

 

Upon adoption ofFAS 133 in 2001, we analyzed our gas storage and gas transportation contractsin detail, and determined that these contracts had the characteristics of aderivative as described in FAS 133. On November 21, 2005, we announcedthat our management and our audit committee have completed a review of theaccounting treatment of our gas storage and gas transportation contracts anddetermined that these contracts do not meet the definition of a derivativeunder FAS 133.  Specifically, after adetailed review of the contracts and the market for those contracts, wesubsequently determined that these contracts do not meet the definition of aderivative under FAS 133 as: (i) the market for these types of contractsis not sufficiently liquid for us to receive fair value in a ready market and (ii) ifthe contract is assigned, there is no assurance that we will be relieved of ourrights and obligations under the contract. Accordingly,we have restated our audited financial statements for the years from2001 through 2004 and our unaudited financial statements for the first twoquarters of 2005 as well as for all the first three quarters of 2004 and 2003.

 

Historically, the non-cash mark-to-market valuationof the gas storage and transportation contracts which prior to the restatementwere considered to be derivatives effectively offset non-cash mark-to-marketchanges to the forward derivative contracts to sell our stored or transportednatural gas.  After the adjustments tocorrect the prior accounting for these contracts as derivatives, the non-cashmark-to-market of the forward derivative contract on the sale of gas willfluctuate through earnings with changes in market prices and will not be offsetby a corresponding mark to market on the gas storage and transportationcontracts.  As the stored or transportednatural gas is sold and the forward sale derivatives are settled, we willrealize the benefit of the storage and transportation transactions throughearnings.

 

The effect of therestatement for each of the years ended December 31, 2002 through 2004 isas follows.  For additional informationon the nature and impact of these accounting corrections, see Note 2, “Restatementof Consolidated Financial Statements,” to our Consolidated Financial Statementsincluded elsewhere in this Form 10-K/A (amounts in thousands, except pershare calculations):

 
| ** **                             | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------|------------|----------------------------------|------------|
| ** **                             | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                             | ** ** | **As**                           | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** |
| ** **                             | ** ** | **Reported**                     | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** |
| Total revenues                         |       | $                                | 3,069,713  |   | $ | 3,083,168 |   | $ | 2,874,010 |   | $ | 2,879,951 |   | $ | 2,489,698 |   | $ | 2,463,746 |   |
| Income before taxes                    |       | 183,268                          |       | 196,723 |   | 144,536 |   | 150,277 |   | 80,703 |   | 54,751 |   |
| Net income                             |       | 119,215                          |       | 127,759 |   | 84,219 |   | 87,935 |   | 50,589 |   | 34,106 |   |
| Earnings per share - assuming dilution |       | 1.61                             |       | 1.73 |   | 1.13 |   | 1.18 |   | 0.62 |   | 0.37 |   |
| Cash flow from operating activities    |       | $                                | 209,159    |   | $ | 209,159 |   | $ | 244,222 |   | $ | 244,222 |   | $ | 124,401 |   | $ | 124,401 |   |
|                                        |            |                                  |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

***Company Overview***

 

***Business Strategy. *** Maximizing the value of our existing coreassets is the focal point of our business strategy.   Our core assets are our fully integratedupstream and midstream assets in the Powder River and Greater Green RiverBasins in Wyoming, the San Juan Basin in New Mexico, the Sand Wash Basin inColorado and our midstream operations in west Texas and Oklahoma.  Our long-term business plan is to increasestockholder value by: (i) doubling proven natural gas reserves and equityproduction of natural gas from the levels achieved in 2001 over a five yearperiod; (ii) meeting or exceeding throughput projections in our midstreamoperations; and (iii) optimizing annual returns.

 

***Industryand Company Overview.  ***InNorth America, our industry has experienced several consecutive years ofdeclining natural gas production.  Mostof the major gas producing areas, such as the Gulf of Mexico, are mature andare in production decline.  We areconcentrating our efforts in the Rocky Mountain gas producing basins wherethere are estimated to be large

 

22

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quantities of undevelopedgas.  The U.S. government largely retainsthe mineral rights to these undeveloped reserves; accordingly, the developmentand production of these reserves require permits from several governmentalagencies including the BLM.  We are wellpositioned for future production growth with a large inventory of undevelopeddrilling locations in the Powder River, the Greater Green River and San JuanBasins to meet the growing demand for clean burning natural gas.  In addition, our experience and technicalexpertise position us to acquire new opportunities to develop natural gas inthe Rocky Mountain region.  Ourchallenges will be to accomplish these goals with the difficulties encounteredby the industry in obtaining the necessary permits from the BLM, and stateagencies such as the Wyoming DEQ.  Webelieve that our technical expertise in developing environmentally responsiblesolutions to the problems encountered in the development of gas reserves willbe a competitive advantage in overcoming these challenges.

 

Our operations are conducted through thefollowing four business segments:

 

***Exploration and Production. ***We explorefor, develop and produce natural gas reserves independently and to enhance andsupport our existing gathering and processing operations. Our producingproperties are primarily located in the Powder River and Greater Green RiverBasins, and the Sand Wash Basin.  Theseplays are relatively low-risk, multi-year development projects.  These provide us with the opportunity tosteadily increase our production volume over time at reasonable operating andlow finding and development costs.  In 2004our average production sold was 153 MMcfe per day, which is a 2% increase overthe average production volume sold in 2003.

 

We continue to seek to add additionalupstream core projects that are focused on Rocky Mountain natural gas.  We will utilize our expertise in explorationand low-risk development of unconventional gas reservoirs including tight-gassands, coal bed methane, biogenic, and shale gas plays to evaluate acquisitionsof either additional leaseholds, proven and undeveloped reserves or companieswith operations primarily focused in the Rockies.  We may also evaluate unconventional gasreservoirs in areas outside the Rockies where we can leverage our relatedexploration, production and gathering expertise.  In January 2005, we opened an explorationoffice in Calgary, Alberta, Canada to evaluate opportunities in the WesternCanadian Sedimentary Basin.  Through December 31,2004, we have acquired the drilling rights on approximately 874,000 net acresin other Rocky Mountain basins and continue to expand our leasehold positions.

 

***Gathering, Processing andTreating. ***Ourcore operations are in well-established areas such as the Permian, Anadarko,Powder River, Greater Green River, and San Juan Basins.  We connect natural gas from gas and oil wellsto our gathering systems for delivery to our processing or treating plantsunder long-term contracts. At our plants we process natural gas to extract NGLsand treat natural gas in order to meet pipeline specifications. We providethese services to major oil and gas companies, to independent producers ofvarious sizes and for our own production. We believe that our low cost of operations, our high on-line time andour safety records are key elements in our ability to compete effectively andprovide service to our customers.  Ourexpertise in gathering, processing and treating operations can enhance theeconomics of developing new upstream projects.

 

This segment of our operations has provided astream of operating profit that is available for reinvestment into otherprojects or other segments of our business. Overall throughput in our facilities during 2004 remained relativelyconstant as compared to 2003 and averaged a total of 1.4 Bcf per day.

 

***Transportation. *** In the Powder River Basin, we own one interstatepipeline, MIGC, Inc., and one intrastate pipeline, MGTC, Inc., whichtransport natural gas for producers and energy marketers under fee schedulesregulated by state or federal agencies.

 

***Marketing. ***Our gasmarketing segment is an outgrowth of our gas processing and upstreamactivities.  One of the primary goals ofour gas marketing operations is the preservation and enhancement of the valuereceived for our equity volumes of natural gas. This goal is achieved through the use of hedges on the production of ourequity natural gas and NGLs and through the use of firm transportationcapacity.  We also buy and sell naturalgas and NGLs in the wholesale market in the United States and in Canada.  These third-party sales, our firmtransportation capacity on interstate pipelines and our gas storage positions,combined with the stable supply of gas from our facilities and production,enable us to respond quickly to changing market conditions and to takeadvantage of seasonal price variations and peak demand periods.

 

23

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***Results of Operations***

 

**Year ended December 31, 2004 compared toyear ended December 31, 2003**

**(amounts in thousands, except per shareamounts and operating data)**

 
| ** **                                           | ** ** | **Year Ended  December 31,** | ** ** | ** **   | ** ** |
|------------------------------------------------------|------------|-----------------------------------|------------|--------------|------------|
| ** **                                           | ** ** | **2004**                          | ** ** | **2003**     | ** ** | **Percent** | ** ** |
| ** **                                           | ** ** | **Restated**                      | ** ** | **Restated** | ** ** | **Change** | ** ** |
| **Financial  results:**                              |       |                              |       |         |       |   |   |
| Revenues                                             |       | $                                 | 3,083,168  |         | $          | 2,879,751 |   | 7 |   |
| Net income                                           |       | 127,759                           |       | 87,935       |       | 45 |   |
| Earnings per share of common stock                   |       | 1.75                              |       | 1.22         |       | 43 |   |
| Earnings per share of common stock - diluted         |       | 1.73                              |       | 1.18         |       | 47 |   |
| Net cash  provided by operating activities           |       | 209,159                           |       | 244,222      |       | (14 | ) |
| Net cash  used in investing activities               |       | (302,455                          | )          | (197,085     | )          | 54 |   |
| Net cash  provided by (used in) financing activities |       | 67,570                            |       | (28,333      | )          | 338 |   |
|                                                 |       |                              |       |         |       |   |   |
| **Operating  data:**                                 |       |                              |       |         |       |   |   |
| Average gas  sales (MMcf/D)                          |       | 1,225                             |       | 1,361        |       | (10 | ) |
| Average NGL  sales (MGal/D)                          |       | 1,641                             |       | 1,634        |       | — |   |
| Average gas  prices ($/Mcf)                          |       | $                                 | 5.59       |         | $          | 4.94 |   | 13 |   |
| Average NGL  prices ($/Gal)                          |       | $                                 | 0.75       |         | $          | 0.58 |   | 29 |   |

 

Net income increased $39.8 million for the yearended December 31, 2004 compared to 2003. This increase was primarilyattributable to higher product prices and mark-to-market non-cash gains from our price riskmanagement activity related to future sales of gas utilizing our storage andtransportation capacity. The price increases were somewhat offset by reducedsegment operating profit from the marketing segment, and after-tax chargesassociated with a settlement with the Commodity Futures Trading Commission, orCFTC, of $7.0 million and the early extinguishment of long-term debt of $6.7million. Additionally, the 2004 results included a change in accountingprinciple that resulted in a cumulative reduction of depreciation and depletionfor periods prior to 2004 of $4.7 million, net of tax, and the 2003 resultsincluded a $6.7 million after-tax loss from the Cumulative effect of a changein accounting principle from the adoption of SFAS No. 143 “Accounting forAsset Retirement Obligations” on January 1, 2003.

 

Revenues from the sale of gas increased $54.5million to $2,518.3 million for the year ended December 31, 2004 comparedto the year ended December 31, 2003. This increase was primarily due to an increase in product prices, whichmore than offset a decrease in sales volume in 2004.  Average gas prices realized by us increased$0.65 per Mcf to $5.59 per Mcf for the year ended December 31, 2004compared to 2003.  Included in therealized gas price were approximately $7.4 million of gains recognized in 2004related to futures positions on equity gas volumes.   We have entered into additional futurespositions for a portion of our equity gas for 2005.  See further discussion in “Item 7A.Quantitative and Qualitative Disclosures About Market Risk.”  Average gas sales volumes decreased to 1,225MMcf per day in 2004 from 1,361 MMcf per day in 2003.  This decrease was the result of our reductionin third party sales volume due to the increase in product prices and relatedcredit exposure.

 

Revenues from the sale of NGLs increased$104.7 million to $450.8 million for the year ended December 31, 2004compared to 2003.  This is primarily dueto a significant increase in product prices as sales volumes were relativelyconstant.  Average NGL prices realized byus increased $0.17 per gallon to $0.75 per gallon in 2004 compared to2003.  Included in the realized NGL pricewere $16.3 million of losses recognized in 2004 related to futures positions onequity NGL volumes.  We have entered intoadditional futures positions for a portion of our equity NGL production for2005.  See further discussion in “Item7A. Quantitative and Qualitative Disclosures About Market Risk.”  Average NGL sales volumes remained relativelyconstant in 2004 compared to 2003.

 

The effect of Price risk managementactivities changed from ($16.4) million for the year ended December 31,2003 to $20.1 million for the year ended December 31, 2004.  This change was due to the non-cash mark tomarket adjustments of our risk management activities.  This account is primarily impacted by changesin the forward price of natural gas in 2004 as compared to 2003 and the impactof those price changes on the fair value of the forward sale derivatives forour gas in storage.

 

Product purchases increased by $84.4 millionfor the year ended December 31, 2004 compared to 2003.  The increase in product purchases in 2004compared to 2003 was the result of an increase in product prices that more thanoffset the reduction in third party sales volume.  Overall, combined product purchases as apercentage of sales of all products decreased to approximately 86% in 2004 from87% in 2003.  The reduction in thispercentage is primarily the result of a decrease in the sale of third partyproduct.

 

24

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Plant and transportation operating expenseincreased by $7.5 million for the year ended December 31, 2004 compared to2003.  The increase was primarily due toa $4.2 million increase in property tax expense, including approximately $1.8million for prior year property taxes in the state of Oklahoma.   Also contributing to the increase wasincreased fuel costs and compression rental expenses.

 

Oil and gas exploration and productionexpenses increased by $25.4 million in the year ended December 31, 2004compared to 2003.  The increase wassubstantially due to increased lease operating expenses, or LOE, in the PowderRiver Basin coal bed development. Overall, LOE averaged $0.68 per Mcf in 2004compared to $0.46 per Mcf in 2003.  Theincrease in LOE is substantially due to higher water handling charges, contractlabor, and fuel and operating costs of wellhead blowers in the Powder RiverBasin.   We expect the trend ofincreasing LOE per Mcf costs to continue in 2005 as water-handling costs arebeing incurred on dewatering wells in several new pilot areas that have nooffsetting gas production as yet.

 

Depreciation, depletion and amortization, or DD&A, increased by$21.6 million in the year ended December 31, 2004 compared to 2003.  The increase is the result of additionalcapital expenditures and depreciation and depletion on our oil and gasassets.  In total, we had an $8.0 millionincrease in DD&A in our midstream operations primarily due to our expandingCBM gathering system in the Powder River Basin. We also had $13.6 million increase in DD&A in our upstreamoperations primarily due to our continued development in the Powder RiverBasin, downward revisions to reserves in the Powder River Basin, and our October 2004acquisition of producing properties in the San Juan Basin.   Also contributing to the increase inDD&A in our upstream operations was a change in our method of calculatingDD&A.  Effective January 1,2004, we redefined the asset groupings for the calculation of depreciation anddepletion on our oil and gas properties from a well-by-well basis to a fieldwide basis for each of the Jonah, Pinedale and Sand Wash fields and to agrouping of all wells drilled into related coal seams for the Powder RiverBasin. This change resulted in an increase in DD&A of $4.9 million in 2004.

 

The change in the depreciation and depletionmethodology is treated as a change in accounting principle.  Accordingly, the Accumulated depreciation,depletion and amortization for these assets has been recalculated under the newmethodology.  The cumulative effect ofthe change in depreciation and depletion methodology is a benefit of $4.7million, net of tax, and is presented in the Consolidated Statement ofOperations under the caption Cumulative effect of change in accountingprinciple, net of tax.

 

Selling and administrative expenses increasedby $11.8 million in the year ended December 31, 2004 compared to2003.  The increase in selling andadministrative expenses included a $7.0 million settlement with the CFTC in July 2004associated with reporting price information to industry publications, andincreased salary and benefit costs.

 

The Total provision for income taxes as apercentage of Income before income taxes was approximately 37.5% during theyear ended December 31, 2004 as compared to 37.0% in 2003.  This increase is due to the settlement paidto the CFTC, which was non-deductible for tax purposes.

 

***CashFlow Information******.***

 

Cash flows from operating activities decreased by$35.1 million in the year ended December 31, 2004 compared to 2003. Thisdecrease was primarily due to the timing of cash receipts and payables and anincrease in our inventory of products held for future resale.

 

Cash flows used in investing activities increased by$105.4 million in 2004 compared to 2003. This increase was due to an increase in capital expenditures andacquisitions in 2004.

 

Cash flows provided by financing activities increasedby $95.9 million in 2004 compared to 2003. This increase was due to additional borrowings to fund our capitalexpenditure program.

 

***EquityTransactions.***

 

***PreferredStock Conversion/Redemption.***  In December 2003, we issued a notice ofredemption for a total of 800,000 shares of our $2.625 cumulative convertiblepreferred stock.  The holders of theseshares had the right to convert them into shares of our common stock in lieu ofreceiving the redemption price in cash.  In January 2004, we issued an additional 1,979,244 shares of commonstock to holders who elected to convert their shares and paid $672,000 in cashproceeds to complete this redemption.  InMarch 2004, we issued an additional notice of redemption for the remaining1,260,000 shares of our $2.625 cumulative convertible preferred stock.  In April 2004, we issued an additional3,113,582 shares of common stock

 

25

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to holders who elected toconvert their shares and paid $391,000 in cash proceeds to complete thisredemption.  After these redemptions, the$2.625 cumulative convertible preferred stock was delisted from trading on the NewYork Stock Exchange and was deregistered by the SEC.

 

***CommonStock Split. ***OnJune 18, 2004, we completed a two-for-one split of our common stock, whichwas distributed in the form of a stock dividend.  Shareholders of our common stock received oneadditional share for every share of common stock held on the record date of June 4,2004.  Upon completion of the stocksplit, we had approximately 73.6 million shares of common stockoutstanding.  After the stock split, eachshare of common stock outstanding or thereafter issued includes or will includeone-half of a Series A Junior Participating Preferred Stock purchaseright.  We have restated our financialinformation to reflect this split for all periods presented.

 

***Other Information***

 

***Price Reporting to Gas TradePublications. *** In 2003, we learned that several employees inour marketing department furnished inaccurate information regarding natural gastransactions to energy publications which compile and report energy indexprices.  We discovered the inaccuraciesduring a review of our marketing activities, which was being conducted inresponse to a subpoena issued by the CFTC. These employees identified inaccuracies associated with reporting ofnatural gas transactions primarily related to points in Texas.  We have discontinued the practice ofreporting pricing information to industry publications.  In conjunction with our investigation intothis matter, we have taken appropriate disciplinary actions including therelease of one manager in our marketing department.  In July 2004, we reached a settlement ofthis matter with the CFTC.  Inconjunction with this settlement, we paid a civil penalty of $7.0 million.

 

***Acquisitionof San Juan Properties. ***InOctober 2004, we acquired oil and gas assets in the San Juan Basin of NewMexico for approximately $82.2 million, plus assumed liabilities. The purchaseincluded 32,000 gross acres, or 24,000 net acres, with approximately 100 wellsthat were producing an average of 15 MMcf per day, gross, or 11 MMcf per day, net,of coal bed methane.   The purchase alsoincludes approximately 130 miles of related gathering systems, which arecurrently connected to our existing San Juan River plant.

 

*** Acquisition and Disposition of GatheringSystems.*** Effective February 1, 2003, we acquired several gathering systemsin Wyoming, primarily located in the Greater Green River Basin with smalleroperations in the Powder River and Wind River Basins, for a total of $37.1million.  Several of the systems locatedin the Powder River and Wind River did not integrate directly into our existingsystems, and accordingly these systems were sold.  During the year ended December 31, 2003,the income, if any, generated by the assets sold was immaterial.

 

##### ***Acquisition of Sand Wash Properties.***  In August 2003,through the acquisition of the stock of a private corporation for $12.9million, we acquired additional reserves, production and acreage in the SandWash area of the Greater Green River Basin. The assets of this private entity consisted primarily of the remaininginterests in various Sand Wash properties that we operate.  This acquisition included approximately 11Bcfe of proved reserves, 2.1 MMcfe per day of production and approximately11,000 net acres under lease.

 

***SegmentInformation.***

 

***Gas Gathering,Processing and Treating.*** The Gas Gathering, Processing and Treating segment realizedsegment-operating profit of $168.9 million for the year ended December 31,2004 compared to $127.3 million in 2003. The increase in operating profit in this segment in 2004 is primarilydue to higher realized prices and improved contractual terms on gas gathered inthe Powder River Basin.

 
| ** **                                                  | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                  | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| Gross Margin  ($/Mcf)(1)                                    |       | $                                | 0.54       |   | $ | 0.44 |   | $ | 0.39 |   |
| Segment  Plant operating and transportation expense ($/Mcf) |       | 0.19                             |       | 0.17 |   | 0.17 |   |
| Net Margin  ($/Mcf)                                         |       | $                                | 0.35       |   | $ | 0.27 |   | $ | 0.22 |   |

 

----

(1) GrossMargin is segment Total revenues excluding net equity hedging losses lesssegment product purchases.

 

***Explorationand Production.*** The Exploration and Production segment realized segment-operating profitof $156.1 million in 2004 compared to $114.2 million in 2003. The increase isdue to an improvement in realized prices and an increase in the production ofnatural gas.  During 2004, our productionof natural gas as compared to 2003 increased by 5% to 55.5

 

26

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Bcfe.  The following table sets forth the averagesales price received for our oil and gas products in the years ended December 31,2004, 2003 and 2002.

 
| ** **                                              | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                              | ** ** | **2004**                         | ** ** | **2003** | ** ** | **2002** | ** ** |
| Average  sales price: (1)                               |       |                             |       |   |   |   |   |
| Oil ($/Bbl),  excluding the effect of hedging positions |       | $                                | 37.86      |   | $ | 29.21 |   | $ | 23.53 |   |
| Oil ($/Bbl),  including the effect of hedging positions |       | 37.86                            |       | 29.21 |   | 23.53 |   |
|                                                    |       |                             |       |   |   |   |   |
| Gas ($/Mcf),  excluding the effect of hedging positions |       | 4.68                             |       | 4.14 |   | 2.33 |   |
| Gas ($/Mcf),  including the effect of hedging positions |       | 4.80                             |       | 3.74 |   | 2.84 |   |
|                                                    |       |                             |       |   |   |   |   |
| Production  and other costs:                            |       |                             |       |   |   |   |   |
| Lease  operating expense ($/Mcfe)                       |       | 0.68                             |       | 0.46 |   | 0.42 |   |
| Production  tax expense ($/Mcfe)                        |       | 0.50                             |       | 0.39 |   | 0.23 |   |
| Gathering  and transportation expense ($/Mcfe)          |       | 0.72                             |       | 0.69 |   | 0.67 |   |
| Other  expenses ($/Mcfe)                                |       | 0.01                             |       | 0.01 |   | 0.01 |   |
| Total costs ($/Mcfe)                                    |       | $                                | 1.91       |   | $ | 1.55 |   | $ | 1.33 |   |

 

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(1)           Theprices received for NGLs are included in the price received for gas.

 

***Marketing.***  The Marketing segment realizedsegment-operating profit of $38.1 million in the year ended December 31,2004 compared to $36.4 million in 2003.  The increase in the marketing profit is primarilydue to lower profitability in transactions associated with our firmtransportation capacity from the Rocky Mountain region to the Mid-Continentwhich was more than offset by non-cash mark-to-market gains from our price riskmanagement activities related to future sales of gas utilizing our storage andtransportation capacity.  As the stored or transported natural gas issold and the future sale derivatives are settled, we will realize the benefitof the storage and transportation transactions through earnings in the quarterin which the gas is physically sold.

 

***Transportation.***  TheTransportation segment realized segment-operating profit of $11.0million in the year ended December 31, 2004 compared to $11.6 million in2003.  The transportation segmentincludes the results from the MIGC and MGTC pipelines in the Powder RiverBasin.  The decrease in profit in thissegment is due to lower interruptible transportation volume in 2004 as more gaswas transported out of the basin through other pipelines.

 

**Year ended December 31, 2003 compared toyear ended December 31, 2002**

**(amounts in thousands, except per shareamounts and operating data)**

 
| ** **                                    | ** ** | **Year Ended  December 31,** | ** ** | ** **   | ** ** |
|-----------------------------------------------|------------|-----------------------------------|------------|--------------|------------|
| ** **                                    | ** ** | **2003**                          | ** ** | **2002**     | ** ** | **Percent** | ** ** |
| ** **                                    | ** ** | **Restated**                      | ** ** | **Restated** | ** ** | **Change** | ** ** |
| **Financial  results:**                       |       |                              |       |         |       |   |   |
| Revenues                                      |       | $                                 | 2,879,751  |         | $          | 2,463,746 |   | 17 |   |
| Net income                                    |       | 87,935                            |       | 34,106       |       | 158 |   |
| Earnings per  share of common stock           |       | 1.22                              |       | 0.38         |       | 221 |   |
| Earnings per  share of common stock - diluted |       | 1.18                              |       | 0.37         |       | 219 |   |
| Net cash  provided by operating activities    |       | 244,222                           |       | 124,401      |       | 96 |   |
| Net cash  (used in) investing activities      |       | (197,085                          | )          | (105,772     | )          | 86 |   |
| Net cash  (used in) financing activities      |       | (28,333                           | )          | (21,349      | )          | 33 |   |
|                                          |       |                              |       |         |       |   |   |
| **Operating  data:**                          |       |                              |       |         |       |   |   |
| Average gas  sales (MMcf/D)                   |       | 1,361                             |       | 1,988        |       | (31 | ) |
| Average NGL  sales (MGal/D)                   |       | 1,634                             |       | 2,010        |       | (19 | ) |
| Average gas  prices ($/Mcf)                   |       | $                                 | 4.94       |         | $          | 2.92 |   | 69 |   |
| Average NGL  prices ($/Gal)                   |       | $                                 | 0.58       |         | $          | 0.42 |   | 38 |   |

 

Net incomeincreased $53.8 million for the year ended December 31, 2003compared to 2002.  The increase in netincome was primarily attributable to a significant increase in gas and NGLprices in 2003 compared to 2002 and mark-to-market non-

 

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cashgains from our price risk management activities related to future sales of gasutilizing our storage and transportation capacity.  This increase in prices was supplemented byincreased equity production from the Powder River Basin CBM project and theGreater Green River Basin.  Partiallyoffsetting the increase in net income in the year ended December 31, 2003was a $6.7 million after-tax loss from the cumulative effect of a change inaccounting principle from the adoption of SFAS No. 143 “Accounting forAsset Retirement Obligations” on January 1, 2003.

 

Revenues fromthe sale of gas increased $344.6 million to $2,463.7 million for the year endedDecember 31, 2003 compared to 2002. This increase was primarily due to an increase in product prices, whichmore than offset a decrease in sales volume in 2003.  Average gas prices realized by us increased$2.02 per Mcf to $4.94 per Mcf for the year ended December 31, 2003compared to 2002.  Included in thecalculation of the realized gas price were approximately $23.9 million oflosses recognized in the year ended December 31, 2003 related to futurespositions on equity gas volumes.  Averagegas sales volumes decreased 627 MMcf per day to 1,361 MMcf per day for the yearended December 31, 2003 compared to 2002. This decrease was due to a reduction in third party sales volumeresulting from the increase in product prices and an intentional effort toreduce related credit exposure.

 

Revenues fromthe sale of NGLs increased approximately $36.6 million to $346.1 million forthe year ended December 31, 2003 compared to 2002.  This increase is primarily due to asignificant increase in product prices, which was partially offset by areduction in third-party sales volumes. Average NGL prices realized by us increased $0.16 per gallon to $0.58per gallon for the year ended December 31, 2003 compared to 2002.  Included in the calculation of the realizedNGL price were approximately $11.4 million of losses recognized in the yearended December 31, 2003 related to futures positions on equity NGLvolumes.  Average NGL sales volumesdecreased 376 MGal per day to 1,634 MGal per day for the year ended December 31,2003 compared to 2002.

 

The effect of Price risk managementactivities changed from ($35.3) million for the year ended December 31,2002 to ($16.4) million for the year ended December 31, 2003.  This change was due to the non-cash mark tomarket adjustments of our risk management activities.  This account is primarily impacted by changesin the forward price of natural gas in 2004 as compared to 2003 and the impactof those price changes on the fair value of the forward sale derivatives forour gas in storage.

 

Productpurchases increased by $299.3 million for the year ended December 31, 2003compared to 2002 as a result of the significant increase in commodityprices.  Overall, combined productpurchases as a percentage of sales of all products remained relatively constantat approximately 89% for both 2003 and 2002.

 

Plant andtransportation operating expense increased by $6.8 million for the year ended December 31,2003 compared to 2002.  The increase wasprimarily due to increased throughput at our facilities, the acquisition ofseveral gathering systems in the first quarter of 2003 and additional leasedcompression in the Powder River Basin coal bed development.  Also contributing to this increase were thefees paid to other companies, primarily Rendezvous, for gas gatheringservices.  Rendezvous is a 50% ownedentity that delivers gas to our Granger Complex.  Rendezvous is accounted for under the equitymethod, and our share of its gathering revenues is reflected in Earnings fromequity investments.

 

Oil and gasexploration and production expenses increased by $18.2 million in the yearended December 31, 2003 compared to 2002. In our operating areas, the significant increase in residue gas pricesin 2003 resulted in substantially higher severance tax expenses.   Overall, lease-operating expense, or LOE,for the year ended December 31, 2003 increased by approximately $0.04 perMcfe compared to 2002 and averaged $0.46 per Mcfe.  The increase in lease-operating expense perMcfe was primarily due to unsuccessful well expenses of $1.8 million in 2003.

 

Depreciation,depletion and amortization decreased by $3.1 million for the year ended December 31,2003 as compared to 2002.  This decreasewas the result of revisions to the operating lives, and salvage values, of ouroperating assets partially offset by increased production in the Powder RiverBasin and additional depreciation in 2003 from new projects.  The revisions to the operating lives andsalvage values of our operating assets were the result of analysis performed inconnection with the adoption of SFAS No. 143 on January 1, 2003 andwere treated as a revision of an estimate and are accounted for on aprospective basis.

 

Selling andadministrative expenses increased by approximately $4.6 million in the yearended December 31, 2003 as compared to 2002.  This increase was the result of highercompensation expenses due to an increased employee count in 2003 resulting fromour growing exploration and production operations, and a modification in 2003to our incentive compensation plan to pay this compensation on a current basisas opposed to a vesting schedule used in prior years.  Also contributing to the increase were higherprofessional fees resulting from litigation concluded in 2003 and our ongoingresearch associated with the

 

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CFTCinvestigation of our price reporting to trade publications.  Partially offsetting these increases werefewer charges for doubtful accounts in 2003 as compared to 2002.

 

In 2003, inorder to properly align our hedged volumes of natural gas to our forecastedequity production, we discontinued hedge treatment on financial instruments for10 MMcf per day of natural gas and 50,000 Barrels per month of ethane.  As a result, a pre-tax loss of $2.8 millionwas reclassified into earnings from Accumulated other comprehensive income.

 

***Cash Flow Information***

 

Cash flows from operating activities increased by $119.8million in 2003 compared to 2002. This increase was primarily due to anincrease in net income in 2003 compared to the prior year and the timing ofcash receipts and payables.

 

Cash flows used in investing activities increased by$91.3 million in 2003 compared to 2002. This increase was primarily due to a higher level of capitalexpenditures.

 

Cash flows used in financing activities increased by$7.0 million in 2003 compared to 2002. This increase was due to increased cash flows from operating activities,which was used to reduce our long-term debt.

 

***Other Information***

 

***Acquisitionand Disposition of Gathering Systems.***  Effective February 1, 2003, we acquiredseveral gathering systems in Wyoming, primarily located in the Greater GreenRiver Basin with smaller operations in the Powder River and Wind River Basins,for a total of $37.1 million.  Several ofthe systems located in the Powder River and Wind River Basins did not integratedirectly into our existing systems, and accordingly these systems were sold.  During the year ended December 31, 2003,the income, if any, generated by the assets sold was immaterial.

 

##### ***Acquisition of Sand Wash Properties.***  In August 2003,through the acquisition of the stock of a private corporation for $12.9million, we acquired additional reserves, production and acreage in thisarea.  The assets of this private entityconsisted primarily of the remaining interests in various Sand Wash propertiesthat we operate.

##### *** ***

***SegmentInformation***

* *

***GasGathering, Processing and Treating.***  The Gas Gathering, Processing and Treatingsegment realized segment-operating profit of $127.2 million for the year ended December 31,2003 as compared to $93.6 million in 2002. The increase in operating profit in this segment in 2003 was primarilydue to higher commodity prices, increased gathering volumes and the acquisitionof several gathering systems in February 2003.

 

***Explorationand Production.*** The Exploration and Production segment realized segment-operating profitof $114.2 million for the year ended December 31, 2003 compared to $74.1million in 2002. The increase in operating profit in this segment in 2003 wasprimarily due to substantially higher natural gas prices and production volumegrowth from the Powder River Basin CBM area and the Pinedale Anticline.

 

***Marketing.***  The Marketing segment realizedsegment-operating profit of $36.4million for the year ended December 31, 2003 compared to $10.5million in 2002.  The increase in the marketing margin is primarily due to transactionsassociated with our firm transportation capacity from the Rocky Mountain regionto the Mid-Continent.  Our firmtransportation allows us to purchase gas in the Rocky Mountain region forresale in the higher priced Mid-Continent markets.  In the second quarter of 2003, additionaltransportation capacity out of the Rocky Mountain region became operational,which reduced the price difference between the two regions.  There is no assurance that the margins werealized on the sale of gas in 2003 will continue in the future, or that wewill continue to originate the same amount of transactions in futureyears.  Also contributing to the increasein marketing segment-operating profit was non-cash mark-to-market gains fromour price risk management activities of future sales of gas utilizing ourstorage and transportation capacity.  As the stored or transported natural gas issold and the future sale derivatives are settled, the Company will realize thebenefit of the storage and transportation transactions through earnings in thatperiod.

 

***Transportation.***  The Transportation segment realizedsegment-operating profit of $11.6 million for the year ended December 31,2003 compared to $16.3 million in 2002. The transportation segment includes the results from the MIGC and

 

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MGTC pipelines in the PowderRiver Basin.  The decrease in profit inthis segment was due to lower interruptible transportation volume in 2003 asmore gas was transported out the basin through other pipelines.

 

#### ***Critical AccountingEstimates***

#### *** ***

The application of accounting policies is animportant process that has developed as our business activities have evolvedand as accounting rules have developed.  Accounting rules generally do not involve a selection among alternatives,but involve an interpretation and implementation of existing rules, and the useof judgment, to the specific set of circumstances existing in ourbusiness.  We make every effort toproperly comply with all applicable rules on or before their adoption, andwe believe the proper implementation and consistent application of theaccounting rules is critical.  For furtherdetails on our accounting policies, and the estimates, assumptions andjudgments we use in applying these policies and a discussion of new accountingrules, see Note 3 of the Notes to Consolidated Financial Statements.

 

***Use of Estimates. ***Thepreparation of consolidated financial statements in conformity with generallyaccepted accounting principles requires us to make estimates and assumptionsthat affect the amounts reported for assets and liabilities, the disclosure ofcontingent assets and liabilities at the date of the financial statements, andthe amounts reported for revenues and expenses during the reporting period.  These estimates are evaluated on an ongoingbasis, utilizing historical experience, consultation with experts and othermethods considered reasonable in the particular circumstances.  However, actual results may differ significantlyfrom the estimates used.  Any effects onour business, financial position or results of operations resulting fromrevisions to these estimates will be recorded in the period in which the factsthat necessitate a revision become known. Although there are a number of areas where we use estimates, what webelieve to be the most significant ones are discussed below.

 

***Property and Equipment. *** Depreciation on our property and equipment isprovided using the straight-line method based on the estimated useful life ofeach facility, which ranges from three to 35 years.  Useful lives are determined based on theshorter of our estimate of the life of the equipment or our estimate of thereserves serviced by the equipment.  Amongother factors, the estimates consider our experience with similar assets andtechnical analysis of the reserves.  Thecost of acquired gas purchase contracts is amortized using the straight-linemethod or units of production.  If theactual lives of the equipment or the reserves serviced by the equipment wereless than we originally estimated, we may be required to record a loss uponretirement of a specific asset.

 

***Oil and Gas Reserves, Propertiesand Equipment. *** We follow the successful efforts method ofaccounting for oil and gas exploration and production activities.  Developed and undeveloped leaseholds withproved reserves are depleted by the units-of-production method based onestimated proved reserves.  Developmentcosts and related equipment are depleted and depreciated by the units-of-productionmethod based on estimated proved developed reserves.  The units of production method is sensitiveto the determination of proved reserves. To the extent the reserves are modified, the depletion determined underthe units of production method will be increased or decreased on a prospectivebasis.

 

Our reserve estimates are subject to numerousuncertainties inherent in the estimation of quantities of proved reserves, theprojection of future rates of production and the timing of developmentexpenditures.  The accuracy of these estimatesis a function of the quality of available data and of engineering andgeological interpretation and judgment. Reserve estimates are imprecise andshould be expected to change as additional information becomes available.  Estimates of economically recoverablereserves and of future net cash flows prepared by different engineers or by thesame engineers at different times may vary substantially.  Results of subsequent drilling, testing andproduction may cause either upward or downward revisions of previousestimates.  Overall, during 2004, 2003and 2002, we experienced downward revisions. In addition, the estimates of future net revenues from our provedreserves and the present value of those reserves are based upon certainassumptions about production levels, prices and costs, which may not becorrect.  Further, the volumes consideredto be commercially recoverable fluctuate with changes in prices and operatingcosts. The meaningfulness of such estimates is highly dependent upon theaccuracy of the assumptions upon which they were based. Actual results maydiffer materially from the results estimated. We estimate that a 5% change inour reserves either upward or downward would decrease or increase,respectively, our depreciation and depletion on our oil and gas assets byapproximately $2.3 million.

 

***AssetRetirement Obligations.***  We use significant judgment in estimating ourfuture liability for asset retirement. We evaluate each asset and in some cases individual components of assetsto determine and estimate the future cost and timing of retiring thoseassets.  The estimate of the future costis then discounted back to the present and recorded as a liability.  This liability will vary based upon theprobability, timing and the extent of remediation necessary to reclaim thosefacilities, the

 

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discount factor used in thosedeterminations and the projected costs of the remediation.  We evaluate these estimates on an ongoingbasis and modify our assumptions as appropriate.

 

***Impairment of Long-Lived Assets.*** If changes in the expected performance of anasset occur, or if overall economic conditions warrant, we will review ourassets to determine their economic viability. In accordance with SFAS No. 144 *“Accountingfor the Impairment or Disposal of Long-Lived Assets”*, assets are tobe evaluated at the lowest level for which identifiable cash flows are largelyindependent of the cash flows of other assets.  Accordingly, our review is completed at the plant facility, the relatedgroup of plant facilities or the oil and gas producing field or producing coalseam level.  In order to determinewhether an impairment exists, we compare the net book value of the asset to theestimated fair market value or the undiscounted expected future net cash flows,determined by applying future prices estimated by management over the shorterof the lives of the facilities or the associated reserves.  If an impairment exists, write-downs ofassets are based upon expected future net cash flows discounted using aninterest rate commensurate with the risk associated with the underlyingasset.  This analysis is sensitive to,among other things; management’s expectation of commodity prices, operatingcosts, drilling plans, production rates and the evaluation in determining assetgroupings for which cash flows are largely independent of the cash flows ofother assets.  During 2004, 2003 and2002, we had no impairments of long-lived assets.

 

***Identificationof Derivatives and Mark-to-Market Valuations****. *Managementdetermines whether or not their contracts qualify as derivatives and uses theirjudgment to determine their value.  Thisanalysis is dependent upon commodity prices, outside market factors andmanagement’s intent upon entering into these contracts.  An analysis of the impact of the change inmarket prices on the value of our derivatives is included in “Item 7A.Quantitative and Qualitative Disclosures on Market Risk.”

 

Historically, the non-cashmark-to-market valuation of the gas storage and transportation contracts whichwere considered to be derivatives effectively offset non-cash mark-to-marketchanges to the forward derivative contract to sell our stored or transportednatural gas. After the adjustments to correct the prior accounting for thesecontracts as derivatives, the non-cash mark-to-market of the future salederivative contract on the sale of gas will fluctuate through earnings withchanges in market prices and will not be offset by a corresponding mark tomarket on the gas storage and transportation contracts. As the stored ortransported natural gas is sold and the forward sale derivatives are settled,we will realize the benefit of the storage and transportation transactionsthrough earnings. At December 31, 2004, we held gas in our contractedstorage facilities and in imbalances of approximately 16.3 Bcf. Thisinventoried gas was sold forward with derivatives. Based on a $1.00 increase inthe forward price of gas in the anticipated month of withdrawal, the change inthe non-cash mark-to-market value of these derivatives will reduce pre-taxearnings by $16.3 million and a $1.00 decrease in the forward price of gas inthe anticipated month of withdrawal will increase pre-tax earnings by $16.3million. As the stored or transported natural gas is sold and the future salederivatives are settled, we will realize the benefit of the storage andtransportation transactions through earnings.

 

***RecentlyIssued Accounting Pronouncements.***  We continually monitor and revise our accountingpolicies as new rules are issued. At this time, there are several new accounting pronouncements that haverecently been issued, but not yet adopted, which will have an impact on ouraccounting when they become effective in 2005. The following pronouncements have been issued but not yet adopted.

 

**SFAS No. 123(R).**   SFAS No. 123(R), “ShareBased Payment” was issued in December 2004 and must be adopted no laterthan periods beginning after June 15, 2005. This pronouncement requirescompanies to expense the fair value of employee stock options and other formsof stock based compensation. We intend to adopt this pronouncement in the thirdquarter of 2005. Currently, we are complying with the pro forma disclosurerequirements of SFAS No. 123, “Accounting for Stock Based Compensation”which are included in Note 2 – Summary of Significant Accounting Policies toConsolidated Financial Statements. We estimate that if we had adopted SFAS No. 123(R)for the year ended December 31, 2004, Earnings per share of common stock -assuming dilution would have been approximately $1.66 per share of common stockor a reduction of approximately $0.07 per share of common stock from the actualresults for 2004.

 

**SFAS No. 151.**   SFAS No. 151, “*Inventory Costs, an amendment of ARB No. 43,Chapter 4”*was issued in November 2004 and is effective for usfor inventory costs incurred in fiscal years beginning after June 15,2005, and will be applied prospectively. SFAS No. 151 amends APB Opinion No. 43, Chapter 4, “InventoryPricing” to clarify the accounting for abnormal amounts of costs and theallocation of fixed production overheads. We believe that the adoption of SFAS No. 153 will not affect ourearnings, financial position or cash flows.

 

**SFAS No. 153.**   SFAS No. 153, “*Exchanges of Nonmonetary Assets, an amendment of APBOpinion No. 29”*was issued in December 2004 and iseffective for us for nonmonetary asset exchanges occurring in fiscal periodsbeginning after June 15,

 

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2005, and will be applied prospectively.  SFAS No. 153 amends APB Opinion No. 29,“*Accounting for Nonmonetary Transactions”*.  The guidance in APB Opinion No. 29 isbased on the principle that exchanges of nonmonetary assets should be measuredbased on the fair value of the assets exchanged but includes certain exceptionsto that principle.  SFAS No. 153amends APB Opinion No. 29 to eliminate the exception for nonmonetaryexchanges of similar productive assets and replaces it with a general exceptionfor exchanges of nonmonetary assets that do not have commercial substance.  A nonmonetary exchange has commercialsubstance if the future cash flows of the entity are expected to changesignificantly as a result of the exchange. We will adopt SFAS No. 153 as required.

 

**EITF No. 04-13.  **At its November 2004meeting, the Emerging Issues Task Force of the FASB began discussion of Issue No.04-13, “Accounting for Purchases and Sales of Inventory with the SameCounterparty.”  This Issue addresses thequestion of when it is appropriate to measure purchases and sales of inventoryat fair value and record them in cost of sales and revenues and when theyshould be recorded as an exchange measured at the book value of the item sold.The EITF did not reach a consensus on this issue, but requested the FASB staffto further explore the alternative views. We record natural gas, and NGL purchases and sales of inventory enteredinto contemporaneously with the same counterparty as cost of sales andrevenues.  These transactions occur undercontractual arrangements that establish the agreement terms either jointly, ina single contract, or separately, in individual contracts.   Should the EITF reach a consensus on thisissue requiring these transactions to be recorded as exchanges measured at bookvalue, Total revenues and Product purchases on the Consolidated Statement ofOperations would be lower by equal amounts with no impact on net income. Wehave not yet determined the amount of any adjustment to Total revenues andProduct purchases under the EITF.

 

**FSP FAS 19-a.**  In February 2005, the FASB Staff postedits proposed staff position FSP FAS 19-a, “Accounting for Suspended WellCosts.” At issue is the current requirement of SFAS 19, “FinancialAccounting and Reporting by Oil and Gas Producing Companies,” to capitalize thecosts of drilling exploratory wells pending determination of whether the wellhas found proved reserves. The capitalized costs become part of the entity’swells, equipment, and facilities if the well successfully located provedreserves. However, if the well has not found proved reserves, the capitalizedcosts of drilling the well are expensed, net of any salvage value. Questionshave arisen as to whether there are circumstances that would permit thecontinued capitalization of exploratory-well costs beyond the one-year limitspecified in SFAS 19 other than when additional exploration wells arenecessary to justify major capital expenditures and those wells are underway orfirmly planned for the near future. In its proposal, the FASB Staff states thatexploratory well costs could be capitalized beyond a one-year limit if the wellhas found a sufficient quantity of reserves to justify its completion as aproducing well and the entity is making progress assessing reserves and theeconomic and operational viability of the project. Comments on the proposedFASB Staff position were due March 7, 2005. This FSP will be effective inthe first quarter after it is approved. We do not believe that this FSP will have a material impact on ourresults of operations, financial position or cash flows

 

**American Jobs Creation Act of2004. **During October 2004, H.R. 4520, the “AmericanJobs Creation Act of 2004,” (the “Act”) was enacted. It provides for certainadditional tax deductions from qualified taxable income beginning in 2005,subject to certain limitations. Although we expect that the Act may result in areduction in our effective tax rate, we have not yet determined the full impactof this law.

 

#### ***Liquidity and Capital Resources***

#### *** ***

Our sources of liquidity and capital resourceshistorically have been net cash provided by operating activities, fundsavailable under our financing facilities and proceeds from offerings of debtand equity securities.  In the past,these sources have been sufficient to meet our needs and finance the growth ofour business.  We can give no assurancethat the historical sources of liquidity and capital resources will beavailable for future development and acquisition projects, and we may berequired to seek additional or alternative financing sources.  Product prices, hedges of equity production,sales of inventory, the volume of natural gas processed by our facilities, thevolume of natural gas produced from our producing properties, the margin onthird-party product purchased for resale, as well as the timely collection ofour receivables are all expected to have significant influences on our futurenet cash provided by operating activities. Additionally, our future growth will be dependent upon obtaining additionsto dedicated plant reserves, acquisitions, new project development, marketingresults, efficient operation of our facilities and our ability to obtainfinancing at favorable terms.

 

During the past several years, we have beensuccessful in developing additional reserves of natural gas and increasing ourequity natural gas production.  However,the overall level of drilling and production associated with our producingproperties will depend upon, among other factors, the price for gas,availability of transportation capacity to market centers, the energy andenvironmental policy and regulation by governmental agencies, the issuance ofdrilling and water disposal permits, and the length of time for wells in thePowder River Basin to be dewatered, none of which is within our control.  Any reduction in the

 

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levels of exploration,development and production by us or a significant reduction in natural gasprices could have a material adverse effect on our financial condition, resultsof operations and cash flows.

 

Although some of our plants have experiencednatural declines in dedicated reserves, overall we have been successful inconnecting additional reserves to more than offset these declines.  However, the overall level of drillingassociated with our plant facilities will depend upon, among other factors, theprices for oil and gas, the drilling budgets of third-party producers,availability of transportation capacity to market centers, the energy and environmentalpolicy and regulation by governmental agencies, the pace at which drillingpermits are received, and the availability of foreign oil and gas, none ofwhich is within our control. There is no assurance that we will continue to besuccessful in replacing the dedicated reserves processed at ourfacilities.  Any prolonged reduction inprices for natural gas and NGLs may depress the levels of exploration,development and production by third-parties. Lower levels of these activities could result in a corresponding declinein the demand for our gathering, processing and treating services.  A reduction in any of these activities couldhave a material adverse effect on our financial condition, results of operationsand cash flows.

 

We believe that the amounts available to beborrowed under our financing facilities, together with net cash provided byoperating activities, will provide us with sufficient funds to connect newreserves, maintain our existing facilities and complete our current capital expenditureprogram.  Depending on the timing and theamount of our future projects, we may be required to seek additional sources ofcapital.  Our ability to secure suchcapital is restricted by our financing facilities, although we may requestadditional borrowing capacity from our lenders, seek waivers from our lendersto permit us to borrow funds from third-parties, seek replacement financingfacilities from other lenders, use stock as a currency for acquisitions, sellexisting assets or use a combination of alternatives.  While we believe that we would be able tosecure additional financing, if required, we can provide no assurance that wewill be able to do so or as to the terms of any additional financing.

 

We utilized amounts available under therevolving credit facility together with an additional $100.0 million borrowingunder the master shelf agreement to redeem our $155.0 million, 10% seniorsubordinated notes in June 2004, to pay a $7.8 million prepayment penaltyon this redemption, and to meet scheduled principal repayments during 2004 of$35.0 million under the master shelf agreement. We believe that amounts available under the revolving credit facilitywill be sufficient to meet scheduled principal repayments during 2005 of $10.0million under the master shelf agreement.

 

***Sourcesand Uses of Funds*.** Our sources and uses of funds for the year ended December 31, 2004are summarized as follows (dollars in thousands):

 
| **Sources of funds:**                                            |   |    |      |
|------------------------------------------------------------------|--------|---------|-----------|
| Borrowings under the revolving credit  facility                  |   | $       | 2,654,230 |   |
| Borrowings under the master shelf agreement                      |   | 100,000 |      |
| Proceeds from the dispositions of property  and equipment        |   | 1,501   |      |
| Net cash provided by operating activities                        |   | 209,159 |      |
| Change in balance of outstanding checks                          |   | 31,581  |      |
| Distributions from equity investments                            |   | 2,310   |      |
| Proceeds from exercise of common stock  options                  |   | 9,993   |      |
| Total sources of funds                                           |   | $       | 3,008,774 |   |
| **Uses of  funds:**                                              |   |    |      |
| Payments related to long-term debt  (including debt issue costs) |   | $       | 2,713,316 |   |
| Capital expenditures                                             |   | 306,266 |      |
| Redemption of $2.625 cumulative convertible  preferred stock     |   | 1,930   |      |
| Preferred dividends paid                                         |   | 757     |      |
| Common dividends paid                                            |   | 12,231  |      |
| Total uses of funds                                              |   | $       | 3,034,500 |   |

 

***CapitalInvestment Program.***  We currently anticipate capital expendituresin 2005 of approximately $338.8 million.  The 2005 capital budget is an 11% increase over the amount expended in2004.  This increase is the result of anexpected increase in drilling activity in each of our upstream areas andadditional drilling activity by third party producers whose acreage is

 

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dedicated to our midstreamfacilities.  Overall, capitalexpenditures in the Powder River Basin CBM development and in the Greater GreenRiver Basin operations represent 38% and 34%, respectively, of the total 2005budget.  Due to drilling and regulatoryuncertainties that are beyond our control, we can make no assurance that ourcapital budget for 2005 will not change or that we will actually incur thislevel of capital expenditures.  Thisbudget may be increased to provide for acquisitions if approved by our board ofdirectors.

 

The 2005 capital budget and our capitalexpenditures during the year ended December 31, 2004 are presented in thefollowing table (dollars in thousands). 

 
| **Type of Capital Expenditure**                              | ** ** | **2005 Capital  Budget** | ** ** | **Capital Expenditures  During the Year  Ended  December 31, 2004** | ** ** |
|--------------------------------------------------------------|------------|--------------------------|------------|--------------------------------------------------------------------------|------------|
| Gathering,  processing, treating and pipeline assets         |       | $                        | 112.8      | *                                                                        | $          | 83.0 | * |
| Exploration  and production and lease acquisition activities |       | 186.7                    |       | 132.7                                                                    |       |
| Acquisition  of San Juan Basin oil and gas properties        |       | —                   |       | 82.2                                                                     |       |
| Acquisition  of Greater Green River Basin midstream assets   |       | 28.0                     |       | —                                                                   |       |
| Information  technology and other items                      |       | 3.0                      |       | 2.3                                                                      |       |
| Capitalized  interest and overhead                           |       | 8.3                      |       | 6.4                                                                      |       |
| Total Capital Expenditures                                   |       | $                        | 338.8      |                                                                     | $          | 306.6 |   |

 

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* Includes $13.7 million budgeted in 2005 and $9.0 million expended in2004 for maintaining existing facilities.

 

***Contractual Commitments and Obligations***

 

##### ***Contractual Cash Obligations. ***Asummary of our contractual cash obligations as of December 31, 2004 is asfollows (dollars in thousands):

 
| ** **                                 | ** ** | ** **             | ** ** |
|--------------------------------------------|------------|------------------------|------------|
| ** **                                 | ** ** | ** **             | ** ** | **Payments by Period** | ** ** |
| **Type of Obligation**                     | ** ** | **Total  Obligations** | ** ** | **Due in  2005** | ** ** | **Due in  2006 – 2007** | ** ** | **Due in  2008 – 2009** | ** ** | **Due  Thereafter** | ** ** |
| Guarantee of  Fort Union Project Financing |       | $                      | 4,743      |   | $ | 866 |   | $ | 1,931 |   | $ | 1,946 |   | $ | — |   |
| Operating  Leases                          |       | 82,321                 |       | 16,607 |   | 31,978 |   | 23,472 |   | 10,264 |   |
| Firm  Transportation Capacity Agreements   |       | 251,223                |       | 38,883 |   | 72,130 |   | 59,281 |   | 80,929 |   |
| Firm Storage  Capacity Agreements          |       | 29,091                 |       | 7,044 |   | 8,311 |   | 4,815 |   | 8,921 |   |
| Long-term  Debt                            |       | 382,000                |       | 35,000 |   | 20,000 |   | 227,000 |   | 100,000 |   |
| Interest on  Long-Term Debt *              |       | 80,679                 |       | 16,504 |   | 30,577 |   | 24,743 |   | 8,856 |   |
| Total  Contractual Cash Obligations        |       | $                      | 830,057    |   | $ | 114,904 |   | $ | 164,927 |   | $ | 341,257 |   | $ | 208,970 |   |
|                                            |            |                        |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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*  The interest rate assumed onthe revolving credit facility is the rate at December 31, 2004 of 3.8%.

 

***Guaranteeof Fort Union Project Financing.***   We own a 13% equity interest in Fort UnionGas Gathering, L.L.C., or Fort Union, and are the construction manager andfield operator.  Fort Union gathers andtreats natural gas in the Powder River Basin in northeast Wyoming.  Initial construction and any expansions of thegathering header and treating system have been project financed by Fort Union.  This debt is amortizing on an annual basisand is scheduled to be fully paid in 2009.  Our requirement to fund under this guarantee would be reduced by thevalue of assets held by Fort Union.  Thisguarantee is not reflected on our Consolidated Balance Sheet.

 

***OperatingLeases. ****  *Inthe ordinary course of our business operations, we enter into operating leasesfor office space, and for office, communication, transportation and compressionequipment.  Payments made on these leasesare a component of operating expenses and are reflected on the ConsolidatedStatement of Operations and, as operating leases, are not reflected on ourConsolidated Balance Sheet.  These leaseshave terms ranging from one month to ten years and the majority of the leaseshave return or fair market purchase options available at various times duringthe lease.   If we were to exercise thepurchase options on all the leased compression equipment, these purchaseoptions would require the capital expenditure of approximately $41.5 millionbetween 2007 and 2013.

 

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***Firm Transportation Capacityand Gathering Agreements.***  Accessto firm transportation is also a significant element of our businessstrategy.  Firm transportation ensures thatour equity production has access to downstream markets and allows us to captureincremental profit when pricing differentials between physical locationsoccur.    Firm transportation agreementsgenerally require the payment of fixed monthly fees regardless of the quantityof gas that flows under a particular agreement. These agreements are not reflected on our Consolidated Balance Sheet.

 

The fixed fees associated with our existingcontracts for firm transportation capacity during 2005 will average approximately$0.16 per Mcf.  The associated contractperiods range from one month to thirteen years. Under firm transportation contracts, we are required to pay the feesassociated with these contracts whether or not the transportation is used.

 

***Firm Storage CapacityAgreements*.**  We customarily store gas in undergroundstorage facilities to ensure an adequate supply for long-term sales contractsand to capture seasonal price differentials. As of December 31, 2004, we had contracts in place forapproximately 17.1 Bcf of storage capacity at various third-partyfacilities.  Firm storageagreements generally require the payment of fixed monthly fees regardless ofthe quantity of gas that is in storage under a particular agreement.  Of the total storage capacity under contract,approximately 6.5 Bcf is under contract to our Canadian subsidiary, WGR Canada, Inc.,and Western guarantees the subsidiary’s performance under these contracts.  This subsidiary is wholly owned by us andfully consolidated in our financial statements.

 

The fees associated withthese contracts in 2005 will average $0.56 per Mcf of annual capacity. Theassociated contract periods at December 31, 2004 had an average term of 34months. At December 31, 2004, we held gas in our contracted storage facilitiesand in imbalances of approximately 16.3 Bcf at an average cost of $5.61 per Mcfcompared to 12.7 Bcf at an average cost of $4.64 per Mcf at December 31,2003. These positions are for storage withdrawals within the next 15 months. Atthe time we place product into storage, we contract for the sale of thatproduct, physically or financially, and do not speculate on the future value ofthe product. These agreements for storage capacity are not reflected on ourConsolidated Balance Sheet.

 

From time to time, we lease NGL storage spaceat major trading locations to facilitate the distribution of products. At December 31,2004, we held NGLs in storage at various third-party facilities of 2,745 MGal,consisting primarily of propane and ethane, at an average cost of $0.30 pergallon compared to 2,989 MGal at an average cost of $0.30 per gallon at December 31,2003.

 

#### ***Long-termDebt***

#### *** ***

***Revolving Credit Facility. ***Therevolving credit facility matures in June 2009.   In December 2004, the size of thecommitment under the revolver was increased from $400 million to $500million.  At January 31,2005, $199.0 million was outstanding under this facility.   Loans made under this facility are securedby a pledge of the capital stock of our significant subsidiaries.  These subsidiaries also guarantee theborrowings under the facility.

 

The borrowings under the creditfacility bear interest at Eurodollar rates or a base rate, as requested by us,plus an applicable percentage based on our debt to capitalization ratio.  The base rate is the agent’s published primerate.  We also pay a quarterly commitmentfee ranging between 0.20% and 0.375%, depending on our debt to capitalizationratio.  This fee is paid on unused amountsof the commitment.  At December 31,2004, the interest rate payable on borrowings under this facility wasapproximately 3.8%.  Under the creditfacility, we are subject to a number of covenants, including: maintaining atotal debt to capitalization ratio of not more than 55% and maintaining a ratioof EBITDA, as defined in the credit facility, to interest over the last fourquarters in excess of 3.0 to 1.0.  Thecredit facility ranks equally with borrowings under our master shelf agreementwith The Prudential Insurance Company. This facility has been rated Ba1 by Moody’s and is not yet rated byS&P.

 

***Master Shelf Agreement. ***Amountsoutstanding under the master shelf agreement at January 31, 2005 are asindicated in the following table (dollars in thousands): 

 
| **Issue Date**         | ** ** | **Amount** | ** ** | **Interest Rate** | ** ** | **Final Maturity**     | ** **          | **Principal Repayment Schedule** | ** **                                          |
|------------------------|------------|------------|------------|-------------------|------------|------------------------|---------------------|----------------------------------|-----------------------------------------------------|
| July 28,  1995    |       | $          | 30,000     |              | 7.61       | %                      | July 28,  2007 |                             | $10,000 on  each of July 28, 2005 through 2007 |   |
| June 30,  2004    |       | 100,000    |       | 5.92              | %          | June 30,  2011    |                | Single  payment at maturity      |                                                |
| January 18,  2005 |       | 25,000     |       | 5.57              | %          | January 18,  2015 |                | Single  payment at maturity      |                                                |
| Total                  |       | $          | 155,000    |              |       |                   |                |                             |                                                |   |
|                        |            |            |            |                   |            |                        |                     |                                  |                                                     |  |  |

 

Our borrowings under the master shelfagreement are secured by a pledge of the capital stock of our significantsubsidiaries.  

 

35

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These subsidiaries also guaranty the borrowings under thefacility.  All of the borrowings underthe master shelf agreement can be prepaid prior to their final maturity bypaying a yield-maintenance fee.   Underour master shelf agreement, we are subject to a number of covenants, including:maintaining a total debt to capitalization ratio of not more than 55% andmaintaining a quarterly test of EBITDA, as defined in the master shelfagreement, to interest for the last four quarters in excess of 3.0 to 1.0.

 

In December 2004, we gave noticeto Prudential of our intention to prepay the $25 million note due January 17,2008.  This note bore interest at 6.36%per annum and was prepaid at par on January 18, 2005.  To fund the prepayment, we issued a new $25million note to Prudential, due January 2015 and bearing interest at 5.57%per annum.  During 2005, we will makescheduled payments totaling $10.0 million on this facility.  We intend to fund these repayments with fundsavailable under the revolving credit facility.

 

***Senior Subordinated Notes. ***In 1999, we sold$155.0 million of senior subordinated notes in a private placement with a finalmaturity of 2009 due in a single payment which were subsequently exchanged forregistered publicly tradable notes under the same terms and conditions.  The subordinated notes bore interest at 10%per annum.  We incurred approximately$5.0 million in offering commissions and expenses, which were capitalized andwere being amortized over the term of the notes.  We redeemed the senior subordinated notes in June 2004using amounts available under the revolving credit facility and an additionalborrowing under the master shelf agreement. In connection with this redemption, we paid a prepayment penalty of$7.75 million and expensed approximately $2.9 million of unamortized offeringcommissions and expenses.

 

***Covenant Compliance. ***We were incompliance with all financial covenants in our debt agreements at December 31,2004.

 

#### ***Environmental***

#### *** ***

The construction and operation of ourgathering systems, plants and other facilities used for the gathering,processing, treating or transporting of gas and NGLs are subject to federal,state and local environmental laws and regulations, including those that canimpose obligations to clean up hazardous substances at our facilities or atfacilities to which we send wastes for disposal. In most instances, theapplicable regulatory requirements relate to water and air pollution control orwaste management. We employ specialists in environmental engineering, safetyand regulatory compliance to monitor environmental and safety compliance at ourfacilities.  In addition, ourenvironmental engineers and safety specialists perform in-house audits of ourexisting facilities to ensure on-going compliance.  Similarly, prior to consummating any majoracquisition, our environmental engineers perform audits on the facilities to beacquired.  We believe that we are insubstantial compliance with applicable material environmental laws andregulations. Environmental regulation can increase the cost of planning,designing, constructing and operating our facilities.  We anticipate that the trend in environmentallegislation and regulation will continue to be toward stricter standards.  The costs for compliance with current environmentallaws and regulations have not had and, we believe, will not have a materialadverse effect on our financial position or results of operations.  We however cannot predict the extent ortiming of future regulations or legislation and whether any such regulations orlegislation will have a material adverse effect on the financial results of ouroperations, financial position or cash flows.

 

Prior to consummating any major acquisition,our environmental engineers perform audits on the facilities to be acquired. Inconducting this audit on the acquisition of the gathering and processingfacilities acquired in February 2005, we performed phase one environmentalassessments and, where conditions indicated, performed phase twoassessments.  These assessments enabledus to satisfy ourselves that the disclosures by the seller were materiallyaccurate and also to form our own risk assessment of potential environmentalissues.  In relation to the assetspurchased in the February 2005 acquisition, one of the sites was thesubject of an Administrative Order between the former owner, the State ofWyoming and a third party who has contracted to remediate the site inaccordance with the Administrative Order. As a result of the acquisition, we also became a party to theAdministrative Order.  Both that site andanother site are insured under an insurance policy that was put in place by theseller for the costs of all remediation activities.  The obligation to perform and complete thoseremediation activities has been assigned contractually to a third partyenvironmental specialist whose costs will be reimbursed by the insurancepolicy.

 

We are in the process of voluntarily cleaning upsubstances at several of the facilities that we operate. Our expenditures forenvironmental evaluation and remediation at existing facilities have not beensignificant in relation to our results of operations and totaled approximately$2.1 million for the year ended December 31, 2004.  In 2004, we also paid approximately $467,000in air emissions fees to the states in which we operate.

 

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***Cautionary StatementRegarding Forward-Looking Information.***

 

The Private Securities Litigation Reform Actof 1995 (“the Act”) provides a safe harbor for forward-looking information madeon our behalf.  All statements, otherthan statements of historical facts, which address activities or actions thatwe expect or anticipate will or may occur in the future, and growth of ouroperations and other such matters are forward-looking terminology, such as “may,”“intend,” “will,” “should,” “expect,” “anticipate,” “estimate,” “plan,” “predict”or “continue” or comparable terminology.

 

This Annual Report contains forward-lookingstatements relating to, without limitation, our future economic performance,plans and objectives for future operations and forecasts of revenue and otherfinancial items.  Forward-lookingstatements made by us are based on our knowledge of our business and theenvironment in which we operate, but any one, or a combination, of factorscould cause actual results to differ materially from our projections in theAnnual Report.  These factors, set forthherein and in our other documents on file with the SEC, include our ability toexpand our gathering operations, completion our budgeted capital expenditures,the success of our drilling activities, our ability to respond to competitivepressures, the composition of gas to be treated and the drilling schedules andsuccess of producers with acreage dedicated to our facilities, the condition ofthe capital markets, uncertainties associated with ongoing and futurelitigation and legal and regulatory programs (including those described underItems 1 and 3 of our Annual Report on Form 10-K/A, in our quarterlyreports on Form 10-Q and any amendments thereto and in our current reportson Form 8-K) and numerous other factors affecting our business generallyand in the markets for gas and NGLs in which we participate.  The forward-looking statements speak only as tothe date when they are made.  We assumeno obligation to update and supplement forward-looking statements that becomeuntrue because of subsequent events.

 

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** **

**ITEM 7A.   QUANTITATIVEAND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

 

Our commodity price risk management programhas two primary objectives.  The firstgoal is to preserve and enhance the value of our equity volumes of gas and NGLswith regard to the impact of commodity price movements on cash flow and netincome in relation to those anticipated by our operating budget.  The second goal is to manage price riskrelated to our marketing activities to protect profit margins.  This risk relates to fixed price purchase andsale commitments, the value of storage inventories and exposure to physicalmarket price volatility.

 

We utilize a combination of fixed priceforward contracts, exchange-traded futures and options, as well as fixed indexswaps, basis swaps and options traded in the over-the-counter, or OTC, marketto accomplish these goals.  Theseinstruments allow us to preserve value and protect margins becausecorresponding losses or gains in the value of the financial instruments offsetgains or losses in the physical market.

 

We also use financial instruments to reducebasis risk.  Basis is the difference inprice between the physical commodity being hedged and the price of the futurescontract used for hedging.  Basis risk isthe risk that an adverse change in the futures market will not be completelyoffset by an equal and opposite change in the cash price of the commodity beinghedged.  Basis risk exists in natural gasprimarily due to the geographic price differentials between cash marketlocations and futures contract delivery locations.

 

We enter into futures transactions on the NewYork Mercantile Exchange, or NYMEX, and OTC swaps and options with variouscounterparties, consisting primarily of investment banks, financialinstitutions and other natural gas companies. We conduct credit reviews of all of our OTC counterparties and haveagreements with many of these parties that contain collateralrequirements.  We generally usestandardized swap agreements that allow for offset of positive and negative OTCexposures with the same counterparty.  OTCexposure is marked-to-market daily for the credit review process.  Our exposure to OTC credit risk is reduced byour ability to require a margin deposit from our counterparties based upon themark-to-market value of their net exposure. We are also subject to margin deposit requirements under these sameagreements and under margin deposit requirements for our NYMEXtransactions.  At December 31, 2004,we had $3.0 million of margin deposits outstanding.

 

We continually monitor and review the creditexposure to our marketing counterparties. In recent months the prices of natural gas and NGLs, and therefore ourcredit exposures, have increased significantly. In order to minimize our credit exposures, we have utilized existingnetting agreements to reduce our net credit exposure, established new nettingagreements with additional customers, terminated several long-term marketingobligations, negotiated accelerated payment terms with several customers, andincreased the amount of credit which we make available to substantial companieswhich meet our credit requirements. Although netting agreements similar to those that we utilize have beenupheld by bankruptcy courts in the past, if any of the customers with whom wehave netting agreements were to file for bankruptcy, we can provide noassurance that our agreements will not be challenged or as to the outcome ofany challenge.

 

The use of financial instruments may exposeus to the risk of financial loss in some circumstances, including instanceswhen (i) our equity volumes are less than expected, (ii) ourcustomers fail to purchase or deliver the contracted quantities of natural gasor NGLs, or (iii) our OTC counterparties fail to perform.  To the extent that we engage in hedgingactivities, we may be prevented from realizing the benefits of favorable pricechanges in the physical market.  However,we are similarly insulated against decreases in these prices.

 

We enter into derivatives for the future sale orpurchase of natural gas to use our storage and transportation capacity.  These transactions utilizing our capacity areeconomic hedges, but are not afforded hedge accounting hedge treatment.  Therefore, the non-cash mark-to-market of theseeconomic hedges will fluctuate through earnings with changes in market prices.As the stored or transported natural gas is sold and the future salederivatives are settled, we will realize the benefit of the storage andtransportation transactions through earnings.

 

***RiskPolicy and Control.**** *We control theextent of risk management and marketing activities through policies andprocedures that involve the senior level of management.  On a daily basis, our marketing activitiesare audited and monitored by our independent risk oversight department, orIRO.  This department reports to theChief Financial Officer, thereby providing a separation of duties from themarketing department.  Additionally, theIRO reports monthly to the Risk Management Committee, or RMC.  This committee is comprised of corporatemanagers and officers and is responsible for developing the policies andguidelines that control the management and measurement of risk, subject to theapproval of the board of directors. The RMC is also responsible for settingrisk limits including value-at-risk and dollar stop loss limits, subject to theapproval of the board of directors.

 

38

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***Hedge Positions.* **As of January 31, 2005, we havehedged approximately 49% of our projected 2005 equity natural gas volumes andapproximately 51% of our projected 2005 equity production of crude oil,condensate, and NGLs.  All thesecontracts are designated and accounted for as cash flow hedges.  As such, gains and losses related to theeffective portions of the changes in the fair value of the derivatives arerecorded in Accumulated other comprehensive income, a component of Stockholders’equity.  Realized gains or losses onthese cash flow hedges are recognized in the Consolidated Statement ofOperations through Sale of gas or Sale of natural gas liquids when the hedgedtransactions occur.

 

To qualify as cash flow hedges, the hedgeinstruments must be designated as cash flow hedges and changes in their fairvalue must be highly effective at offsetting changes in the price of theforecasted transaction being hedged so that our exposure to the risk ofcommodity price changes is reduced.  Tomeet this requirement, we hedge the price of the commodity and, if applicable,the basis between that derivative’s contract delivery location and the cashmarket location used for the actual sale of the product.  This structure attains a high level ofeffectiveness, ensuring that a change in the price of the forecastedtransaction will result in an equal and opposite change in the price of thederivative instrument hedging the transaction. We utilize crude oil as a surrogate hedge for natural gasoline andcondensate.  Our hedges are tested foreffectiveness at inception and on a quarterly basis thereafter.  We use regression analysis based on afive-year period of time for this test.

 

In the first quarter of 2004, we determinedin our quarterly effectiveness testing that our hedges of equity butaneproduction which utilized crude oil puts as a surrogate were no longereffective hedges.  Therefore, in thefirst quarter, we discontinued cash flow hedge accounting treatment on theseinstruments.  The value of thesefinancial instruments remained in Accumulated other comprehensive income andwas reclassified to our results of operations during 2004 as the underlying transactionsoccurred.   Gains or losses from theineffective portions of changes in the fair value of cash flow hedges arerecognized currently in earnings through Price risk management activities.  During 2004, we recognized a loss of $159,000from the ineffective portions of our hedges.

 

***Outstanding EquityHedge Positions and the Associated Basis for 2005****.* The following table details our hedge positions as of January 31,2005.  In order to determine the hedgedprice to the particular operating region, deduct the basis differential fromthe NYMEX price.  The prices for NGLs donot include the cost of the hedges of approximately $572,000 as of January 31,2005.  There is no associated cost forthe natural gas hedges.

 
| **Product**                         | ** ** | **Year** | ** ** | **Quantity  and Settle Price**                                                                                                   | ** ** | **Hedge of  Basis Differential**                                                                                                                                                                                                                                                             |
|-------------------------------------|------------|----------|------------|----------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Natural gas                         |       | 2005     |       | 80,000 MMBtu per day  with an average minimum price of $4.75 per MMBtu and an average maximum price  of $8.88 per MMBtu.         |       | Mid-Continent – 60,000  MMBtu per day with an average basis price of $0.42 per MMBtu.

 

Permian – 5,000 MMBtu  per day with an average basis price of $0.48 per MMBtu.

 

Rocky Mountain – 15,000  MMBtu per day with an average basis price of $0.72 per MMBtu. |
| Crude, Condensate, Natural Gasoline |       | 2005     |       | 50,000 Barrels per  month with an average minimum price of $31.00 per barrel and an average  maximum price of $48.01 per barrel. |       | Not Applicable                                                                                                                                                                                                                                                                               |
| Propane                             |       | 2005     |       | 75,000 Barrels per  month with an average minimum price of $0.52 per gallon and an average  maximum price of $0.88 per gallon.   |       | Not Applicable                                                                                                                                                                                                                                                                               |
| Ethane                              |       | 2005     |       | 75,000 Barrels per  month. Floor at $0.38 per gallon.                                                                            |       | Not Applicable                                                                                                                                                                                                                                                                               |

 

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Account balances related to hedgingtransactions (designated as hedges under SFAS 133) at December 31, 2004were $2.9 millionin Current assets from price risk management activities, $1.7 million inCurrent liabilities from price risk management activities, $240,000 in Deferredincome taxes payable, net, and a $410,000 after-tax unrealized gain inAccumulated other comprehensive income, a component of Stockholders’equity.  The unrealized gain inAccumulated other comprehensive income will be reclassified to earnings in2005.

 

***Valueat Risk.***  Wemeasure market risk in our natural gas and liquid marketing portfolios usingvalue-at-risk, or VaR.  We define VaR asa measure of the maximum expected loss over a given horizon under normal marketconditions.  VaR does not explicitlyindicate potential realized losses.  VaRdoes, however, implicitly indicate a firm’s potential realized loss if marketconditions were to remain constant or if the portfolio is liquidated within thespecified time period.  Our calculationsare derived from Financial Engineering Association’s VaR Works using thevariance/co-variance method.  We assume aone-day holding period with a 95% confidence level.  There is a 95% (19 out of 20 business days)chance that the portfolio loss will be less than a specified amount if theentire portfolio were liquidated the next day. As of December 31, 2004, our VaR position for natural gas andliquid marketing portfolios was $542,000 and the average for all of 2004 was$447,000.  This figure includes the riskrelated to our entire marketing portfolio of natural gas and NGL financial instrumentsand the related underlying physical transactions including stored gas volumes.

 

We also measure market risk by sensitivityvaluations.  As of December 31,2004, an increase in natural gas prices of $1.00 per MMbtu would lead to anincrease in the fair value of our marketing portfolio, including the relatedunderlying physical transactions including stored gas volumes, of $1.6 millionand an increase in crude oil prices of $5.00 per barrel would lead to anincrease in the fair value of our marketing portfolio of $900,000.

 

Historically, from an earnings perspective, thenon-cash mark-to-market valuation of the gas storage and transportationcontracts which were considered to be derivatives effectively offset non-cashmark-to-market changes to the future sale derivatives for our stored ortransported natural gas.  Without thisoffsetting valuation, the non-cash mark-to-market of the future sale derivativecontract on the sale of gas will fluctuate through earnings with changes inmarket prices and will not be offset by a corresponding mark to market on thegas storage and transportation contracts which are no longer derivatives.  Accordingly, earnings volatility will begreater than reflected by either the VaR calculation or the market risksensitivity presented above.  For example,at December 31, 2004, we held gas in our contracted storage facilities andin imbalances of approximately 16.3 Bcf. This inventoried gas was sold forward with derivatives.  Based on a $1.00 increase in the forwardprice of gas in the anticipated month of withdrawal, the change in the non-cashmark-to-market value of these derivatives will reduce pre-tax earnings by $16.3million and a $1.00 decrease in the forward price of gas in the anticipatedmonth of withdrawal will increase pre-tax earnings by $16.3 million. As the stored or transported natural gas issold and the future sale derivatives are settled, we will realize the benefitof the storage and transportation transactions through earnings.

 

***Summaryof Derivative Positions.***  A summary of the change in our derivativeposition from December 31, 2003 to December 31, 2004 is as follows(dollars in thousands):

 

| ** **                                                             | ** ** | **Restated** | ** ** |
|------------------------------------------------------------------------|------------|--------------|------------|
| Fair value  of contracts outstanding at December 31, 2003         |       | $            | (2,447     | ) |
| Decrease in  value due to change in price                              |       | 924          |       |
| Increase in  value due to new contracts entered into during the period |       | 23,702       |       |
| Losses  realized during the period from existing and new contracts     |       | 6,538        |       |
| Changes in  fair value attributable to changes in valuation techniques |       | —       |       |
| Fair value  of contracts outstanding at December 31, 2004         |       | $            | 15,640     |   |
|                                                                        |            |              |            |  |  |

 

A summary of our outstanding derivativepositions at December 31, 2004 is as follows (dollars in thousands):

 
| ** **                        | ** ** | **Fair Value of Contracts at December 31, 2004** | ** ** |
|-----------------------------------|------------|-------------------------------------------------------|------------|
| **Source of Fair Value**          | ** ** | **Total  Fair Value Restated**                        | ** ** | **Maturing  In 2005  Restated** | ** ** | **Maturing In  2006-2007  Restated** | ** ** | **Maturing In  2008-2009  Restated** | ** ** | **Maturing  Thereafter Restated** | ** ** |
| Exchange published prices         |       | $                                                     | 11,434     |   | $ | 11,392 |   | $ | 42 |   | — |   | — |   |
| Other actively quoted  prices (1) |       | 4,056                                                 |       | 4,030 |   | 26 |   | — |   | — |   |
| Other valuation methods  (2)      |       | 150                                                   |       | 150 |   | — |   | — |   | — |   |
| Total fair value                  |       | $                                                     | 15,640     |   | $ | 15,572 |   | $ | 68 |   | — |   | — |   |

 

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(1)               Other activelyquoted prices are derived from broker quotations, trade publications, andindustry indices.

(2)               Other valuationmethods are the Black-Scholes option-pricing model utilizing prices andvolatility obtained from broker quotations, trade publications, and industryindices.

 

***Foreign Currency DerivativeMarket Risk***. As a normal part of our business, we enter into physical gastransactions which are payable in Canadian dollars.  We enter into forward purchases and sales ofCanadian dollars from time to time to fix the cost of our future Canadiandollar denominated natural gas purchase, sale, storage, and transportationobligations.  This is done to protectmarketing margins from adverse changes in the U.S. and Canadian dollar exchangerate between the time the commitment for the payment obligation is made and theactual payment date of such obligation. As of December 31, 2004, we had sold forward contracts for $31.3million in Canadian dollars in exchange for $24.0 million in U.S. dollars, andthe fair market value of these contracts was a loss of $2.1 million in U.S.dollars.

 

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**ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA**

 

This Amendment No. 1 on Form 10-K/A to ourAnnual Report on Form 10-K for the year ended December 31, 2004,initially filed with the SEC on March 16, 2005, is being filed toreflect restatements of our Consolidated Financial Statements for each of thethree years in the period ended December 31, 2004, the Notes thereto,and Management's Report on Internal Control Over Financial Reporting.

 

Index

 
| Management’s Report on Internal Control  Over Financial Reporting (restated) |   |
|-----------------------------------------------------------------------------------|--------|
| Report of Independent Registered Public Accounting  Firm                          |   |
| Consolidated  Balance Sheet                                                       |   |
| Consolidated  Statement of Cash Flows                                             |   |
| Consolidated  Statement of Operations                                             |   |
| Consolidated  Statement of Changes in Stockholders’ Equity                   |   |
| Notes to  Consolidated Financial Statements                                       |   |
|                                                                              |   |
| Supplementary  Data                                                               |
|                                                                              |   |
| Supplemental Information on Oil and Gas Producing  Activities (unaudited)         |   |

 

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**Management’s Report on Internal Control OverFinancial Reporting (Restated)**

 

Our management is responsible for establishingand maintaining adequate internal control over financial reporting as definedin Rules 13a-15(f) and 15d-15(f) under the Securities ExchangeAct of 1934, as amended.  Our internalcontrol over financial reporting is designed to provide reasonable assuranceregarding the reliability of financial reporting and the preparation offinancial statements for external purposes in accordance with generallyaccepted accounting principles.  Because of its inherent limitations, internal controls overfinancial reporting may not prevent or detect misstatements.  Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

 

Management assessed the effectiveness of ourinternal control over financial reporting as of December 31, 2004. Inmaking this assessment, management used the criteria set forth by the Committeeof Sponsoring Organizations of the Treadway Commission (COSO) in *Internal Control-Integrated Framework*.

 

A material weakness is acontrol deficiency, or combination of control deficiencies, that results inmore than a remote likelihood that a material misstatement of the annual orinterim financial statements will not be prevented or detected.  Management has identified the followingmaterial weakness.  As of December 31,2004, the Company did not maintain effective controls over the existence anddesignation of certain derivative financial instruments.  Specifically, the Company inappropriatelydetermined its gas storage and transportation contracts to be transferable in aliquid market and therefore accounted for them as derivatives with changes inthe fair value of the contracts recognized in earnings during the currentperiod.  Inaddition, this control deficiency could result in a misstatement of the assetand liability from price risk management activities and related accounts thatwould result in a material misstatement of the annual or interim financialstatements that would not be prevented or detected.  Thiscontrol deficiency resulted in a restatement of the consolidatedfinancial statements for each of the three years in the period ended December 31,2004, each of the quarters in the two year period ended December 31, 2004and each of the quarters ended March 31, 2005 and June 30, 2005.  Accordingly, management has concluded thatthis control deficiency constitutes a material weakness.  As a result of this material weakness,management has concluded that the Company did not maintain effective internalcontrol over financial reporting as of December 31, 2004 based on thecriteria set forth in the COSO Internal Control Integrated Framework.  Management had previously concluded that theCompany did maintain effective internal control over financial reporting.  In connection with the restatement of theCompany’s consolidated financial statements described in Note 2 to theconsolidated financial statements, management has determined that the materialweakness described above existed at December 31, 2004 and has restated theprevious report.

 

We conduct aportion of our oil and gas operations through joint operating agreements withother companies.  Under a portion ofthese joint operating agreements, the other company is the operator of the welland charges us a proportional share of the cost of the well and the on-goingwell operations.  Under the agreements,we have the contractual right to audit the charges billed to us, but we do nothave the contractual right or abilityto dictate or modify the internal controls over financial reporting of theseentities and do not have the ability, in practice, to assess those controls.  Accordingly, these operations have not beenincluded in our assessment of the effectiveness of the Company’s internalcontrol over financial reporting. These oil and gas operationsare accounted for under the proportionate consolidation method.  The total assets of approximately $210million at December 31, 2004 and the total revenues of approximately $148million for the year ended December 31, 2004 represent 11% and 5%,respectively, of our consolidated financial statement amounts, and 45% and 56%,respectively, of the assets and revenues in the Exploration and ProductionSegment.

 

Management’s assessment ofthe effectiveness of the Company’s internal control over financial reporting asof December 31, 2004 has been audited by PricewaterhouseCoopers LLP, anindependent registered public accounting firm, as stated in their report whichis included herein.

 

 
| /s/ PETER A. DEA                      |   |
|---------------------------------------|--------|
| Peter A. Dea                          |
| Chief Executive Officer and President |

 

43

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| /s/ WILLIAM J. KRYSIAK                                   |   |
|----------------------------------------------------------|--------|
| William J. Krysiak                                       |
| Executive Vice President – Chief Financial  Officer |
| (Principal Financial and Accounting  Officer)            |

 

December 16, 2005

 

44

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### ***Report of Independent RegisteredPublic Accounting Firm***

 

Tothe Board of Directors and

Stockholdersof Western Gas Resources, Inc.:

 

Wehave completed an integrated audit of Western Gas Resources, Inc.’s 2004consolidated financial statements and of its internal control over financialreporting as of December 31, 2004 and audits of its 2003 and 2002 consolidatedfinancial statements in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Our opinions, based on ouraudits, are presented below.

 

Consolidatedfinancial statements

 

Inour opinion, the consolidated financialstatements listed in the accompanyingindex present fairly, in all material respects, the financial positionof Western Gas Resources, Inc. and its subsidiaries at December 31, 2004 and2003, and the results of their operations and their cash flows for each of thethree years in the period ended December 31, 2004****inconformity with accounting principles generally accepted in the United Statesof America.  These financial statementsare the responsibility of the Company’s management.  Our responsibility is to express an opinionon these financial statements based on our audits.  We conducted our audits of these statementsin accordance with the standards of the Public Company Accounting OversightBoard (United States).  Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether the financial statements are free of material misstatement.  An audit of financial statements includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements, assessing the accounting principles used andsignificant estimates made by management, and evaluating the overall financialstatement presentation.  We believe thatour audits provide a reasonable basis for our opinion.

 

Asdiscussed in Note 3 to the consolidated financial statements, the Companychanged its method of computing depletion for oil and gas properties effectiveJanuary 1, 2004, its method of accounting for asset retirement obligationseffective January 1, 2003, and its method of testing long-lived assets forimpairment in 2003.

 

As discussed in Note 2 to theconsolidated financial statements, the Company restated its 2004, 2003 and 2002consolidated financial statements.

 

Internal control over financialreporting

 

Also, we have audited management’sassessment, included in Management’s Report on Internal Control Over FinancialReporting appearing in Item 8, that the Company did not maintain effectiveinternal control over financial reporting as of December 31, 2004, because ofthe effect of the ineffective controls over the existence and designation ofcertain derivative financial instruments, based on criteria established in *Internal Control – Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commission(COSO).  The Company’s management isresponsible for maintaining effective internal control over financial reportingand for its assessment of the effectiveness of internal control over financialreporting.  Our responsibility is toexpress opinions on management’s assessment and on the effectiveness ofthe Company’s internal control over financial reporting based on our audit.

 

We conducted our audit of internalcontrol over financial reporting in accordance with the standards of the PublicCompany Accounting Oversight Board (United States).  Those standards require that we plan andperform the audit to obtain reasonable assurance about whether effectiveinternal control over financial reporting was maintained in all materialrespects.  An audit of internal controlover financial reporting includes obtaining an understanding of internalcontrol over financial reporting, evaluating management’s assessment, testingand evaluating the design and operating effectiveness of internal control, andperforming such other procedures as we consider necessary in thecircumstances.  We believe that our auditprovides a reasonable basis for our opinions.

 

A company’s internal control overfinancial reporting is a process designed to provide reasonable assuranceregarding the reliability of financial reporting and the preparation offinancial statements for external purposes in accordance with generally acceptedaccounting principles.  A company’sinternal control over financial reporting includes those policies andprocedures

 

45

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that (i) pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company;(ii) provide reasonable assurance that transactions are recorded asnecessary to permit preparation of financial statements in accordance withgenerally accepted accounting principles, and that receipts and expenditures ofthe company are being made only in accordance with authorizations of managementand directors of the company; and (iii) provide reasonable assuranceregarding prevention or timely detection of unauthorized acquisition, use, ordisposition of the company’s assets that could have a material effect on thefinancial statements.

 

Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements.  Also, projectionsof any evaluation of effectiveness to future periods are subject to the riskthat controls may become inadequate because of changes in conditions, or thatthe degree of compliance with the policies or procedures may deteriorate.

 

A material weakness is a controldeficiency, or combination of control deficiencies, that results in more than aremote likelihood that a material misstatement of the annual or interimfinancial statements will not be prevented or detected.  The following material weakness has beenidentified and included in management’s assessment.  As of December 31, 2004, the Company did notmaintain effective controls over the existence and designation of certainderivative financial instruments. Specifically, the Company inappropriately determined their gas storageand transportation contracts to be transferable in a liquid market andtherefore accounted for them as derivatives with changes in the fair value ofthe contracts recognized in earnings during the current period.  This control deficiency resulted in arestatement of the consolidated financial statements for each of the threeyears in the period ended December 31, 2004, each of the quarters in the twoyear period ended December 31, 2004 and each of the quarters ended March 31,2005 and June 30, 2005.  In addition,this control deficiency could result in a misstatement of the asset andliability from price risk management activities and related accounts that wouldresult in a material misstatement of the annual or interim financial statementsthat would not be prevented or detected. Accordingly, management has concluded that this control deficiencyconstitutes a material weakness.

 

This material weakness wasconsidered in determining the nature, timing and extent of audit tests appliedin our audit of the 2004 consolidated financial statements, and our opinionregarding the effectiveness of the Company’s internal control over financialreporting does not affect our opinion on those consolidated financialstatements.

 

As described in Management’s Reporton Internal Control Over Financial Reporting, management has excluded its oiland gas operations managed by other joint interest operators from itsassessment of internal control over financial reporting as of December 31, 2004because the Company does not have the ability to dictate or modify the internalcontrols over financial reporting of these entities and does not have theability, in practice, to assess those controls. Accordingly, these operations have not been included in management’sassessment of the effectiveness of the Company’s internal control overfinancial reporting.  These oil and gasoperations are owned through undivided interests and proportionatelyconsolidated in the Company’s consolidated financial statements.  These properties had total assets and totalrevenues of $210 million and $148 million, respectively, representing 11% and5% of the related consolidated financial statement amounts, as of and for theyear ended December 31, 2004.

 

Management and we previously concluded that the Company maintainedeffective internal control over financial reporting as of December 31,2004.  In connection with the restatementof the Company’s consolidated financial statements described in Note 2 to theconsolidated financial statements, management has determined that the materialweakness described above existed as of December 31, 2004.  Accordingly, Management’s Report on InternalControl Over Financial Reporting has been restated and our present opinion oninternal control over financial reporting, as presented herein, is differentfrom that expressed in our previous report.

 

In our opinion, management’sassessment that Western Gas Resources, Inc. did not maintain effective internalcontrol over financial reporting as of December 31, 2004, is fairly stated, inall material respects, based on criteria established in *Internal Control – Integrated Framework*issued by the COSO.  Also, in ouropinion, because of the effect of the material weakness described above on theachievement of the objectives of the control criteria, the Company has notmaintained effective internal control over financial reporting as of December31, 2004 based on the criteria established in *InternalControl – Integrated Framework* issued by the COSO.

 

PricewaterhouseCoopers LLP

Denver, Colorado

March 11, 2005, except for therestatement described in Note 2 to the consolidated financial statements andthe matter described in the third paragraph of Management’s Report on InternalControl Over Financial Reporting (restated), as to which the date isDecember 18, 2005

 

46

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WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(000s, except share data)

 
| ** **                                                                                                          | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------|------------|------------------|------------|
| ** **                                                                                                          | ** ** | **2004**         | ** ** | **2003** | ** ** |
| ** **                                                                                                          | ** ** | **Restated**     | ** ** | **Restated** | ** ** |
| ASSETS                                                                                                              |       |             |       |   |   |
| Current assets:                                                                                                     |       |             |       |   |   |
| Cash and cash equivalents                                                                                           |       | $                | 390        |   | $ | 26,116 |   |
| Trade accounts receivable, net                                                                                      |       | 385,811          |       | 254,411 |   |
| Margin deposits                                                                                                     |       | 7,939            |       | 8,098 |   |
| Inventory                                                                                                           |       | 94,604           |       | 70,304 |   |
| Assets from price risk management  activities                                                                       |       | 19,893           |       | 6,857 |   |
| Deferred income taxes                                                                                               |       | —           |       | 946 |   |
| Other                                                                                                               |       | 12,494           |       | 11,225 |   |
| Total current assets                                                                                                |       | 521,131          |       | 377,957 |   |
|                                                                                                                |       |             |       |   |   |
| Property and equipment:                                                                                             |       |             |       |   |   |
| Gas gathering, processing and  transportation                                                                       |       | 1,150,904        |       | 1,028,176 |   |
| Oil and gas properties and equipment (successful  efforts method)                                                   |       | 495,314          |       | 329,555 |   |
| Construction in progress                                                                                            |       | 150,273          |       | 134,751 |   |
|                                                                                                                |       | 1,796,491        |       | 1,492,482 |   |
| Less: Accumulated depreciation, depletion  and amortization                                                         |       | (570,582         | )          | (495,721 | ) |
|                                                                                                                |       |             |       |   |   |
| Total property and equipment, net                                                                                   |       | 1,225,909        |       | 996,761 |   |
|                                                                                                                |       |             |       |   |   |
| Other assets:                                                                                                       |       |             |       |   |   |
| Gas purchase contracts (net of accumulated  amortization of $40,652 and $38,937, respectively)                      |       | 27,704           |       | 29,219 |   |
| Assets from price risk management  activities                                                                       |       | 249              |       | 1,466 |   |
| Investments in joint ventures                                                                                       |       | 35,729           |       | 39,289 |   |
| Other                                                                                                               |       | 26,676           |       | 6,486 |   |
|                                                                                                                |       |             |       |   |   |
| Total other assets                                                                                                  |       | 90,358           |       | 76,460 |   |
|                                                                                                                |       |             |       |   |   |
| TOTAL ASSETS                                                                                                        |       | $                | 1,837,398  |   | $ | 1,451,178 |   |
|                                                                                                                |       |             |       |   |   |
| LIABILITIES  AND STOCKHOLDERS’ EQUITY                                                                          |       |             |       |   |   |
|                                                                                                                |       |             |       |   |   |
| Current liabilities:                                                                                                |       |             |       |   |   |
| Accounts payable                                                                                                    |       | $                | 400,672    |   | $ | 303,186 |   |
| Accrued expenses                                                                                                    |       | 60,472           |       | 42,136 |   |
| Liabilities from price risk management  activities                                                                  |       | 4,321            |       | 9,465 |   |
| Deferred income taxes                                                                                               |       | 5,618            |       | — |   |
| Dividends payable                                                                                                   |       | 3,704            |       | 3,056 |   |
| Total current liabilities                                                                                           |       | 474,787          |       | 357,843 |   |
|                                                                                                                |       |             |       |   |   |
| Long-term debt                                                                                                      |       | 382,000          |       | 339,000 |   |
| Liabilities from price risk management  activities                                                                  |       | 180              |       | 1,304 |   |
| Other long-term liabilities                                                                                         |       | 51,827           |       | 22,057 |   |
| Deferred income taxes payable, net                                                                                  |       | 243,835          |       | 174,268 |   |
|                                                                                                                |       |             |       |   |   |
| Total liabilities                                                                                                   |       | 1,152,629        |       | 894,472 |   |
|                                                                                                                |       |             |       |   |   |
| Stockholders’ equity:                                                                                          |       |             |       |   |   |
| Preferred Stock; 10,000,000 shares  authorized:                                                                     |       |             |       |   |   |
| $2.625 cumulative convertible preferred  stock, par value $.10; none and 2,060,000 outstanding, respectively        |       | —           |       | 206 |   |
| Common stock, par value $.10; 100,000,000  shares authorized; 74,078,733 and 68,271,802 shares issued, respectively |       | 7,430            |       | 6,876 |   |
| Treasury stock, at cost; 50,032 common  shares in treasury                                                          |       | (788             | )          | (788 | ) |
| Additional paid-in capital                                                                                          |       | 392,437          |       | 381,581 |   |
| Retained earnings                                                                                                   |       | 281,428          |       | 167,273 |   |
| Accumulated other comprehensive income                                                                              |       | 4,262            |       | 1,558 |   |
|                                                                                                                |       |             |       |   |   |
| Total stockholders’ equity                                                                                     |       | 684,769          |       | 556,706 |   |
|                                                                                                                |       |             |       |   |   |
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                     |       | $                | 1,837,398  |   | $ | 1,451,178 |   |

 

Theaccompanying notes are an integral part of the consolidated financial statements.

 

47

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WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(000s)

 
| ** **                                                                              | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                              | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
|                                                                                    |       |                        |       |   |   |   |   |
| Reconciliation of net income to net cash  provided by operating activities:             |       |                        |       |   |   |   |   |
| Net income                                                                              |       | $                           | 127,759    |   | $ | 87,935 |   | $ | 34,106 |   |
| Add income items that do not affect  operating cash flows:                              |       |                        |       |   |   |   |   |
| Depreciation, depletion and amortization                                                |       | 95,536                      |       | 73,906 |   | 77,005 |   |
| Deferred income taxes                                                                   |       | 71,200                      |       | 51,351 |   | 10,145 |   |
| Distributions more than or (less than)  equity income, net                              |       | 127                         |       | 1,076 |   | (2,906 | ) |
| (Gain) loss on the sale of property and  equipment                                      |       | 1,288                       |       | (156 | ) | 948 |   |
| Non-cash change in fair value of  derivatives                                           |       | (15,027                     | )          | (6,976 | ) | 39,741 |   |
| Compensation expense from re-priced stock  options                                      |       | 646                         |       | 376 |   | 224 |   |
| Cumulative effect of change in accounting  principle                                    |       | (4,714                      | )          | 6,724 |   | — |   |
| Other non-cash items, net                                                               |       | 2,112                       |       | 1,430 |   | 1,809 |   |
|                                                                                    |       |                        |       |   |   |   |   |
| Adjustments to working capital  to arrive at net cash provided by operating activities: |       |                        |       |   |   |   |   |
| (Increase) in trade accounts receivable                                                 |       | (127,042                    | )          | (21,730 | ) | (3,139 | ) |
| (Increase) decrease in margin deposits                                                  |       | 159                         |       | 14,010 |   | (32,077 | ) |
| (Increase) decrease in product inventory                                                |       | (22,215                     | )          | (25,136 | ) | 7,164 |   |
| Decrease (increase) in other current assets                                             |       | 1,553                       |       | 8,869 |   | (13,329 | ) |
| (Increase) decrease in other assets and  liabilities, net                               |       | (5,019                      | )          | (359 | ) | 347 |   |
| Increase (decrease) in accounts payable                                                 |       | 65,905                      |       | 55,689 |   | (23,129 | ) |
| Increase (decrease) in accrued expenses                                                 |       | 16,891                      |       | (2,787 | ) | 27,492 |   |
|                                                                                    |       |                        |       |   |   |   |   |
| Net cash provided by operating activities                                               |       | 209,159                     |       | 244,222 |   | 124,401 |   |
|                                                                                    |       |                        |       |   |   |   |   |
| Cash flows from investing activities:                                                   |       |                        |       |   |   |   |   |
| Purchases of property and equipment,  including acquisitions                            |       | (306,266                    | )          | (188,318 | ) | (125,600 | ) |
| Proceeds from the disposition of property  and equipment                                |       | 1,501                       |       | 5,983 |   | 34,865 |   |
| Distributions from (contributions to)  equity investees                                 |       | 2,310                       |       | (14,750 | ) | (15,037 | ) |
|                                                                                    |       |                        |       |   |   |   |   |
| Net cash used in investing activities                                                   |       | (302,455                    | )          | (197,085 | ) | (105,772 | ) |
|                                                                                    |       |                        |       |   |   |   |   |
| Cash flows from financing activities:                                                   |       |                        |       |   |   |   |   |
| Net proceeds from exercise of common stock  options                                     |       | 9,993                       |       | 5,027 |   | 6,489 |   |
| Change in outstanding checks                                                            |       | 31,581                      |       | 4,510 |   | 6,735 |   |
| Payments for the redemption of preferred  stock                                         |       | (1,930                      | )          | (1,201 | ) | (12,607 | ) |
| Borrowings under long-term debt                                                         |       | 100,000                     |       | 25,000 |   | — |   |
| Payments on long-term debt                                                              |       | (190,000                    | )          | (43,333 | ) | (8,333 | ) |
| Borrowings under revolving credit facility                                              |       | 2,654,230                   |       | 1,022,300 |   | 994,545 |   |
| Payments on revolving credit facility                                                   |       | (2,521,230                  | )          | (1,024,900 | ) | (992,945 | ) |
| Debt issue costs paid                                                                   |       | (2,086                      | )          | (1,861 | ) | (126 | ) |
| Dividends paid                                                                          |       | (12,988                     | )          | (13,875 | ) | (15,107 | ) |
|                                                                                    |       |                        |       |   |   |   |   |
| Net cash provided by (used in) financing  activities                                    |       | 67,570                      |       | (28,333 | ) | (21,349 | ) |
|                                                                                    |       |                        |       |   |   |   |   |
| Net (decrease) increase in cash and cash equivalents                                    |       | (25,726                     | )          | 18,804 |   | (2,720 | ) |
|                                                                                    |       |                        |       |   |   |   |   |
| Cash and cash equivalents at beginning of  year                                         |       | 26,116                      |       | 7,312 |   | 10,032 |   |
|                                                                                    |       |                        |       |   |   |   |   |
| Cash and cash equivalents at end of year                                                |       | $                           | 390        |   | $ | 26,116 |   | $ | 7,312 |   |

 

Theaccompanying notes are an integral part of the consolidated financialstatements.

 

48

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WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(000s, except share and per share amounts)

 
| ** **                                                                                                                  | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                  | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                                                  | ** ** | **Restated**                | ** ** | **Restated** | ** ** | **Restated** | ** ** |
| Revenues:                                                                                                                   |       |                        |       |   |   |   |   |
| Sale of gas                                                                                                                 |       | $                           | 2,518,281  |   | $ | 2,463,757 |   | $ | 2,119,196 |   |
| Sale of natural gas liquids                                                                                                 |       | 450,761                     |       | 346,109 |   | 309,514 |   |
| Gathering, processing and transportation                                                                                    |       | 90,874                      |       | 83,672 |   | 65,601 |   |
| Price risk management activities                                                                                            |       | 20,051                      |       | (16,386 | ) | (35,285 | ) |
| Other                                                                                                                       |       | 3,201                       |       | 2,599 |   | 4,720 |   |
| Total revenues                                                                                                              |       | 3,083,168                   |       | 2,879,751 |   | 2,463,746 |   |
|                                                                                                                        |       |                        |       |   |   |   |   |
| Costs and expenses:                                                                                                         |       |                        |       |   |   |   |   |
| Product purchases                                                                                                           |       | 2,540,799                   |       | 2,456,441 |   | 2,157,179 |   |
| Plant and transportation operating expense                                                                                  |       | 95,868                      |       | 88,344 |   | 81,530 |   |
| Oil and gas exploration and production  costs                                                                               |       | 77,608                      |       | 52,245 |   | 34,007 |   |
| Depreciation, depletion and amortization                                                                                    |       | 95,536                      |       | 73,906 |   | 77,005 |   |
| Selling and administrative expense                                                                                          |       | 52,246                      |       | 40,423 |   | 35,828 |   |
| (Gain) loss on sale of assets                                                                                               |       | 1,288                       |       | (156 | ) | 948 |   |
| Loss from early extinguishment of debt                                                                                      |       | 10,662                      |       | — |   | — |   |
| Earnings from equity investments                                                                                            |       | (7,124                      | )          | (7,356 | ) | (4,453 | ) |
| Interest expense                                                                                                            |       | 19,562                      |       | 25,627 |   | 26,951 |   |
| Total costs and expenses                                                                                                    |       | 2,886,445                   |       | 2,729,474 |   | 2,408,995 |   |
|                                                                                                                        |       |                        |       |   |   |   |   |
| Income before income taxes                                                                                                  |       | 196,723                     |       | 150,277 |   | 54,751 |   |
| Provision for income taxes:                                                                                                 |       |                        |       |   |   |   |   |
| Current                                                                                                                     |       | 2,478                       |       | 4,267 |   | 10,500 |   |
| Deferred                                                                                                                    |       | 71,200                      |       | 51,351 |   | 10,145 |   |
| Total provision for income taxes                                                                                            |       | 73,678                      |       | 55,618 |   | 20,645 |   |
| Income before cumulative effect of change  in accounting principle                                                          |       | 123,045                     |       | 94,659 |   | 34,106 |   |
| Cumulative effect of change in accounting  principle, net of tax (expense) or benefit of ($2,710) and $3,967,  respectively |       | 4,714                       |       | (6,724 | ) | — |   |
| Net income                                                                                                                  |       | $                           | 127,759    |   | $ | 87,935 |   | $ | 34,106 |   |
|                                                                                                                        |       |                        |       |   |   |   |   |
| Preferred stock requirements                                                                                                |       | (835                        | )          | (6,841 | ) | (9,198 | ) |
|                                                                                                                        |       |                        |       |   |   |   |   |
| Income attributable to common stock                                                                                         |       | $                           | 126,924    |   | $ | 81,094 |   | $ | 24,908 |   |
|                                                                                                                        |       |                        |       |   |   |   |   |
| Earnings per share of common stock before  cumulative effect of change in accounting principle                              |       | $                           | 1.68       |   | $ | 1.32 |   | $ | 0.38 |   |
|                                                                                                                        |       |                        |       |   |   |   |   |
| Cumulative effect of change in accounting  principle per share of common stock, net of tax                                  |       | $                           | 0.07       |   | $ | (0.10 | ) | $ | — |   |
|                                                                                                                        |       |                        |       |   |   |   |   |
| Earnings per share of common stock                                                                                          |       | $                           | 1.75       |   | $ | 1.22 |   | $ | 0.38 |   |
|                                                                                                                        |       |                        |       |   |   |   |   |
| Weighted average shares of common stock  outstanding                                                                        |       | 72,419,980                  |       | 66,412,229 |   | 65,905,086 |   |
|                                                                                                                        |       |                        |       |   |   |   |   |
| Income attributable to common stock -  assuming dilution                                                                    |       | $                           | 126,924    |   | $ | 87,935 |   | $ | 24,908 |   |
|                                                                                                                        |       |                        |       |   |   |   |   |
| Earnings per share of common stock -  assuming dilution                                                                     |       | $                           | 1.73       |   | $ | 1.18 |   | $ | 0.37 |   |
|                                                                                                                        |       |                        |       |   |   |   |   |
| Weighted average shares of common stock  outstanding - assuming dilution                                                    |       | 73,494,747                  |       | 74,694,420 |   | 67,215,120 |   |

 

Theaccompanying notes are an integral part of the consolidated financialstatements.

 

49

----

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(000s, except share amounts)

 
| ** **                                                           | ** ** | **Shares  of** | ** ** | **$2.625**      | ** ** | ** **     | ** ** | ** **       | ** ** | **Shares  of**       | ** ** | ** **     | ** ** | **$2.625**      | ** ** |
|----------------------------------------------------------------------|------------|----------------|------------|-----------------|------------|----------------|------------|------------------|------------|----------------------|------------|----------------|------------|-----------------|------------|
| ** **                                                           | ** ** | **$2.28**      | ** ** | **Cumulative**  | ** ** | ** **     | ** ** | **Shares**       | ** ** | **$2.28**            | ** ** | **$2.28**      | ** ** | **Cumulative**  | ** ** |
| ** **                                                           | ** ** | **Cumulative** | ** ** | **Convertible** | ** ** | **Shares**     | ** ** | **of  Common**   | ** ** | **Cumulative**       | ** ** | **Cumulative** | ** ** | **Convertible** | ** ** |
| ** **                                                           | ** ** | **Preferred**  | ** ** | **Preferred**   | ** ** | **of  Common** | ** ** | **Stock**        | ** ** | **Preferred  Stock** | ** ** | **Preferred**  | ** ** | **Preferred**   | ** ** |
| ** **                                                           | ** ** | **Stock**      | ** ** | **Stock**       | ** ** | **Stock**      | ** ** | **in  Treasury** | ** ** | **in  Treasury**     | ** ** | **Stock**      | ** ** | **Stock**       | ** ** |
| Balance at  December 31, 2001 (Restated)                             |       | 591,136        |       | 2,760,000       |       | 65,378,018     |       | 50,032           |       | 44,290               |       | $              | 59         |            | $          | 276 |   |
| Comprehensive  income:                                               |       |           |       |            |       |           |       |             |       |                 |       |           |       |            |       |
| Net income, 2002  (Restated)                                         |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Other  comprehensive income from equity investees                    |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Translation  adjustments                                             |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Reclassification  adjustment for settled contracts                   |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Changes in fair  value of outstanding hedge positions                |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Fair value of new  hedge positions                                   |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Change in  accumulated derivative comprehensive income               |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Total  comprehensive income, net of tax                              |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Stock options  exercised                                             |       | —         |       | —          |       | 777,204        |       | —           |       | —               |       | —         |       | —          |       |
| Effect of  re-priced options                                         |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Officer loans  forgiven                                              |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Tax benefit  related to stock options exercised                      |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Dividends  declared on common stock                                  |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Dividends  declared on $2.28 cumulative preferred stock              |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Dividends  declared on $2.625 cumulative convertible preferred stock |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Redemption of  $2.28 cumulative preferred stock                      |       | (591,136       | )          | —          |       | —         |       | —           |       | (44,290              | )          | (59            | )          | —          |       |
| Balance at  December 31, 2002 (Restated)                             |       | —         |       | 2,760,000       |       | 66,155,222     |       | 50,032           |       | —               |       | $              | —     |            | $          | 276 |   |
| Comprehensive  income:                                               |       |           |       |            |       |           |       |             |       |                 |       |           |       |            |       |
| Net income, 2003  (Restated)                                         |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Translation  adjustments                                             |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Reclassification  adjustment for settled contracts                   |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Changes in fair  value of outstanding hedge positions                |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Fair value of new  hedge positions                                   |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Change in accumulated  derivative comprehensive income               |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Total  comprehensive income, net of tax                              |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Stock options  exercised                                             |       | —         |       | —          |       | 415,180        |       | —           |       | —               |       | —         |       | —          |       |
| Effect of  re-priced options                                         |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Officer loans  forgiven                                              |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Tax benefit  related to stock options exercised                      |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Dividends  declared on common stock                                  |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Dividends  declared on $2.625 cumulative convertible preferred stock |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Conversion of  $2.625 cumulative convertible preferred stock         |       | —         |       | (676,344        | )          | 1,701,400      |       | —           |       | —               |       | —         |       | (68             | )          |
| Redemption of  $2.625 cumulative convertible preferred stock         |       | —         |       | (23,656         | )          | —         |       | —           |       | —               |       | —         |       | (2              | )          |
| Balance at December  31, 2003 (Restated)                             |       | —         |       | 2,060,000       |       | 68,271,802     |       | 50,032           |       | —               |       | $              | —     |            | $          | 206 |   |
| Comprehensive  income:                                               |       |           |       |            |       |           |       |             |       |                 |       |           |       |            |       |
| Net income, 2004  (Restated)                                         |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Translation  adjustments                                             |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Other comprehensive  income from equity affiliates                   |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Reclassification  adjustment for settled contracts                   |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Changes in fair  value of outstanding hedge positions                |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Reduction due to  estimated ineffectiveness                          |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Fair value of new  hedge positions                                   |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Change in  accumulated derivative comprehensive income               |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Total  comprehensive income, net of tax                              |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Stock options  exercised                                             |       | —         |       | —          |       | 681,703        |       | —           |       | —               |       | —         |       | —          |       |
| Effect of  re-priced options                                         |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Tax benefit  related to stock options exercised                      |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Dividends  declared on common stock                                  |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Dividends  declared on $2.625 cumulative convertible preferred stock |       | —         |       | —          |       | —         |       | —           |       | —               |       | —         |       | —          |       |
| Conversion of  $2.625 cumulative convertible preferred stock         |       | —         |       | (2,024,404      | )          | 5,125,228      |       | —           |       | —               |       | —         |       | (204            | )          |
| Redemption of  $2.625 cumulative convertible preferred stock         |       | —         |       | (35,596         | )          | —         |       | —           |       | —               |       | —         |       | (2              | )          |
| Balance at  December 31, 2004 (Restated)                             |       | —         |       | —          |       | 74,078,733     |       | 50,032           |       | —               |       | $              | —     |            | $          | — |   |

 
| ** **                                                           | ** ** | ** ** | ** ** | ** **   | ** ** | ** **     | ** ** | ** **    | ** ** | **Accumulated**    | ** ** | ** **     | ** ** | ** **             | ** ** |
|----------------------------------------------------------------------|------------|------------|------------|--------------|------------|----------------|------------|---------------|------------|--------------------|------------|----------------|------------|------------------------|------------|
| ** **                                                           | ** ** | ** ** | ** ** | ** **   | ** ** | ** **     | ** ** | ** **    | ** ** | **Other**          | ** ** | **Notes**      | ** ** | ** **             | ** ** |
| ** **                                                           | ** ** | ** ** | ** ** | ** **   | ** ** | **Additional** | ** ** | **Retained**  | ** ** | **Comprehensive**  | ** ** | **Receivable** | ** ** | **Total**              | ** ** |
| ** **                                                           | ** ** | **Common** | ** ** | **Treasury** | ** ** | **Paid-In**    | ** ** | **(Deficit)** | ** ** | **Income  (Loss)** | ** ** | **from Key**   | ** ** | **Stockholders’** | ** ** |
| ** **                                                           | ** ** | **Stock**  | ** ** | **Stock**    | ** ** | **Capital**    | ** ** | **Earnings**  | ** ** | **Net of  Tax**    | ** ** | **Employees**  | ** ** | **Equity**             | ** ** |
| Balance at  December 31, 2001 (Restated)                             |       | $          | 3,293      |         | $          | (1,907         | )          | $             | 387,505    |               | $          | 73,092         |       | $                      | 18,882     |   | $ | (884 | ) | $ | 480,316 |   |
| Comprehensive  income:                                               |       |       |       |         |       |           |       |          |       |               |       |           |       |                   |       |
| Net income, 2002  (Restated)                                         |       | —     |       | —       |       | —         |       | 34,106        |       | —             |       | —         |       | 34,106                 |       |
| Other  comprehensive income from equity investees                    |       | —     |       | —       |       | —         |       | —        |       | 556                |       | —         |       | 556                    |       |
| Translation  adjustments                                             |       | —     |       | —       |       | —         |       | —        |       | 283                |       | —         |       | 283                    |       |
| Reclassification  adjustment for settled contracts                   |       | —     |       | —       |       | —         |       | —        |       | (17,142            | )          | —         |       | (17,142                | )          |
| Changes in fair  value of outstanding hedge positions                |       | —     |       | —       |       | —         |       | —        |       | (119               | )          | —         |       | (119                   | )          |
| Fair value of new  hedge positions                                   |       | —     |       | —       |       | —         |       | —        |       | (5,272             | )          | —         |       | (5,272                 | )          |
| Change in  accumulated derivative comprehensive income               |       | —     |       | —       |       | —         |       | —        |       | (22,533            | )          | —         |       | (22,533                | )          |
| Total  comprehensive income, net of tax                              |       | —     |       | —       |       | —         |       | —        |       | —             |       | —         |       | 12,412                 |       |
| Stock options  exercised                                             |       | 36         |       | —       |       | 5,975          |       | —        |       | —             |       | —         |       | 6,011                  |       |
| Effect of  re-priced options                                         |       | —     |       | —       |       | 478            |       | —        |       | —             |       | —         |       | 478                    |       |
| Officer loans  forgiven                                              |       | —     |       | —       |       | —         |       | —        |       | —             |       | 589            |       | 589                    |       |
| Tax benefit  related to stock options exercised                      |       | —     |       | —       |       | 1,154          |       | —        |       | —             |       | —         |       | 1,154                  |       |
| Dividends  declared on common stock                                  |       | —     |       | —       |       | —         |       | (6,603        | )          | —             |       | —         |       | (6,603                 | )          |
| Dividends  declared on $2.28 cumulative preferred stock              |       | —     |       | —       |       | —         |       | (957          | )          | —             |       | —         |       | (957                   | )          |
| Dividends  declared on $2.625 cumulative convertible preferred stock |       | —     |       | —       |       | —         |       | (7,244        | )          | —             |       | —         |       | (7,244                 | )          |
| Redemption of  $2.28 cumulative preferred stock                      |       | —     |       | 1,119        |       | (14,046        | )          | 379           |       | —             |       | —         |       | (12,607                | )          |
| Balance at  December 31, 2002 (Restated)                             |       | $          | 3,329      |         | $          | (788           | )          | $             | 381,066    |               | $          | 92,773         |       | $                      | (2,812     | ) | $ | (295 | ) | $ | 473,549 |   |
| Comprehensive  income:                                               |       |       |       |         |       |           |       |          |       |               |       |           |       |                   |       |
| Net income, 2003  (Restated)                                         |       | —     |       | —       |       | —         |       | 87,935        |       | —             |       | —         |       | 87,935                 |       |
| Translation  adjustments                                             |       | —     |       | —       |       | —         |       | —        |       | 1,237              |       | —         |       | 1,237                  |       |
| Reclassification  adjustment for settled contracts                   |       | —     |       | —       |       | —         |       | —        |       | 5,272              |       | —         |       | 5,272                  |       |
| Changes in fair  value of outstanding hedge positions                |       | —     |       | —       |       | —         |       | —        |       | 127                |       | —         |       | 127                    |       |
| Fair value of new  hedge positions                                   |       | —     |       | —       |       | —         |       | —        |       | (2,266             | )          | —         |       | (2,266                 | )          |
| Change in  accumulated derivative comprehensive income               |       | —     |       | —       |       | —         |       | —        |       | 3,133              |       | —         |       | 3,133                  |       |
| Total  comprehensive income, net of tax                              |       | —     |       | —       |       | —         |       | —        |       | —             |       | —         |       | 92,305                 |       |
| Stock options  exercised                                             |       | 24         |       | —       |       | 3,570          |       | —        |       | —             |       | —         |       | 3,594                  |       |
| Effect of  re-priced options                                         |       | —     |       | —       |       | 904            |       | —        |       | —             |       | —         |       | 904                    |       |
| Officer loans  forgiven                                              |       | —     |       | —       |       | —         |       | —        |       | —             |       | 295            |       | 295                    |       |
| Tax benefit  related to stock options exercised                      |       | —     |       | —       |       | 727            |       | —        |       | —             |       | —         |       | 727                    |       |
| Dividends  declared on common stock                                  |       | —     |       | —       |       | —         |       | (6,684        | )          | —             |       | —         |       | (6,684                 | )          |
| Dividends  declared on $2.625 cumulative convertible preferred stock |       | —     |       | —       |       | —         |       | (6,783        | )          | —             |       | —         |       | (6,783                 | )          |
| Conversion of  $2.625 cumulative convertible preferred stock         |       | 85         |       | —       |       | (17            | )          | —        |       | —             |       | —         |       | —                 |       |
| Redemption of  $2.625 cumulative convertible preferred stock         |       | —     |       | —       |       | (1,231         | )          | 32            |       | —             |       | —         |       | (1,201                 | )          |
| Two for one  common stock split on June 18, 2004                     |       | 3,438      |       | —       |       | (3,438         | )          | —        |       | —             |       | —         |       | —                 |       |
| Balance at  December 31, 2003 (Restated)                             |       | $          | 6,876      |         | $          | (788           | )          | $             | 381,581    |               | $          | 167,273        |       | $                      | 1,558      |   | $ | — |   | $ | 556,706 |   |
| Comprehensive  income:                                               |       |       |       |         |       |           |       |          |       |               |       |           |       |                   |       |
| Net income, 2004  (Restated)                                         |       | —     |       | —       |       | —         |       | 127,759       |       | —             |       | —         |       | 127,759                |       |
| Translation  adjustments                                             |       | —     |       | —       |       | —         |       | —        |       | 816                |       | —         |       | 816                    |       |
| Other  comprehensive income from equity affiliates                   |       | —     |       | —       |       | —         |       | —        |       | (780               | )          | —         |       | (780                   | )          |
| Reclassification  adjustment for settled contracts                   |       | —     |       | —       |       | —         |       | —        |       | 2,266              |       | —         |       | 2,266                  |       |
| Changes in fair  value of outstanding hedge positions                |       | —     |       | —       |       | —         |       | —        |       | 16                 |       | —         |       | 16                     |       |
| Reduction due to  estimated ineffectiveness                          |       | —     |       | —       |       | —         |       | —        |       | (8                 | )          | —         |       | (8                     | )          |
| Fair value of new  hedge positions                                   |       | —     |       | —       |       | —         |       | —        |       | 394                |       | —         |       | 394                    |       |
| Change in  accumulated derivative comprehensive income               |       | —     |       | —       |       | —         |       | —        |       | 2,668              |       | —         |       | 2,668                  |       |
| Total  comprehensive income, net of tax                              |       | —     |       | —       |       | —         |       | —        |       | —             |       | —         |       | 130,463                |       |
| Stock options  exercised                                             |       | 108        |       | —       |       | 9,885          |       | —        |       | —             |       | —         |       | 9,993                  |       |
| Effect of  re-priced options                                         |       | —     |       | —       |       | 646            |       | —        |       | —             |       | —         |       | 646                    |       |
| Tax benefit  related to stock options exercised                      |       | —     |       | —       |       | 2,527          |       | —        |       | —             |       | —         |       | 2,527                  |       |
| Dividends declared  on common stock                                  |       | —     |       | —       |       | —         |       | (12,847       | )          | —             |       | —         |       | (12,847                | )          |
| Dividends  declared on $2.625 cumulative convertible preferred stock |       | —     |       | —       |       | —         |       | (789          | )          | —             |       | —         |       | (789                   | )          |
| Conversion of  $2.625 cumulative convertible preferred stock         |       | 510        |       | —       |       | (348           | )          | —        |       | —             |       | —         |       | (42                    | )          |
| Redemption of  $2.625 cumulative convertible preferred stock         |       | —     |       | —       |       | (1,918         | )          | 32            |       | —             |       | —         |       | (1,888                 | )          |
| Open market stock  split transactions                                |       | (64        | )          | —       |       | 64             |       | —        |       | —             |       | —         |       | —                 |       |
| Balance at  December 31, 2004 (Restated)                             |       | $          | 7,430      |         | $          | (788           | )          | $             | 392,437    |               | $          | 281,428        |       | $                      | 4,262      |   | $ | — |   | $ | 684,769 |   |

 

The accompanying notes are an integral part of the consolidatedfinancial statements.

 

50

----

 

**WESTERN GAS RESOURCES, INC.**

###### **NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

 

# **NOTE 1 - NATURE OFORGANIZATION**

 

Western Gas Resources,Inc. (the “Company”) explores for, develops and produces, gathers, processesand treats, transports and markets natural gas and natural gas liquids (“NGLs”).In its upstream operations, the Company explores for, develops and producesnatural gas reserves primarily in the Rocky Mountain region.  In its midstream operations the Companydesigns, constructs, owns and operates natural gas gathering, processing andtreating facilities and owns and operates regulated transportation facilities,and offers marketing services in order to provide its customers with a broadrange of services from the wellhead to the sales delivery point.  The Company’s midstream operations areconducted in major gas-producing basins in the Rocky Mountain, Mid-Continentand Southwestern regions of the United States.

 

In2002, the Company adopted a Stockholder Rights Plan under which Series A JuniorParticipating Preferred Stock Purchase Rights were distributed as a dividend atthe rate of one-half of one right for each share of its common stock held bystockholders of record as of the close of business on April 9, 2002.  Each right initially will entitlestockholders to buy one unit consisting of 1/100th of a share of anew series of preferred stock for $180 per unit.  The right generally will be exercisable onlyif a person or group acquires beneficial ownership of 15% or more of theCompany’s then outstanding common stock or commences a tender or exchange offerupon consummation of which a person or group would beneficially own 15% or moreof its then outstanding common stock. The rights will expire on March 22, 2011.

 

InJune 2004, the Company completed a two-for-one split of its common stock, whichwas distributed in the form of a stock dividend.  Stockholders of the Company’s common stockreceived one additional share for every share of common stock held on therecord date of June 4, 2004.  After thestock split, each share of common stock outstanding or thereafter issuedincludes or will include one-half of a Series A Junior Participating PreferredStock purchase right.  The Company hasrestated its financial information to reflect this split for all periodspresented.

 

InNovember 1992, the Company issued 1,400,000 shares of $2.28 CumulativePreferred Stock with a liquidation preference of $25 per share, at a publicoffering price of $25 per share, redeemable at the Company’s option on or afterNovember 15, 1997.  In 2000, the Companyre-purchased 39,190 of the $2.28 Cumulative Preferred Stock for a totalconsideration of approximately $1.0 million. In 2001, the Company purchased in open market transactions an additional5,100 shares of this preferred stock for a total cost, including broker commissions,of approximately $129,000, or an average of $25.29 per share of this preferredstock.  In December 2001, the Companyredeemed 808,864 shares of this preferred stock at the liquidation preferencefor total proceeds of $20.6 million including accrued and unpaiddividends.  In December 2002, the Companyredeemed the remaining 546,846 shares of this preferred stock at theliquidation preference for total proceeds of $14.0 million including accruedand unpaid dividends.

 

InFebruary 1994, the Company issued 2,760,000 shares of $2.625 Cumulative ConvertiblePreferred Stock with a liquidation preference of $50 per share, at a publicoffering price of $50 per share, redeemable at the Company’s option on or afterFebruary 16, 1997 and convertible at the option of the holder into Common Stockat a per share conversion price of $19.88. In November 2003 and in December 2003, the Company issued notices ofredemption for approximately 700,000 and 800,000 shares, respectively, of its$2.625 cumulative convertible preferred stock at the liquidation preferenceplus 0.525% premium.  In relation to thenotice of redemption issued in November 2003, in December 2003 a total of1,701,400 common shares were issued and $1.2 million was paid in cash tocomplete the redemption.  In relation tothe notice of redemption issued in December 2003, in January 2004 a total of1,979,244 common shares were issued and $672,000 was paid in cash.  In March 2004, the Company issued anadditional notice of redemption for the remaining 1,260,000 shares of its$2.625 cumulative convertible preferred stock. In April 2004, the Company issued an additional 3,113,582 shares ofcommon stock to holders who elected to convert their shares and paid $391,000in cash proceeds to complete this redemption. After these redemptions, the $2.625 cumulative convertible preferredstock was delisted from trading on the New York Stock Exchange and applicationwas made to the SEC to deregister such stock.

 

***Significant Projects and Asset Divestitures***

 

***Acquisition of San Juan Properties. ***In October 2004, the Company acquired oil and gas assets in the SanJuan Basin of New Mexico for approximately $82.2 million, plus assumedliabilities.  The purchase also includedrelated gathering systems, which are connected to the Company’s San Juan Riverplant.  In connection with thisacquisition, the Company increased Oil and gas properties and equipment by$72.6 million and increased Gas gathering, processing and transportation by$13.3 million.

 

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***Acquisition and Disposition of GatheringSystems.***  Effective February 1, 2003, the Companyacquired several gathering systems in Wyoming, primarily located in the GreaterGreen River Basin with smaller operations in the Powder River and Wind RiverBasins, for a total of $37.1 million. Several of the systems located in the Powder River did not integratedirectly into the Company’s existing systems, and accordingly these systemswere sold in 2003.  During the year endedDecember 31, 2003, the income generated by the assets sold was immaterial.

 

##### ***Acquisition ofSand Wash Properties.***  In August 2003, through the acquisition ofthe stock of a private corporation for $12.9 million, the Company acquiredadditional reserves, production and acreage in the Sand Wash Basin.  The assets of this private entity consistedprimarily of the remaining interests in various Sand Wash properties operatedby the Company.

##### *** ***

***Toca Processing Facility. ***In September 2002, the Company sold its Toca processing facility inLouisiana.  The sale price was $32.2million and resulted in a pre-tax loss of approximately $230,000.  During the year ended December 31, 2002, thisfacility generated net after-tax earnings of approximately $683,000, or $.01per share of common stock, respectively. The Company believes the results from this facility are immaterial forseparate presentation as a discontinued operation.  Approximately $15.0 million of the proceedsreceived from this asset sale were initially used to reduce amounts outstandingon the Company’s revolving credit facility. At December 31, 2002, the remaining amount of $17.2 million was ondeposit with a trustee in anticipation of the completion of a like-kindexchange transaction and was reflected on the Consolidated Balance Sheet underthe caption Other current assets.  Thesefunds, along with additional amounts drawn on the Company’s revolving creditfacility, were used in a February 2003 acquisition of several gathering systemsdescribed above.

 

***Powder River Basin Coal Bed Methane. ***The Company continues to develop its Powder River Basin coal bed methane reservesand expand the associated gathering system. During the years ended December 31, 2004, 2003 and 2002, the Companyexpended approximately $106.9 million, $53.3 million and $71.0 million,respectively, on this project.

 

***Greater Green River Basin.*** TheCompany’s assets in southwest Wyoming and northwest Colorado include theGranger and Lincoln Road facilities (collectively the “Granger Complex”), theCompany’s 50% equity interest in Rendezvous Gas Services, L.L.C. (“Rendezvous”),the Red Desert facility, Wamsutter gathering, and production from the JonahField, Pinedale Anticline and Sand Wash areas. During the years ended December 31, 2004, 2003 and 2002, the Companyexpended approximately $63.9 million, $102.5 million and $37.1 million,respectively, in this area.

 

**NOTE 2 – RESTATEMENT OF CONSOLIDATED FINANCIAL STATEMENTS**

 

Upon adoption of FASB Statement No.133, “Accounting for Derivative Instruments and Hedging Activities” (“FAS 133”)in 2001, the Company analyzed its gas storage and gas transportation contractsin detail, and determined that these contracts had the characteristics of aderivative as described in FAS 133.  Thetreatment of these contracts as derivatives has been consistently applied sinceadoption of FAS 133 as reflected in the Company’s consolidated financialstatements.  Historically, the Companyrecorded these contracts at fair value with the changes in fair value reflectedin earnings. On November 8, 2005, after the release of its third quarter 2005results and prior to the filing of the Form 10-Q for the quarter endedSeptember 30, 2005, it came to the Company’s attention that these contracts maynot meet the definition of a derivative. On November 21, 2005, the Company announced that its management and itsaudit committee had completed a review of the accounting treatment of its gasstorage and gas transportation contracts and determined that these contracts donot meet the definition of a derivative under generally accepted accountingprinciples. Specifically, after a detailed review of the contracts and themarket for those contracts, the Company determined that these contracts do notmeet the definition of a derivative as: (i) the market for these types ofcontracts is not sufficiently liquid for the Company to receive fair value in aready market and (ii) if any contract is assigned, there is no assurance thatthe Company will be relieved of its rights and obligations under thatcontract.  Accordingly, the Company hasrestated its audited financial statements for the years from 2001 through 2004included herein and the beginning retained earnings as of January 1, 2002.

 

Historically,the non-cash mark-to-market valuation of the gas storage and transportationcontracts which were considered to be derivatives effectively offset non-cashmark-to-market changes to the forward derivative contracts to sell our storedor transported natural gas.  The changesin both of these mark-to-market valuations were reflected in Price riskmanagement activities on the Consolidated statement of operations and asreported in the marketing segment.  Afterthe adjustments to correct the prior accounting for the gas storage and gastransportation contracts, the non-cash mark-to-market of the forward derivativecontract on the sale of gas will fluctuate through earnings with changes inmarket prices and will not be offset by a corresponding mark-to-market on thegas storage and transportation contracts. As the stored or transported natural gas is sold and the forward salederivatives are settled, we will realize the benefit of the storage andtransportation transactions through earnings.

 

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Thefollowing table summarizes the impact of the accounting adjustments necessaryto correct the treatment of storage and transportation contracts on the Company’spreviously reported Consolidated Financial Statements as reported in itsoriginally reported 2004 Annual Report on Form 10-K as filed on March 14, 2005(000s):

 
| ** **                                       | ** ** | **Year Ended  December 31,** | ** ** |
|--------------------------------------------------|------------|------------------------------|------------|
| ** **                                       | ** ** | **2004**                     | ** ** | **2003** | ** ** | **2002** | ** ** |
| Net income  as previously reported               |       | $                            | 119,215    |   | $ | 84,219 |   | $ | 50,589 |   |
| Accounting  correction for derivatives (pre-tax) |       | 13,455                       |       | 5,741 |   | (25,952 | ) |
| Tax impact of above                              |       | (4,911                       | )          | (2,025 | ) | 9,469 |   |
| Net income as  restated                          |       | $                            | 127,759    |   | $ | 87,935 |   | $ | 34,106 |   |

 

Thefollowing is a summary of the impact of these accounting adjustments on theCompany’s Consolidated Balance Sheet and Consolidated Statement of Operationsas previously reported in the 2004 Annual Report on Form 10-K as filed on March14, 2005.  The aforementioned restatementadjustments do not affect cash flows provided by operating activities, net cashused in investing activities and net cash provided by (used in) financingactivities, although certain components of cash flows provided by operatingactivities have been restated.

 
| ** **                                                   | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                   | ** ** | **2004**                    | ** ** | **2003** | ** ** |
| ** **                                                   | ** ** | **As**                      | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** |
| **(000s)**                                                   | ** ** | **Reported**                | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** |
| Assets:                                                      |       |                        |       |   |   |   |   |   |   |
| Current  assets from price risk management activities        |       | 22,238                      |       | 19,893 |   | 17,149 |   | 6,857 |   |
| Deferred  income taxes                                       |       | —                      |       | — |   | — |   | 946 |   |
| Long-term assets from price risk management  activities      |       | 618                         |       | 249 |   | 1,466 |   | 1,466 |   |
| Total Assets                                                 |       | $                           | 1,840,112  |   | $ | 1,837,398 |   | $ | 1,460,524 |   | $ | 1,451,178 |   |
|                                                         |       |                        |       |   |   |   |   |   |   |
| Liabilities  and Stockholder’s equity                   |       |                        |       |   |   |   |   |   |   |
| Current liabilities from price risk  management activities   |       | 11,099                      |       | 4,321 |   | 10,603 |   | 9,465 |   |
| Deferred income taxes                                        |       | —                      |       | 5,618 |   | — |   | — |   |
| Long-term liabilities from price risk  management activities |       | 417                         |       | 180 |   | 1,304 |   | 1,304 |   |
| Deferred income taxes payable, net                           |       | 247,893                     |       | 243,835 |   | 176,673 |   | 174,268 |   |
| Total liabilities                                            |       | 1,158,084                   |       | 1,152,629 |   | 898,015 |   | 894,472 |   |
|                                                         |       |                        |       |   |   |   |   |   |   |
| Stockholders’ equity                                    |       |                        |       |   |   |   |   |   |   |
| Retained earnings                                            |       | 278,687                     |       | 281,428 |   | 173,076 |   | 167,273 |   |
| Total stockholders’ equity                              |       | 682,028                     |       | 684,769 |   | 562,509 |   | 556,706 |   |
| Total liabilities and stockholders’ equity              |       | $                           | 1,840,112  |   | $ | 1,837,398 |   | $ | 1,460,524 |   | $ | 1,451,178 |   |

 

ConsolidatedStatement of Operations

 
| ** **                                                                                     | ** ** | **Year Ended December 31,** | ** ** |
|------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                     | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                     | ** ** | **As**                      | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** |
| **(000s)**                                                                                     | ** ** | **Reported**                | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** |
| Revenues:                                                                                      |       |                        |       |   |   |   |   |   |   |   |   |   |   |
| Price risk management activities                                                               |       | 6,596                       |       | 20,051 |   | (22,126 | ) | (16,386 | ) | (9,333 | ) | (35,285 | ) |
| Total revenues                                                                                 |       | 3,069,713                   |       | 3,083,168 |   | 2,874,010 |   | 2,879,751 |   | 2,489,698 |   | 2,463,746 |   |
|                                                                                           |       |                        |       |   |   |   |   |   |   |   |   |   |   |
| Income before income taxes                                                                     |       | 183,268                     |       | 196,723 |   | 144,536 |   | 150,277 |   | 80,703 |   | 54,751 |   |
| Provision for income taxes:                                                                    |       |                        |       |   |   |   |   |   |   |   |   |   |   |
| Deferred                                                                                       |       | 66,289                      |       | 71,200 |   | 49,326 |   | 51,351 |   | 19,614 |   | 10,145 |   |
| Total provision for income taxes                                                               |       | 68,767                      |       | 73,678 |   | 53,593 |   | 55,618 |   | 30,114 |   | 20,645 |   |
| Income before cumulative effect of change  in accounting principle                             |       | 114,501                     |       | 123,045 |   | 90,943 |   | 94,659 |   | 50,589 |   | 34,106 |   |
| Net income                                                                                     |       | $                           | 119,215    |   | $ | 127,759 |   | $ | 84,219 |   | $ | 87,935 |   | $ | 50,589 |   | $ | 34,106 |   |
| Income attributable to common stock                                                            |       | $                           | 118,380    |   | $ | 126,924 |   | $ | 77,378 |   | $ | 81,094 |   | $ | 41,391 |   | $ | 24,908 |   |
| Earnings per share of common stock before  cumulative effect of change in accounting principle |       | 1.56                        |       | 1.68 |   | 1.27 |   | 1.32 |   | 0.63 |   | 0.38 |   |
| Earnings per share of common stock                                                             |       | 1.63                        |       | 1.75 |   | 1.17 |   | 1.22 |   | 0.63 |   | 0.38 |   |
| Income attributable to common stock -  assuming dilution                                       |       | 118,380                     |       | 126,924 |   | 84,219 |   | 87,935 |   | 41,391 |   | 24,908 |   |
| Earnings per share of common stock -  assuming dilution                                        |       | $                           | 1.61       |   | $ | 1.73 |   | $ | 1.13 |   | $ | 1.18 |   | $ | 0.62 |   | $ | 0.37 |   |

 

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Thenet impact of this restatement was to adjust Net income by $8.5 million, $3.7million, and ($16.5) million for each of the years ended December 31, 2004,2003 and 2002, respectively.  The netimpact of this restatement was to adjust Earnings per share of common stock –assuming dilution by $0.12, $0.05, and ($0.25) for each of the years endedDecember 31, 2004, 2003 and 2002, respectively. Refer to Note 12 for a summary of the impact of the restatement on the2004 and 2003 quarterly periods.

 

**NOTE3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**

 

Thesignificant accounting policies followed by the Company and its wholly ownedsubsidiaries are presented here to assist the reader in evaluating thefinancial information contained herein. The Company’s accounting policies are in accordance with generallyaccepted accounting principles.

 

***Principles of Consolidation***.  The consolidated financial statements includethe accounts of the Company and the Company’s wholly owned subsidiaries. Allmaterial inter-company transactions have been eliminated in consolidation.  The Company’s interest in certainnon-controlled investments is accounted for by the equity method.

 

***Inventories.*** The cost of gas and NGL inventories aredetermined by the weighted average cost method on a location-by-locationbasis.  Residue and NGL inventory coveredby derivative contracts is accounted for on a specific identificationbasis.  Product inventory includes $88.8million and $67.1 million of gas and $2.0 million and $1.6 million of NGLs atDecember 31, 2004 and 2003, respectively.

 

***Property and Equipment.*** Property and equipment is recorded at cost,including capitalized interest.  Interestincurred during the construction period of new projects is capitalized andamortized over the life of the associated assets.  Repair and maintenance of property andequipment is expensed as incurred.

 

Depreciationis provided using the straight-line method based on the estimated useful lifeof each facility, which ranges from three to 35 years.  Useful lives are determined based on theshorter of the life of the equipment or the reserves serviced by the equipment.The cost of acquired gas purchase contracts is amortized using thestraight-line method or units of production.

 

Inconnection with the adoption of SFAS No. 143 on January 1, 2003, a review wascompleted of the Company’s operating assets. As a result of this evaluation, the operating lives and salvage valuesof the associated equipment was reevaluated, and the Company extended theuseful life of many of its operating assets and adjusted the estimated salvagevalue of its operating equipment.  Theseadjustments resulted in an approximate $10.7 million, or $0.10 per share ofcommon stock - assuming dilution, decrease in depreciation, depletion andamortization in the year ended December 31, 2003, from the expense calculatedusing the previous useful lives.  Theadjustments to the salvage value and depreciable lives of the Company’s assetsare treated as a revision of an estimate and are accounted for on a prospectivebasis.

 

In December 2004, theCompany placed into service a new 200 MMcf per day processing facility adjacentto its Granger Complex.  This facilitystraddles a third-party regulated pipeline and processes its gas to meetpipeline specifications.  The facility’scapacity is contractually committed to this service, and the contract for processingthis gas requires a monthly charge to be paid by the pipeline regardless of theamount of gas processed.  These feestotal approximately $2.2 million per year and the contract has a term of tenyears.  In accordance with EITF 01-08, “DeterminingWhether an Arrangement Contains a Lease”, facilities that are built to provideservices to one specific customer should be evaluated for potential treatmentas capital leases.  The Company hasdetermined that accounting for this contract as a capital lease isappropriate.  On the Consolidated BalanceSheet, at December 31, 2004 related to this transaction, the Company hadreceivables of $22.4 million in Other assets for the fixed portion of thenon-current future lease payments plus the unguaranteed residual value at theend of the lease term and $2.2 million in Other Current assets. The Companyalso had deferred revenue totaling $17.8 million in Other long-term liabilitiesfor the non-current deferred revenue and $2.0 million in Accrued expenses forthe current portion.

 

***Oil and Gas Properties and Equipment.*** The Company follows the successful effortsmethod of accounting for oil and gas exploration and production activities.Acquisition costs, development costs and successful exploration costs arecapitalized.  Upon surrender orimpairment of undeveloped properties, the original cost is charged againstincome.  Developed and undevelopedleaseholds with proved reserves are depleted by the units-of-production methodbased on estimated proved reserves. Development

 

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costsand related equipment are depleted and depreciated by the units-of-productionmethod based on estimated proved developed reserves.

 

Exploratorylease rentals and geological and geophysical costs are charged to expense asincurred.  Exploratory drilling costs arecapitalized when incurred pending the determination of whether a well has foundproved reserves.  A determination ofwhether a well has found proved reserves is made shortly after drilling iscompleted. The determination is based on a process that relies oninterpretations of available geological, geophysical, and engineeringdata.  If an exploratory well isdetermined to be unsuccessful, the capitalized drilling costs will be chargedto expense in the period the determination is made.  If an exploratory well requires a majorcapital expenditure before production can begin, the cost of drilling theexploratory well will continue to be carried as an asset pending determinationof whether proved reserves have been found only as long as: i) the well hasfound a sufficient quantity of reserves to justify its completion as aproducing well if the required capital expenditure is made, and ii) drilling ofadditional exploratory wells is under way or firmly planned for the nearfuture. If the drilling of additional exploratory wells in the area is notunder way or firmly planned, or if the well has not found a commerciallyproducible quantity of reserves, the exploratory well is assumed to be impaired,and its costs are charged to expense.

 

As of December 31, 2004, theCompany has included disclosures related to suspended well costs.  The Company evaluated all existingcapitalized exploratory well costs under the provisions of the pending FSP. Thefollowing table reflects the net changes in capitalized exploratory well costsduring the years ended December 31, 2004, 2003 and 2002 (000s).

 
| ** **                                                                                           | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Beginning balance at January 1,                                                                      |       | $        | 25,083     |     | $          | 18,795   |       | $ | 7,239 |   |
| Additions to capitalized exploratory well  costs pending the determination of proved reserves        |       | 30,683   |       | 12,804   |       | 11,830   |       |
| Reclassifications to wells, facilities, and  equipment based on the determination of proved reserves |       | (6,900   | )          | (4,655   | )          | (49      | )          |
| Capitalized exploratory well costs charged  to expense                                               |       | (320     | )          | (1,861   | )          | (225     | )          |
| Ending balance at December 31,                                                                       |       | $        | 48,546     |     | $          | 25,083   |       | $ | 18,795 |   |

 

Substantiallyall of the Company’s exploratory wells that have been capitalized for a periodgreater than one year are located in the Powder River Basin.  In this basin, the Company drills wells intovarious coal seams.  In order to producegas from the coal seams, a period of dewatering lasting from a few totwenty-four months, or in some cases longer, is required prior to obtainingsufficient gas production to justify capital expenditures for compression andgathering, and to classify the reserves as proven.  In order to accelerate the dewatering time,the Company drills additional exploratory wells in these areas.

 

EffectiveJanuary 1, 2004, the Company redefined the asset groupings for the calculationof depreciation and depletion on its oil and gas properties from a well-by-wellbasis to a field wide basis for each of the Jonah, Pinedale and Sand Washfields and to a grouping of all wells drilled into related coal seams for thePowder River Basin. This change resulted in an increase in Depreciation,depletion and amortization expense of $4.9 million, or $.07 per share of commonstock - assuming dilution, in 2004.  Thechange in the depreciation and depletion methodology is treated as a change inaccounting principle.  Accordingly, theAccumulated depreciation, depletion and amortization for these assets has beenrecalculated under the new methodology. The cumulative effect of the change in depreciation and depletionmethodology for the year ended December 31, 2004 is a benefit of $4.7 million,net of tax, or $0.06 per share of common stock - assuming dilution, and ispresented in the Consolidated Statement of Operations under the caption Cumulativeeffect of change in accounting principle, net of tax.

 

***Income Taxes.*** Deferred income taxes reflect the impact oftemporary differences between amounts of assets and liabilities for financialreporting purposes and such amounts as measured by tax laws.  These temporary differences are determined andaccounted for in accordance with SFAS No. 109, “Accounting for Income Taxes.”

 

***Foreign Currency Adjustments. *** The Company has a subsidiary in Canada.  The functional currency of this subsidiary isthe Canadian dollar.  The assets andliabilities associated with this subsidiary are translated into U.S. dollars atthe exchange rate as of the balance sheet date and revenues and expenses at theweighted-average of exchange rates in effect during each reporting period.  The translation gains for the years endedDecember 31, 2004, 2003 and 2002 were $816,000, $1.2 million and $283,000,respectively, net of tax.

 

***Revenue Recognition.*** Inthe Gas Gathering, Processing and Treating segment, the Company recognizesrevenue for its services at the time the service is performed. The Companyrecords revenue from its gas and NGL marketing activities, including sales ofthe Company’s equity production, upon transfer of title.  In accordance with EITF 03-11, the Company records revenue on its physical gas andNGL marketing activities on a gross basis versus sales net of purchases basisbecause it obtains title to all the gas and NGLs that it buys includingthird-party purchases, bear the risk of loss and credit exposure on thesetransactions, and it is the Company’s intention upon entering these contractsto take physical delivery of the product. Gas imbalances on the Company’s production are

 

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accountedfor using the sales method.  Gasimbalances on the Company’s production at December 31, 2004 and 2003 areimmaterial.  For its marketing activitiesthe Company utilizes mark-to-market accounting for its derivatives.  In the Transportation segment, the Companyrealizes revenue on a monthly basis from firm capacity contracts under whichthe shipper pays for transport capacity whether or not the capacity is used andfrom interruptible contracts where a fee is charged based upon volumes receivedinto the pipeline.  See additional discussionin Note 9 – Business Segments and Related Information.

 

Inorder to minimize transportation costs or make product available at a locationof our customer’s preference, from time to time, the Company will enter intoarrangements to buy product from a party at one location and arrange to sell alike quantity of product to this same party at another location.  In accordance with EITF 03-11, the Company records revenue on these transactions ona gross basis versus sales net of purchases basis because it obtains title tothe product that it buys, bears the risk of loss, credit and performanceexposure on these transactions, and the Company takes physical delivery of theproduct.  For the years ended December31, 2004, 2003 and 2002, the Company recorded revenues of $92.6 million, $95.5million and $39.8 million, respectively, and product purchases of $86.7million, $84.2 million and $36.3 million, respectively, for transactions whichwere entered into concurrently and with the intent to buy and sell like quantitieswith the same counter party at different locations and at market prices atthose locations.

 

***Accounting for Derivative Instruments andHedging Activities.*** The Company recognizes the change in the market value of allderivatives, as either assets or liabilities in the statement of financialposition and measures those instruments at fair value.  Changes in the fair value of derivatives arerecorded each period in current earnings or other comprehensive incomedepending upon the nature of the underlying transaction.

 

***Comprehensive Income.*** Accumulated other comprehensive income isreported as a separate component of stockholders’ equity.  Accumulated other comprehensive incomeincludes cumulative translation adjustments for foreign currency transactionsand the change in fair market value of cash flow hedges.  The Company’s accumulated derivative gains atDecember 31, 2004 totaled $410,000 and will be reclassified into earningsduring 2005. These items are separately reported on the Consolidated Statementof Changes in Stockholders’ Equity.

 

***Impairment of Long-Lived Assets.*** The Company reviews its long-lived assetswhenever events or changes in circumstances indicate that the carrying value ofsuch assets may not be recoverable.  TheCompany’s assets are evaluated at the lowest level for which identifiable cashflows are largely independent of the cash flows of other assets.  In order to determine whether an impairmentexists, the Company compares its net book value of the asset to theundiscounted expected future net cash flows, determined by applying futureprices estimated by management over the shorter of the lives of the facilitiesor the reserves supporting the facilities. If an impairment exists, write-downsof assets are based upon expected future net cash flows discounted using aninterest rate commensurate with the risk associated with the underlying asset.

 

The Company reviewsits assets at the plant facility, the related group of plant facilities or theoil and gas producing field or producing coal seam level. Prior to 2003, theCompany completed its impairment analysis on its oil and gas producingproperties on an individual well-by-well basis. In the fourth quarter of 2003, the Company conducted a review of its oiland gas producing properties, which included an evaluation of the geologicformations and production history for the Company’s producing properties.  This review indicated that the cash flowsfrom individual wells in its operating areas were not largely independent ofthe cash flows of other wells producing in the same field or coal seam.  As a result of this review, the Companyredefined the asset groupings to a field wide analysis for impairment for theJonah, Pinedale and Sand Wash Basins and a grouping of all wells drilled intorelated coal seams for the Powder River Basin. These asset groupings were used to determine if any impairment wasnecessary for the years ended December 31, 2004 and 2003, and it was determinedthat none of the asset groups were impaired. In addition, as the previous method of asset grouping was notappropriate under generally accepted accounting principles, a reevaluation ofthe impairment test for the year ended December 31, 2002 was completedutilizing the new asset groups.  Thatrevised impairment test also did not result in an impairment of the Company’sproducing properties for that period, and accordingly, the correction of thiserror in the method of application of the accounting principle relating toasset grouping for testing the impairment of producing oil and gas propertiesdid not have any financial statement impact for the year ended December 31,2002.

 

***Cumulative Effect of a Change in AccountingPrinciple.*** In June 2001, the FASB issued SFAS No.143 “Accounting for Asset Retirement Obligations.”  SFAS No. 143 was effective for fiscal yearsbeginning after June 15, 2002.  SFAS No.143 establishes accounting standards for recognition and measurement of aliability for an asset retirement obligation and the associated assetretirement cost.  The Company adoptedSFAS No. 143 on January 1, 2003 and recorded an $11.5 million increase toProperty and equipment, a $4.4 million increase to Accumulated depreciation,depletion and amortization, a $17.8 million increase to Other long-termliabilities and a $6.7 million non-cash, after-tax loss from the Cumulativeeffect of a change in accounting principle.

 

Thefollowing is a reconciliation of the asset retirement obligation for the yearsended December 31, 2004 and 2003 (000’s):

 

56

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| ** **                                              | ** ** | **2004** | ** ** | **2003** | ** ** |
|---------------------------------------------------------|------------|----------|------------|----------|------------|
| Asset  retirement obligation as of January 1            |       | $        | 20,644     |     | $          | 17,801 |   |
| Liability  accrued upon capital expenditures            |       | 3,562    |       | 1,994    |       |
| Changes due  to revisions of estimated retirement costs |       | 7,262    |       | —   |       |
| Liability  settled                                      |       | (139     | )          | (306     | )          |
| Accretion of  discount expense                          |       | 1,335    |       | 1,155    |       |
| Asset  retirement obligation as of December 31          |       | $        | 32,664     |     | $          | 20,644 |   |

 

Exclusiveof assets disposed of during 2002, if the Company had adopted SFAS No. 143 asof January 1, 2002, it estimates that the asset retirement obligation at thatdate would have been $15.7 million, based on the same assumptions used in itscalculation of the obligation at January 1, 2003.  The estimated 2002 pro forma effect of ahypothetical January 1, 2002 adoption of SFAS No. 143 on net income andearnings per share, for annual and interim periods, is not material.

 

***Earnings Per Share of Common Stock.*** Earnings per share of common stock arecomputed by dividing income attributable to common stock by the weighted averageshares of common stock outstanding.  Inaddition, earnings per share of common stock - assuming dilution is computed bydividing income attributable to common stock by the weighted average shares ofcommon stock outstanding as adjusted for potential common shares.  Income attributable to common stock is netincome less preferred stock dividends. The following table presents the dividends declared by the Company foreach class of its outstanding equity securities (000’s, except per shareamounts):

 
| ** **                     | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------|------------|-----------------------------|------------|
| ** **                     | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| Common Stock                   |       | $                           | 12,847     |   | $ | 6,684 |   | $ | 6,603 |   |
| Preferred  Stock               |       | 835                         |       | 6,783 |   | 8,201 |   |
| Total  Dividends Declared      |       | $                           | 13,682     |   | $ | 13,467 |   | $ | 14,804 |   |
|                           |       |                        |       |   |   |   |   |
| Dividends  Declared Per Share: |       |                        |       |   |   |   |   |
| Common Stock                   |       | $                           | 0.18       |   | $ | 0.10 |   | $ | 0.10 |   |
| Preferred  Stock               |       | $                           | 0.81       |   | $ | 2.82 |   | $ | 2.68 |   |

 

Commonstock options and, until the final conversion or redemption in April 2004, theCompany’s $2.625 cumulative convertible preferred stock are potential commonshares.  The following is areconciliation of the weighted average shares of common stock outstanding tothe weighted average common shares outstanding – assuming dilution.  The share information presented reflects thetwo-for-one common stock split completed in 2004.

 
| ** **                                                               | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------|------------|-----------------------------|------------|
| ** **                                                               | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| Weighted  average shares of common stock outstanding                     |       | 72,419,980                  |       | 66,412,228 |   | 65,905,086 |   |
| Potential  common shares from:                                           |       |                        |       |   |   |   |   |
| Common stock options                                                     |       | 1,074,767                   |       | 1,413,354 |   | 1,310,034 |   |
| $2.625 Cumulative Convertible Preferred  Stock                           |       | —                      |       | 6,868,838 |   | — |   |
| Weighted average shares of common stock  outstanding - assuming dilution |       | 73,494,747                  |       | 74,694,420 |   | 67,215,120 |   |

 

Thenumerators and the denominators for the prior periods were adjusted to reflectthese potential common shares and any related preferred dividends incalculating fully diluted earnings per share.

 

***Concentration of Credit Risk.*** Financial instruments that potentially subjectthe Company to concentrations of credit risk consist principally of tradeaccounts receivable and OTC swaps and options. The risk is limited due to the large number of entities comprising theCompany’s customer base and their dispersion across geographic locations.  The Company records its trade accountsreceivable at the invoiced amount, which does not include interest.

 

TheCompany continually monitors and reviews the credit exposure to its marketingcounter parties.  This review hasresulted in a reduction in sales volumes with various counter parties in orderto maintain acceptable credit exposures. During 2002, the Company reserved approximately $1.6 million fordoubtful accounts through a charge to Selling and administrative expense.  During 2004 and 2003, the Company did notincrease its allowance for doubtful accounts. The Company records an allowance for doubtful accounts on a specificidentification basis, and the balance in the reserve for doubtful accounts was$648,000 and $2.3 million, respectively, at December 31, 2004 and 2003.

 

***Cash and Cash Equivalents.*** Cash and cash equivalents includes all cashbalances and highly liquid investments with an original maturity of threemonths or less.  At December 31, 2004 and2003, the Company had outstanding disbursements to vendors and producerstotaling $72.0 million and $40.4 million, respectively, which were reclassifiedto Accounts payable.  The change in

 

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outstandingdisbursements to vendors and producers is presented as a component of Cashflows from financing activities in the Statement of Cash Flows.

 

***Supplementary Cash Flow Information.*** Interest paid was $22.3 million, $28.0million, and $28.1million, respectively, for the years ended December 31, 2004,2003 and 2002.  Capitalized interestassociated with construction of new projects was $2.5 million, $1.8 million and$1.7 million, respectively, for the years ended December 31, 2004, 2003 and2002.  Income taxes paid were $9.4million, $11.1 million and $1.5 million, respectively, for the years endedDecember 31, 2004, 2003 and 2002.  Alease receivable of $24.6 million and an unearned revenue liability of $19.8million were recorded for the year ending December 31, 2004 for the lease ofthe Granger 200MMcf per day straddle plant. Asset retirement obligation assets of $10.7 million were recorded forcapitalized assets and asset retirement obligation liabilities of $12.1 millionwere recorded for the year ending December 31, 2004.

 

***Stock Compensation.*** Aspermitted under SFAS No. 123, “Accounting for Stock-Based Compensation”, theCompany has elected to continue to measure compensation costs for stock-basedemployee compensation plans as prescribed by Accounting Principles BoardOpinion No. 25, “Accounting for Stock Issued to Employees.”  The Company has complied with the pro formadisclosure requirements of SFAS No. 123 as required under thepronouncement.  The Company realizes anincome tax benefit for any amount the employee declares as ordinary income.  The tax benefit related to the amount ofordinary income that exceeds the amount recognized by the Company totals $2.5million and was credited to additional paid-in capital.

 

TheCompany had options covering 27,000, 49,438 and 119,000 common sharesoutstanding at December 31, 2004, 2003 and 2002, respectively, which weretreated as re-priced options.  TheCompany is required to record compensation expense (if not previously accrued)equal to the number of unexercised re-priced options multiplied by the amountby which its stock price at the end of any quarter exceeds $10.5021 pershare.  Based on the Company’s per sharestock price at December 31, 2004, 2003 and 2002 of $29.25, $23.63 and $18.43,respectively; expense of $310,000, $529,000 and $224,000 was recorded in theyears ended December 31, 2004, 2003 and 2002, respectively.

 

SFASNo. 123 encourages companies to record compensation expense for stock-basedcompensation plans at fair value.  Aspermitted under SFAS No. 123, the Company has elected to continue to measurecompensation costs for such plans as prescribed by APB No. 25.  Such information was only calculated for theoptions granted under the 1999 Stock Option Plan, the 2002 Stock Option Planand the 2002 Directors’ Plan, as there were no grants under any other plans.

 

Thefollowing is a summary of the options to purchase the Company’s common stockgranted during the years ended December 31, 2004, 2003 and 2002,respectively.  

 
| ** **                 | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------|------------|-----------------------------|------------|
| ** **                 | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| 1999 Stock Option Plan     |       | 140,876                     |       | — |   | 340,000 |   |
| 2002 Stock Option Plan     |       | 956,841                     |       | 1,129,900 |   | 375,994 |   |
| 2002  Directors’ Plan |       | 32,000                      |       | 36,000 |   | 36,000 |   |
| Total  options granted     |       | 1,129,717                   |       | 1,165,900 |   | 751,994 |   |

 

Thefollowing is a summary of the weighted average fair value per share of theoptions granted during the years ended December 31, 2004, 2003 and 2002,respectively.

 
| ** **                 | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------|------------|-----------------------------|------------|
| ** **                 | ** ** | **2004**                    | ** ** | **2003** | ** ** | **2002** | ** ** |
| 1999 Stock Option Plan     |       | $                           | 13.12      |   | — |   | $ | 8.68 |   |
| 2002 Stock Option Plan     |       | $                           | 13.09      |   | $ | 9.77 |   | $ | 8.72 |   |
| 2002  Directors’ Plan |       | $                           | 12.13      |   | $ | 10.70 |   | $ | 11.25 |   |

 

Thesevalues were estimated using the Black-Scholes option-pricing model with thefollowing assumptions:

 
| ** **                     | ** ** | **1999 Stock Option Plan** | ** ** | **2002 Stock Option Plan** | ** ** | **2002 Directors’ Plan** | ** ** |
|--------------------------------|------------|----------------------------|------------|----------------------------|------------|-------------------------------|------------|
| ** **                     | ** ** | **2004**                   | ** ** | **2003**                   | ** ** | **2002**                      | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| Risk-free  interest rate       |       | 3.74                       | %          | —                     |       | 3.40                          | %          | 3.77 | % | 3.47 | % | 3.41 | % | 4.46 | % | 2.59 | % | 3.40 | % |
| Expected  life (in years)      |       | 7                          |       | —                     |       | 7                             |       | 7 |   | 7 |   | 7 |   | 7 |   | 7 |   | 7 |   |
| Expected  volatility           |       | 39                         | %          | —                     |       | 55                            | %          | 39 | % | 53 | % | 55 | % | 40 | % | 54 | % | 56 | % |
| Expected dividends (quarterly) |       | $                          | 0.05       |                       | —     |                          | $          | 0.025 |   | $ | 0.05 |   | $ | 0.025 |   | $ | 0.025 |   | $ | 0.05 |   | $ | 0.025 |   | $ | 0.025 |   |
|                                |            |                            |            |                            |            |                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

Hadcompensation expense for the Company’s 2004, 2003 and 2002 grants forstock-based compensation plans been determined consistent with the fair valuemethod under SFAS No. 123, the Company’s net income, income attributable tocommon stock, earnings

 

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pershare of common stock and earnings per share of common stock - assumingdilution would approximate the pro forma amounts below (000s, except per shareamounts):

 
| ** **                                                                                                                                     | ** ** | **2004 Restated** | ** ** | **2003 Restated** | ** ** | **2002 Restated** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|-------------------|------------|-------------------|------------|
| ** **                                                                                                                                     | ** ** | **As  Reported**  | ** ** | **Pro forma**     | ** ** | **As  Reported**  | ** ** | **Pro forma** | ** ** | **As  Reported** | ** ** | **Pro forma** | ** ** |
| Net income                                                                                                                                     |       | $                 | 127,759    |              | $          | 122,597           |       | $ | 87,935 |   | $ | 84,495 |   | $ | 34,106 |   | $ | 31,495 |   |
| Net income attributable to common stock                                                                                                        |       | 126,924           |       | 121,762           |       | 81,094            |       | 77,654 |   | 24,908 |   | 22,297 |   |
| Earnings per share of common stock                                                                                                             |       | 1.75              |       | 1.68              |       | 1.22              |       | 1.17 |   | 0.38 |   | 0.34 |   |
| Earnings per share of common stock -  assuming dilution                                                                                        |       | 1.73              |       | 1.66              |       | 1.18              |       | 1.13 |   | 0.37 |   | 0.33 |   |
| Stock-based employee compensation cost, net  of related tax effects, included in net income                                                    |       | $                 | 428        |              | N/A        |              | $          | 576 |   | N/A |   | $ | 375 |   | N/A |   |
| Stock-based employee compensation cost, net  of related tax effects, includable in net income if the fair value based  method had been applied |       | N/A               |       | $                 | 5,590      |              | N/A        |   | $ | 4,016 |   | N/A |   | $ | 2,986 |   |

 

Thefair market value of the options at grant date is amortized over theappropriate vesting period for purposes of calculating compensation expense.

 

***Use of Estimates and Significant Risks.*** The preparation of consolidated financialstatements in conformity with generally accepted accounting principles requiresmanagement to make estimates and assumptions that affect the amounts reportedfor assets and liabilities, the disclosure of contingent assets and liabilitiesat the date of the financial statements, and the amounts reported for revenuesand expenses, including depletion, during the reporting period.  Therefore, the reported amounts of theCompany’s assets and liabilities, revenues and expenses and associateddisclosures with respect to contingent assets and obligations are necessarilyaffected by these estimates.  Theseestimates are evaluated on an ongoing basis, utilizing historical experience,consultation with experts and other methods considered reasonable in theparticular circumstances.  Nevertheless,actual results may differ significantly from the estimates used.  Any effects on the Company’s business,financial position or results of operations resulting from revisions to theseestimates are recorded in the period in which the facts that give rise to therevision become known.

 

TheCompany is subject to a number of risks inherent in the industry in which itoperates, including price volatility, counterparty credit risk, the success ofits drilling programs and other gas supply. The Company’s financial condition, results of operations and cash flowswill depend significantly upon the prices received for gas and NGLs.  These prices are subject to fluctuations inresponse to changes in supply, market uncertainty and a variety of additionalfactors that are beyond the control of the Company.  In addition, the Company must continuallyconnect new wells to its gathering systems in order to maintain or increasethroughput levels to offset natural declines in dedicated volumes.  The number of new wells drilled by theCompany and other producers will depend upon, among other factors, prices forgas and oil, the drilling budgets of third-party producers, the energy and taxpolicies of the federal and state governments, the pace at which permitsrequired for drilling and production operations are obtained, and theavailability of foreign oil and gas, none of which are within the Company’scontrol.

 

***Revised classifications. ***In 2004, the Company revised its classification in its Statement ofCash Flows for the years ended December 31, 2003 and 2002, of the Change in thebalance of outstanding checks from a component of Net cash provided byoperating activities to a component of Cash flows from financing activities.  This change in classification had the effectof decreasing previously reported cash provided by operating activities by$4,510 and $6,735 for the years ended December 31, 2003 and 2002, respectively,with corresponding increases in the respective periods in cash flows used infinancing activities.

 

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***Recently Issued Accounting Pronouncements.***

 

**SFAS No. 123(R).**  SFAS No. 123(R), “*Share Based Payment”*was issued inDecember 2004 and must be adopted no later than periods beginning afterJune 15, 2005.  This pronouncementrequires companies to expense the fair value of employee stock options andother forms of stock based compensation. The Company intends to adopt this pronouncement in the third quarter of2005.  Currently, the Company iscomplying with the pro forma disclosure requirements of SFAS No. 123, *“Accounting for Stock Based Compensation*”which are included in Note 2 – Summary of Significant Accounting Policies toConsolidated Financial Statements.  Ifthe Company had adopted SFAS No. 123(R) for the year ended December 31, 2004,Earnings per share of common stock - assuming dilution would have been $1.54per share of common stock or a reduction of approximately $0.07 per share ofcommon stock from the actual results for 2004.

 

**SFASNo. 151.**   SFASNo. 151, “*Inventory Costs, an amendmentof ARB No. 43, Chapter 4”*was issued in November 2004 and iseffective for the Company for inventory costs incurred in fiscal yearsbeginning after June 15, 2005, and will be applied prospectively.  SFAS No. 151 amends APB Opinion No. 43,Chapter 4, “Inventory Pricing” to clarify the accounting for abnormal amountsof costs and the allocation of fixed production overheads.  The Company believes that the adoption ofSFAS No. 153 will not affect its earnings, financial position or cash flows.

 

**SFASNo. 153.**   SFASNo. 153, “*Exchanges of NonmonetaryAssets, an amendment of APB Opinion No. 29”*was issued in December2004 and is effective for the Company for nonmonetary asset exchanges occurringin fiscal periods beginning after June 15, 2005, and will be appliedprospectively.  SFAS No. 153 amendsAPB Opinion No. 29, “*Accounting forNonmonetary Transactions”*. The guidance in APB Opinion No. 29 is based on the principle that exchangesof nonmonetary assets should be measured based on the fair value of the assetsexchanged but included certain exceptions to that principle.  SFAS No. 153 amends APB Opinion No. 29 toeliminate the exception for nonmonetary exchanges of similar productive assetsand replaces it with a general exception for exchanges of nonmonetary assetsthat do not have commercial substance.  Anonmonetary exchange has commercial substance if the future cash flows of theentity are expected to change significantly as a result of the exchange.  The Company will adopt SFAS No. 153 asrequired.

 

**EITF No. 04-13.  **At itsNovember 2004 meeting, the Emerging Issues Task Force of the FASB begandiscussion of Issue No. 04-13, “Accounting for Purchases and Sales of Inventorywith the Same Counterparty.”  This Issueaddresses the question of when it is appropriate to measure non-monetarypurchases and sales of inventory at fair value and record them in cost of salesand revenues and when they should be recorded as an exchange measured at thebook value of the item sold. The EITF did not reach a consensus on this issue,but requested the FASB staff to further explore the alternative views.  The implementation of this EITF, if approved,may reduce revenues and related costs but will not have a significant impact onits net income, financial position or cash flows.

 

**FSP FAS 19-a.** In February 2005, the FASB Staff posted its proposed staff positionFSP FAS 19-a, “Accounting for Suspended Well Costs.” At issue is thecurrent requirement of SFAS 19, “Financial Accounting and Reporting by Oiland Gas Producing Companies,” to capitalize the costs of drilling exploratorywells pending determination of whether the well has found proved reserves. Thecapitalized costs become part of the entity’s wells, equipment, and facilitiesif the well successfully located proved reserves. However, if the well has notfound proved reserves, the capitalized costs of drilling the well are expensed,net of any salvage value. Questions have arisen as to whether there arecircumstances that would permit the continued capitalization ofexploratory-well costs beyond the one-year limit specified in SFAS 19other than when additional exploration wells are necessary to justify majorcapital expenditures and those wells are underway or firmly planned for thenear future. In its proposal, the FASB Staff states that exploratory well costscould be capitalized beyond a one-year limit if the well has found a sufficientquantity of reserves to justify its completion as a producing well and theentity is making progress assessing reserves and the economic and operationalviability of the project. Comments on the proposed FASB Staff position were dueMarch 7, 2005. This FSP will be effective in the first quarter after it isapproved.  The Company does not believethat this FSP will have a material impact on our results of operations,financial position or cash flows.

 

**American Jobs Creation Act of 2004. **During October 2004, H.R. 4520, the “AmericanJobs Creation Act of 2004,” was enacted. The Act provides for certainadditional tax deductions from qualified taxable income beginning in 2005,subject to certain limitations. Although the Company expects that the Act mayresult in a reduction in the Company’s effective tax rate, the Company has notyet determined the full impact of this law.

 

**NOTE4 - RELATED PARTIES**

 

Fromtime to time, the Company enters into joint ventures and partnerships in orderto reduce risk, create strategic alliances and to establish itself in oil andgas producing basins in the United States. It is our policy that all transactions entered into by the Company withits related parties were consummated in the ordinary course of business and onterms that would be comparable to those obtained from third parties.

 

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***Fort Union.***  FortUnion Gas Gathering, L.L.C. (“Fort Union”), owns a gathering pipeline andtreater in the Powder River Basin.  AtDecember 31, 2004 and 2003, the Company owned an approximate 13% interest inFort Union and is the construction manager and field operator.  The Company accounts for its investment inthis entity under the equity method of accounting.  Construction and expansions of the gatheringheader and treating system were project financed by Fort Union.  At December 31, 2004, Fort Union had totalproject financing debt outstanding of $35.7 million.  This debt is amortizing on an annual basisand is scheduled to be fully paid in 2009. All participants in Fort Union have guaranteed Fort Union’s payment ofthe project financing on a proportional basis, resulting in the Company’sguarantee of $4.7 million of the debt of Fort Union.  This guarantee is not reflected on theConsolidated Balance Sheet.

 

TheCompany has entered into long-term agreements for firm gathering services on 83MMcf per day of capacity for $0.14 per Mcf on Fort Union.  The Company acts as field operator of FortUnion and charges a monthly overhead fee to cover such services.  In 2004, 2003 and 2002, the Company receivedoverhead fees from Fort Union totaling $43,000, $(2,000) and $25,000,respectively, and the Company paid to Fort Union a total of $5.0 million, $6.4million and $5.3 million for gathering services, respectively.  At December 31, 2004 and 2003, the Companyhad a net amount due to Fort Union of $7,000 and $71,000, respectively.  At December 31, 2004, the Company’sinvestment in Fort Union totaled $2.6 million and is included in Investments injoint ventures on the Consolidated Balance Sheet.

 

***Rendezvous.***  AtDecember 31, 2004 and 2003, the Company owned a 50% interest in Rendezvous GasServices, L.L.C., (“Rendezvous”) and the Company serves as field operator ofits systems.  Rendezvous was formed in2001 to gather gas for the Company and other third parties along the PinedaleAnticline for blending or processing at either the Company’s Granger Complex orat a third-party owned processing facility. The Granger Complex utilizes Rendezvous to deliver significant volumesof gas contractually dedicated to the Granger Complex for processing orblending.  In December 2004,approximately 77% of the gas processed or blended at the Granger Complex wasdelivered to the facility by Rendezvous. The other 50% owner in Rendezvous is a large utility with oil and gasproduction and gathering and processing assets in the same area.  Rendezvous was expanded during 2004 and 2003,and at December 31, 2004, the Company had a total of $33.2 million invested inthis venture.  The investment is includedin Investments in joint ventures on the Consolidated Balance Sheet.  The Company accounts for its investment inthis entity under the equity method of accounting.  The Company charges a monthly overhead fee toact as field operator of Rendezvous and an overhead charge for capital projectsit constructs on behalf of the venture. In 2004 and 2003, the Company received overhead fees as field operatorfrom Rendezvous totaling $100,000 for both years and overhead fees on capitalprojects totaling $42,800 and $825,000, respectively.  In 2004 and 2003, the Company paid toRendezvous a total of $3.9 million and $2.2 million, respectively, forgathering services.  At December 31, 2004and 2003, the Company had a net amount due to Rendezvous of $1.2 million and$382,000, respectively.

 

***Officer Transactions.***  In prior years, the Company hadentered into agreements committing the Company to loan to certain key employeesan amount sufficient to exercise their options as each portion of their optionsvests under the Key Employees’ Incentive Stock Option Plan.  The loan and accrued interest were to beforgiven if the employee was continually employed by the Company and upon aresolution of the board of directors.  In2002, the Company forgave loans related to 125,000 shares of Common Stocktotaling $703,000.  Pursuant to the termsof an agreement entered into in 2001, the remaining loan was forgiven in May2003.  As of December 31, 2003, therewere no loans outstanding under these programs and the program is no longer ineffect.  At December 31, 2002, loansrelated to 55,000 shares of Common Stock totaling $295,000 were outstandingunder these programs.  In prior years,the Company had accrued for the forgiveness of these loans.  In October 2001, the Company’s former ChiefExecutive Officer and President retired. The Company had entered into a consulting agreement with this executiveproviding for payments of $167,000 in May 2002 and $175,000 in May 2003.

 

**NOTE5 - COMMODITY RISK MANAGEMENT**

 

***Risk Management Activities.*** The Company’s commodity price risk managementprogram has two primary objectives. The first goal is to preserve and enhancethe value of the Company’s equity volumes of gas and NGLs with regard to theimpact of commodity price movements on cash flow, net income and earnings pershare in relation to those anticipated by the Company’s operating budget. Thesecond goal is to manage price risk related to the Company’s physical gas,crude oil and NGL marketing activities to protect profit margins.  This risk relates to fixed price purchase andsale commitments, the value of storage inventories and exposure to physicalmarket price volatility.

 

TheCompany utilizes a combination of fixed price forward contracts,exchange-traded futures and options, as well as fixed index swaps, basis swapsand options traded in the OTC to accomplish these objectives. These instrumentsallow the Company to preserve value and protect margins because correspondinglosses or gains in the value of the financial instruments offset gains orlosses in the physical market.

 

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TheCompany also uses financial instruments to reduce basis risk.  Basis is the difference in price between thephysical commodity being hedged and the price of the futures contract used forhedging.  Basis risk is the risk that anadverse change in the futures market will not be completely offset by an equaland opposite change in the cash price of the commodity being hedged.  Basis risk exists in natural gas primarilydue to the geographic price differentials between cash market locations andfutures contract delivery locations.

 

TheCompany enters into futures transactions on the New York Mercantile Exchange (“NYMEX”)and OTC swaps and options with various counter parties, consisting primarily offinancial institutions and other natural gas companies. The Company conducts acredit review of OTC counter parties and has agreements with many of theseparties that contain collateral requirements. The Company generally usesstandardized swap agreements that allow for offset of positive and negative OTCexposures.  OTC exposure ismarked-to-market daily for the credit review process.  The Company’s exposure to OTC credit risk isreduced by its ability to require a margin deposit from its counterpartiesbased upon the mark-to-market value of their net exposure.  The Company is also subject to margin depositrequirements under these same agreements and under margin deposit requirementsfor its NYMEX transactions.  At December31, 2004 and 2003, the Company had posted margin deposits totaling $3.0 millionand $5.7 million, respectively, with various counterparties.

 

Theuse of financial instruments may expose the Company to the risk of financialloss in certain circumstances, including instances when (i) the Company’sequity volumes are less than expected, (ii) the Company’s customers fail topurchase or deliver the contracted quantities of natural gas or NGLs, or (iii)the Company’s OTC counter parties fail to perform. To the extent that theCompany engages in hedging activities, it may be prevented from realizing thebenefits of favorable price changes in the physical market. However, it issimilarly insulated against decreases in such prices.

 

Allequity-hedging contracts are designated and accounted for as cash flowhedges.  As such, gains and lossesrelated to the effective portions of the changes in the fair value of thederivatives are recorded in Accumulated other comprehensive income, a componentof Stockholders’ equity.  Realized gainsor losses on these cash flow hedges are recognized in the ConsolidatedStatement of Operations through Sale of gas or Sale of natural gas liquids whenthe hedged transactions occur.  Realizedand unrealized gains or losses represented by the periodic or final cashsettlements from economic hedges are included in Price risk managementactivities on the Consolidated Statement of Operations.  Economic hedges are financially settledderivatives that either were not designated or did not qualify as hedges underSFAS No. 133.  These are marked-to-marketthrough earnings.

 

Toqualify as cash flow hedges, the hedge instruments must be designated as cashflow hedges and changes in their fair value must be highly effective atoffsetting changes in the price of the forecasted transaction being hedged sothat the Company’s exposure to the risk of commodity price changes isreduced.  To meet this requirement, theCompany hedges the price of the commodity, and if applicable, the basis betweenthat derivative’s contract delivery location and the cash market location usedfor the actual sale of the product.  Thisstructure attains a high level of effectiveness, ensuring that a change in theprice of the forecasted transaction will result in an equal and opposite changein the price of the derivative instrument hedgeing the transaction.In 2004,2003 and 2002, the Company utilized crude oil as a surrogate hedge for naturalgasoline, butane and condensate.  Thesehedges were tested for effectiveness at inception and on a quarterly basisthereafter.  Regression analysis based ona five-year period of time was used for these tests.  In the first quarter of 2004, the Companydetermined in its quarterly effectiveness testing that its hedges of equitybutane production which utilized crude oil puts as a surrogate were no longereffective hedges.  Therefore, in thefirst quarter, the Company discontinued cash flow hedge accounting treatment onthese instruments.  The value of these financialinstruments remained in Accumulated other comprehensive income and wasreclassified to the Company’s results of operations in 2004 as the underlyingtransactions occurred.  Gains or lossesfrom the ineffective portions of changes in the fair value of cash flow hedgesare recognized currently in earnings through Price risk managementactivities.  During the year endedDecember 31, 2004, 2003 and 2002, the Company recognized losses of $159,000,$110,000 and $154,000, respectively, from the ineffective portions of itshedges.

 

In 2003, in order to properly align the Company’s hedgedvolumes of natural gas to its forecasted equity production, the Companydiscontinued hedge treatment on financial instruments for 10 MMcf per day ofnatural gas and 50,000 barrels per month of ethane.  As a result, a pre-tax loss of $2.8 millionwas reclassified into earnings from Accumulated other comprehensive income.  In 2002,in order to properly align the Company’s hedged volumes of natural gas to itsforecasted equity production for 2003, the Company discontinued hedge treatmenton financial instruments for 6 MMcf per day. As a result, a pre-tax gain of $790,000 was reclassified into earningsin 2002 from Accumulated other comprehensive income.  There were no gains or losses reclassifiedinto earnings as a result of the discontinuance of cash flow hedges in 2004.

 

Accountbalances related to equity hedging transactions at December 31, 2004 were $2.9million in Current Assets from price risk management activities, $1.7 millionin Current Liabilities from price risk management activities, $240,000 inDeferred income taxes payable, net, and a $410,000 after-tax unrealized gain inAccumulated other comprehensive income, a component of Stockholders’Equity.  Based on the commodity prices asof December 31, 2004, the after-tax gain will be re-classified from Accumulatedother comprehensive income to Sale of gas or Sale of natural gas liquids during2005.

 

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***Natural Gas Derivative Market Risk*****.**  As of December 31,2004, the Company held a notional quantity of approximately 342 Bcf of naturalgas futures, swaps and options extending from January 2005 to October 2006 witha weighted average duration of approximately five months.  This was comprised of approximately 151 Bcfof long positions and 191 Bcf of short positions in these instruments.  As of December 31, 2003, the Company held anotional quantity of approximately 268 Bcf of natural gas futures, swaps andoptions extending from January 2004 to October 2006 with a weighted averageduration of approximately five months. This was comprised of approximately 107Bcf of long positions and 161 Bcf of short positions in these instruments.

 

***Crude Oil and NGL Derivative Market Risk.***  As of December 31, 2004, the Company held anotional quantity of approximately 163,800 MGal of NGL futures, swaps andoptions extending from January 2005 to December 2005 with a weighted averageduration of approximately six months. This was comprised of approximately 100,800 MGal of long positions and63,000 MGal of short positions in these instruments.  As of December 31, 2003, the Company held anotional quantity of approximately 191,520 MGal of NGL futures, swaps andoptions extending from January 2004 to December 2004 with a weighted averageduration of approximately six months. This was comprised of approximately120,960 MGal of long positions and 70,560 MGal of short positions in theseinstruments.

 

***Foreign Currency Derivative Market Risk***.  As a normal part of its business, the Companyenters into physical gas transactions which are payable in Canadian dollars.The Company enters into forward purchases and sales of Canadian dollars fromtime to time to fix the cost of its future Canadian dollar denominated naturalgas purchase, sale, storage and transportation obligations. This is done toprotect marketing margins from adverse changes in the U.S. and Canadian dollarexchange rate between the time the commitment for the payment obligation ismade and the actual payment date of such obligation. As of December 31, 2004,the Company had sold forward contracts for $31.3 million in Canadian dollars inexchange for $24.0 million in U.S. dollars, and the fair market value of thesecontracts was a loss of $2.1 million in U.S. dollars.  As of December 31, 2003, the net notionalvalue of such contracts was approximately $24.3 million in Canadian dollars,which approximated its fair market value.

 

**NOTE6 - DEBT**

 

Thefollowing summarizes the Company’s consolidated debt at the dates indicated(000s):

 
| ** **                               | ** ** | **December 31,** | ** ** |
|------------------------------------------|------------|------------------|------------|
| ** **                               | ** ** | **2004**         | ** ** | **2003** | ** ** |
| Variable  Rate Revolving Credit Facility |       | $                | 227,000    |   | $ | 94,000 |   |
| Master Shelf  and Subordinated Notes     |       | 155,000          |       | 245,000 |   |
| Total long-term debt                     |       | $                | 382,000    |   | $ | 339,000 |   |

 

***Variable Rate Revolving Credit Facility. ***Therevolving credit facility matures in June 2009. In December 2004, the size of the commitment under the revolver wasincreased from $400 million to $500 million. At December 31, 2004, $227.0 million was outstanding under thisfacility.  Loans made under this facilityare secured by a pledge of the capital stock of the Company’s significantsubsidiaries.  These subsidiaries alsoguarantee the borrowings under the facility.

 

Theborrowings under the revolving credit facility bear interest at Eurodollarrates or a base rate, as requested by the Company, plus an applicablepercentage based on the Company’s debt to capitalization ratio.  The base rate is the agent’s published primerate.  The Company also pays a quarterlycommitment fee ranging between 0.20% and 0.375%, depending on its debt tocapitalization ratio.  This fee is paidon unused amounts of the commitment.  AtDecember 31, 2004, the interest rate payable on borrowings under this facilitywas approximately 3.8%.  Under therevolving credit facility, the Company is subject to a number of covenants,including: maintaining a total debt to capitalization ratio of not more than55% and maintaining a ratio of EBITDA, as defined in the revolving creditfacility, to interest over the last four quarters in excess of 3.0 to 1.0.  The revolving credit facility ranks equallywith borrowings under the Company’s master shelf agreement with The PrudentialInsurance Company.  This facility hasbeen rated Ba1 by Moody’s and is in the process of being rated by S&P.

 

***Master Shelf Agreement. ***Amounts outstanding under the master shelfagreement at December 31, 2004 are as indicated in the following table (000s): 

 
| **Issue Date**    | ** ** | **Amount** | ** ** | **Interest Rate** | ** ** | **Final Maturity** | ** **     | **Principal Repayment Schedule** | ** **                                     |
|-------------------|------------|------------|------------|-------------------|------------|--------------------|----------------|----------------------------------|------------------------------------------------|
| July  28, 1995    |       | $          | 30,000     |              | 7.61       | %                  | July  28, 2007 |                             | $10,000  on each of July 28, 2005 through 2007 |   |
| January  17, 2003 |       | 25,000     |       | 6.36              | %          | January  17, 2008  |           | Single  payment at maturity      |                                           |
| June  30, 2004    |       | 100,000    |       | 5.92              | %          | June  30, 2011     |           | Single  payment at maturity      |                                           |
| Total             |       | $          | 155,000    |              |       |               |           |                             |                                           |   |

 

TheCompany’s borrowings under the master shelf agreement are secured by a pledgeof the capital stock of its significant

 

63

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subsidiaries.  These subsidiaries also guarantee theborrowings under the facility.  All ofthe borrowings under the master shelf agreement can be prepaid prior to theirfinal maturity by paying a yield-maintenance fee.  Under the master shelf agreement, the Companyis subject to a number of covenants, including: maintaining a total debt tocapitalization ratio of not more than 55% and maintaining a quarterly test ofEBITDA, as defined in the master shelf agreement, to interest for the last fourquarters in excess of 3.0 to 1.0.

 

InDecember 2004, the Company notified Prudential of its intention to prepay the$25 million note due January 17, 2008. This note bore interest at 6.36% per annum and was prepaid at par onJanuary 18, 2005.  To fund theprepayment, the Company issued a new $25 million note to Prudential, due January2015 that bears interest at 5.57% per annum. During 2005, the Company will make scheduled payments totaling $10.0million on the master shelf.  The Companyintends to fund these repayments with funds available under the revolvingcredit facility.

 

***Senior Subordinated Notes. ***In 1999, the Company sold$155.0 million of senior subordinated notes in a private placement with a finalmaturity of 2009 due in a single payment which were subsequently exchanged forregistered publicly tradable notes under the same terms and conditions.  The subordinated notes bore interest at 10%per annum.  The Company incurredapproximately $5.0 million in offering commissions and expenses, which werecapitalized and were being amortized over the term of the notes.  The Company redeemed the senior subordinatednotes in June 2004 using amounts available under the revolving credit facilityand an additional borrowing under the master shelf agreement.  In connection with this redemption, aprepayment penalty of $7.75 million was paid and expensed and approximately $2.9million of unamortized offering commissions were expensed.

 

Approximatefuture maturities of long-term debt in the year indicated are as follows atDecember 31, 2004 (000s):

 
| 2005       |   | $       | 35,000  |   |
|------------|--------|---------|---------|--------|
| 2006       |   | 10,000  |    |
| 2007       |   | 10,000  |    |
| 2008       |   | —  |    |
| 2009       |   | 227,000 |    |
| Thereafter |   | 100,000 |    |
| Total      |   | $       | 382,000 |   |

 

**NOTE7 - FINANCIAL INSTRUMENTS**

 

TheCompany, using available market information and valuation methodologies, hasdetermined the estimated fair values of the Company’s financialinstruments.  Considerable judgment isrequired to develop the estimates of fair value; thus, the estimates providedherein are not necessarily indicative of the amount that the Company couldrealize upon the sale or refinancing of such financial instruments.

 
| ** **                       | ** ** | **December 31, 2004** | ** ** | **December 31, 2003** | ** ** |
|----------------------------------|------------|-----------------------|------------|-----------------------|------------|
| ** **                       | ** ** | **Carrying**          | ** ** | **Fair**              | ** ** | **Carrying** | ** ** | **Fair** | ** ** |
| ** **                       | ** ** | **Value**             | ** ** | **Value**             | ** ** | **Value** | ** ** | **Value** | ** ** |
| ** **                       | ** ** | **(000s)**            | ** ** | ** **            | ** ** | **(000s)** | ** ** | ** ** | ** ** |
| Cash and  cash equivalents       |       | $                     | 390        |                  | $          | 390 |   | $ | 26,116 |   | $ | 26,116 |   |
| Margin  deposits                 |       | 7,939                 |       | 7,939                 |       | 8,098 |   | 8,098 |   |
| Trade  accounts receivable       |       | 385,811               |       | 385,811               |       | 254,411 |   | 254,411 |   |
| Accounts payable                 |       | 400,672               |       | 400,672               |       | 303,186 |   | 303,186 |   |
| Long-term  debt                  |       | 382,000               |       | 384,544               |       | 339,000 |   | 371,553 |   |
| Derivative  contracts (Restated) |       | $                     | 15,641     |                  | $          | 15,641 |   | $ | (2,446 | ) | $ | (2,446 | ) |

 

TheCompany in estimating the fair value of its financial instruments used thefollowing methods and assumptions:

 

***Cash and cash equivalents, margin deposits, trade accounts receivableand accounts payable.*** Due to the short-term nature of theseinstruments, the carrying value approximates the fair value.

 

***Long-term debt.*** The Company’s long-term debt was comprised offixed and floating rate facilities.  Thefair market value for the fixed rate debt was estimated using discounted cashflows based upon the Company’s current borrowing rates for debt with similarmaturities. The floating rate portion of the long-term debt was borrowed on arevolving basis, which accrues interest at current rates; as a result, carryingvalue approximates fair value of this outstanding debt.

 

64

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***Derivative contracts.*** Fair value represents the amount at which theinstrument could be exchanged in a current arms-length transaction.

 

**NOTE8 - INCOME TAXES**

 

Theprovision for income taxes for the years ended December 31, 2004, 2003 and 2002is comprised of (000s):

 
| ** **          | ** ** | **2004**     | ** ** | **2003**     | ** ** | **2002**     | ** ** |
|---------------------|------------|--------------|------------|--------------|------------|--------------|------------|
| ** **          | ** ** | **Restated** | ** ** | **Restated** | ** ** | **Restated** | ** ** |
| Current:            |       |         |       |         |       |         |       |
| Federal             |       | $            | 820        |         | $          | 4,002        |       | $ | 9,404 |   |
| State               |       | 1,658        |       | 265          |       | 1,096        |       |
| Total Current       |       | 2,478        |       | 4,267        |       | 10,500       |       |
| Deferred:           |       |         |       |         |       |         |       |
| Federal             |       | 69,069       |       | 49,567       |       | 9,812        |       |
| State               |       | 2,131        |       | 1,784        |       | 333          |       |
| Total Deferred      |       | 71,200       |       | 51,351       |       | 10,145       |       |
| Total tax provision |       | $            | 73,678     |         | $          | 55,618       |       | $ | 20,645 |   |

 

Notincluded above is the tax (expense) and benefit, respectively, allocated to thecumulative effect of a change in accounting principle of approximately ($2.7)million and $4.0 million for the years ended December 31, 2004 and 2003.  There were no such items in 2002.

 

Temporarydifferences and carry-forwards which give rise to the deferred tax liabilities(assets) at December 31, 2004 and 2003, net of the tax effect of the cumulativechange in accounting principle, are as follows (000s):

 
| ** **                                                       | ** ** | ** ** | ** ** | **2004**     | ** ** | **2003**     | ** ** |
|------------------------------------------------------------------|------------|------------|------------|--------------|------------|--------------|------------|
| ** **                                                       | ** ** | ** ** | ** ** | **Restated** | ** ** | **Restated** | ** ** |
| Property and  equipment                                          |       |       |       | $            | 280,565    |         | $          | 222,884 |   |
| Differences  between the book and tax basis of acquired assets   |       | 10,505     |       | 11,341       |       |
| Hedging  derivatives                                             |       |       |       | 1,795        |       | (4,649       | )          |
| Total deferred income tax liabilities                            |       |       |       | 292,865      |       | 229,576      |       |
| Alternative  Minimum Tax (“AMT”) credit carry-forwards |       | (43,412    | )          | (50,220      | )          |
| Net  Operating Loss (“NOL”) carry-forwards             |       |       |       | —       |       | (6,034       | )          |
| Total carry-forwards                                             |       |       |       | (43,412      | )          | (56,254      | )          |
| Net deferred income taxes payable                                |       |       |       | $            | 249,453    |         | $          | 173,322 |   |

 

Thechange in the net deferred income taxes in 2004 and 2003 includes a $2.5million and $700,000 tax benefit, respectively, associated with the exercise ofincentive stock options, which is included in Additional paid in capital.

 

Thedifferences between the provision for income taxes at the statutory rate andthe actual provision for income taxes, before the tax effect of the change inaccounting principle, for the years ended December 31, 2004, 2003 and 2002 aresummarized as follows (000s):

 
| ** **                                                                                     | ** ** | **2004**     | ** ** | **2003** | ** ** | **2002**     | ** ** |
|------------------------------------------------------------------------------------------------|------------|--------------|------------|----------|------------|--------------|------------|
| ** **                                                                                     | ** ** | **Restated** | ** ** | **%**    | ** ** | **Restated** | ** ** | **%** | ** ** | **Restated** | ** ** | **%** | ** ** |
| Income tax before effect of change in  accounting principle at statutory rate                  |       | $            | 68,853     |     | 35.0       |         | $          | 52,597 |   | 35.0 |   | $ | 19,163 |   | 35.0 |   |
| State income taxes, net of federal benefit                                                     |       | 2,125        |       | 1.1      |       | 1,893        |       | 1.3 |   | 657 |   | 1.2 |   |
| Federal and state effect of  non-deductibility of CFTC settlement                              |       | 2,518        |       | 1.3      |       |         |       |   |   |   |   |   |   |
| Canada income taxes, effect of disallowed  loss on sale of stock and other miscellaneous items |       | 182          |       | 0.1      |       | 1,128        |       | 0.8 |   | 825 |   | 1.5 |   |
| Total                                                                                          |       | $            | 73,678     |     | 37.5       |         | $          | 55,618 |   | 37.1 |   | $ | 20,645 |   | 37.7 |   |

 

AtDecember 31, 2004, the Company had AMT credit carry-forwards for federal incometax purposes of approximately $43.4 million, respectively.  These carry-forwards have no expiration.

 

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TheCompany believes that the AMT credit carry-forwards will be realized becausethey are substantially offset by existing taxable temporary differencesreversing or are expected to be realized by achieving future profitableoperations based on the Company’s dedicated and owned reserves, past earningshistory and projections of future earnings.

 

**NOTE9 - COMMITMENTS AND CONTINGENT LIABILITIES**

 

***Litigation.***

 

***Gracey et al. v. Western GasResources, Inc. et al., United States District Court, Southern District of NewYork, Case No. 03-CV-6186 (vm) (S.D.N.Y.). ***OnSeptember 17, 2004, the plaintiffs, traders of natural gas futures contracts onthe NYMEX filed this action on behalf of themselves and a putative class ofothers similarly situated.  In thecomplaint, the plaintiffs claim that the Company manipulated the prices ofnatural gas futures on the NYMEX in violation of the Commodity Exchange Act, orCEA, by reporting allegedly “inaccurate, misleading and false tradinginformation” to trade publications that compile and publish indices of naturalgas spot prices.  In addition, thecomplaint asserts that the Company aided and abetted the alleged CEA violationsof others.  The plaintiffs seek torecover actual damages on behalf of themselves and a class of natural gasfutures traders, and their costs of litigation including attorney’s fees.  The Company believes that the claims arewithout merit and intends to vigorously contest the allegations in this case.

 

***United States of America and ex rel. Jack J.Grynberg v. Western Gas Resources, Inc., et al., United States District Court,District of Colorado, Civil Action No. 97-D-1427. ***The Company, along with over 300 other natural gascompanies, are defendants in litigation filed on September 30, 1997, in 72 separateactions filed by Mr. Grynberg on behalf of the federal government.  The allegations made by Mr. Grynberg are thatestablished gas measurement and royalty calculation practices improperlydeprived the federal government of appropriate natural gas royalties andviolate 31 U. S. C. 3729 (a) (7) of the False Claims Act.  The cases have been consolidated to theUnited States District Court for the District of Wyoming.  Discovery on the jurisdictional issues isbeing completed to determine if this matter qualifies as a qui tam action (anaction on behalf of the individual plaintiff and the government).  The Company believes that Mr. Grynberg’sclaims are baseless and without merit and intends to vigorously contest theallegations in this case.

 

***Price, et al. v. Gas Pipelines, Western GasResources, Inc., et al., District Court, Stevens County, Kansas, Case No.99-C-30. ***Western is a defendant in litigation filed onSeptember 23, 1999, along with numerous other natural gas companies, in whichMr. Price is claiming an under measurement of gas and Btu volumes throughoutthe country.  The Company along withother natural gas companies filed a motion to dismiss for failure to state aclaim.  The court denied these motions todismiss.  The court denied plaintiff’smotion for certification as a class and, in the third quarter of 2003, theplaintiff amended and refiled for certification as a class.  On May 12, 2003, Mr. Price filed a furtherclaim, *Will Price et al v. Western GasResources, Inc. et al., District Court, Stevens County, Kansas, Case No. 03C23*,relating to certain matters previously removed from the foregoing action.  The Company believes that Mr. Price’s claimsare without merit and intends to vigorously contest the allegations in thiscase.

 

***Other Litigation.***** TheCompany is involved in various other litigation and administrative proceedingsarising in the normal course of business. In the opinion of the Company’s management, any liabilities that mayresult from these claims will not, individually or in the aggregate, have amaterial adverse effect on its financial position, results of operations orcash flow.

 

***Retirement Plan.***  TheCompany provides a Retirement Plan for its present and past employees, orparticipants.  The purpose of theRetirement Plan is to provide a method for participants to save toward theirretirement.  Beginning in January 1989,participants were given the option to invest their contributions in the WesternGas Fund.  The Western Gas Fund iscomprised of shares of the Company’s common stock, purchased in the open marketby the trustee, Fidelity Management Trust Company, and short-term investments.A participant’s ownership in the Western Gas Fund is measured in Units ratherthan in shares of common stock.  Toeffectuate participant investment elections and therefore purchases and salesof Units, the trustee purchases and sells the common stock in the open marketat market prices.

 

TheCompany is required to register the shares of its common stock purchased by thetrustee of the Retirement Plan under the Securities Act.  Although all the purchases by the trusteewere made in the open market and in a manner consistent with the RetirementPlan and the investment elections of the participants, the Company determinedthat approximately 934,000 shares of its common stock purchased by the trusteebeginning August 14, 2001 and ending August 14, 2002 (the “Rescission Period”)may not have been properly registered in accordance with the SecuritiesAct.  As a result of this determination,the Company filed a registration statement on Form S-3 with the SEC providingfor a rescission offer to certain of the plan participants.  The SEC declared this registration statementeffective in December 2004.  The Companyissued a rescission notice to the affected parties in December 2004.  The notice period ended on January 10,2005.  In connection with the rescissionoffer, the Company has not re-acquired any of its common stock and has paidtotal damages, including interest, to the eligible plan participants ofapproximately $39,000.

 

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***Price Reporting to Gas Trade Publications.*** In 2003, the Company learned that severalemployees in its marketing department furnished inaccurate informationregarding natural gas transactions to energy publications, which compile andreport energy index prices.  The Companydiscovered the inaccuracies during a review of its marketing activities, whichwas being conducted in response to a subpoena issued by the Commodity FuturesTrading Commission (“CFTC”).  Theseemployees identified inaccuracies associated with reporting of natural gastransactions primarily related to points in Texas.  The Company has discontinued the practice ofreporting pricing information to industry publications.  In conjunction with its investigation intothis matter, the Company has taken appropriate disciplinary actions includingthe release of one manager in its marketing department.  In the second quarter of 2004, the Companyreached a settlement of this matter with the CFTC.  In conjunction with this settlement, theCompany paid a civil penalty of $7.0 million that is included in Selling andadministrative expense.

 

***Commitments.***

 

***Lease Commitments. ***As a normal course of the Company’s business operations, the Companyenters into operating leases for office space and office, communication andtransportation equipment.  In addition,primarily to support its growing development in the Powder River Basin coal beddevelopment, the Company has entered into operating leases for compressionequipment. These leases are classified as operating leases and have termsranging from one month to ten years.  Themajority of the leases for compression have purchase options at various timesthroughout the primary terms of the agreements and have renewalprovisions.  Rental payments underoperating leases have totaled $15.3 million, $13.8 million and $10.8 million in2004, 2003 and 2002, respectively. Future operating lease payments by year under these leases are asfollows (000s):

 
| 2005       |   | $      | 16,607 |   |
|------------|--------|--------|--------|--------|
| 2006       |   | 16,422 |   |
| 2007       |   | 15,556 |   |
| 2008       |   | 13,982 |   |
| 2009       |   | 9,490  |   |
| Thereafter |   | 10,264 |   |
| Total      |   | $      | 82,321 |   |

 

***Firm Transportation Capacity.*** The Company enters intofirm transportation agreements with interstate pipeline companies as a part ofits marketing operations and to ensure that its equity production has access todownstream markets.  At December 31,2004, these agreements have terms ranging from one month to thirteenyears.  Payments under these agreementshave totaled $29.3 million, $26.4 million and $29.2 million in 2004, 2003 and2002, respectively.  Future payments byyear under these agreements are as follows (000s):

 
| 2005       |   | $      | 38,883  |   |
|------------|--------|--------|---------|--------|
| 2006       |   | 36,473 |    |
| 2007       |   | 35,657 |    |
| 2008       |   | 32,594 |    |
| 2009       |   | 26,687 |    |
| Thereafter |   | 80,929 |    |
| Total      |   | $      | 251,223 |   |

 

***Storage Capacity.***  TheCompany enters into storage agreements with various third parties primarily aspart of its marketing operations. Payments under these agreements totaled $6.2 million, $5.2 million and$5.1 million in 2004, 2003 and 2002, respectively.  As of December 31, 2004, the Company hadcontracts in place for approximately 17.1 Bcf of storage capacity at variousthird-party facilities.  The associatedcontract periods have an average term of 34 months.  Future payments by year under theseagreements are as follows (000s):

 
| 2005       |   | $     | 7,044  |   |
|------------|--------|-------|--------|--------|
| 2006       |   | 5,127 |   |
| 2007       |   | 3,184 |   |
| 2008       |   | 2,715 |   |
| 2009       |   | 2,100 |   |
| Thereafter |   | 8,921 |   |
| Total      |   | $     | 29,091 |   |

 

***Post Retirement Benefits. ***In July 2004, the Company’s board of directorsauthorized the development of an amendment to the board’s existing health careplan to provide for health care benefits for qualifying members, and their spouses,after their retirement

 

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from the Company’s board of directors.  At December 31, 2004, the terms of the planhad not yet been finalized and, accordingly, no accrual for the future cost ofthis benefit had yet been made.

 

**NOTE10 - BUSINESS SEGMENTS AND RELATED INFORMATION**

 

TheCompany operates in four principal business segments, as follows: Gathering,Processing and Treating; Exploration and Production; Marketing; and Transportation.  Management separately monitors these segmentsfor performance against its internal forecast and these segments are consistentwith the Company’s internal financial reporting package.  These segments have been identified basedupon the differing products and services, regulatory environment and theexpertise required for these operations.

 

***Gathering, Processing and Treating.***  Inthe Gathering, Processing and Treating segment, collectively with the Marketingand Transportation segments referred to as the midstream operations, theCompany connects producers’ wells (including those of the Company’s Explorationand Production segment) to its gathering systems for delivery to its processingor treating plants, process the natural gas to extract NGLs and treat thenatural gas in order to meet pipeline specifications.  In some areas, where no processing isrequired, the Company gathers and compresses producers’ gas and delivers it topipelines for further delivery to market. Except for volumes taken in kind by the Company’s producers, theMarketing segment sells the gas and NGLs extracted at most of its facilities.

 

Inthis segment, the Company recognizes revenue for its services at the time theservice is performed. Included in this segment is the Company’s Powder Rivercoal bed methane gathering operation, which gathers gas from producers,including the Company’s Exploration and Production segment.  In 2003, this service for the Exploration andProduction segment was performed under a percentage-of-proceeds contract and in2004, this service was performed under a fee-based contract.  The change of contract type had no effect onthe Operating profit of either the Gathering, Processing and Treating segmentor the Exploration and Production segment.

 

Substantiallyall gas flowing through the Company’s gathering, processing and treatingfacilities is supplied under three types of contracts providing for thepurchase, treating or processing of natural gas for periods ranging from onemonth to twenty years or in some cases for the life of the oil and gaslease.  Approximately 70% of the Company’splant facilities’ gross margin, or revenues at the plant less productpurchases, for the month of December 2004 was under percentage-of-proceedsagreements in which the Company is typically responsible for the marketing ofthe gas and NGLs.  Under theseagreements, the Company pays producers a specified percentage of the netproceeds received from the sale of the gas and the NGLs.  Revenue is recognized when the gas or NGLs aresold and the related product purchases are recorded as a percentage of the saleof the product.

 

Approximately20% of the Company’s plant facilities’ gross margin for the month of December2004 was under contracts that are primarily fee-based from which the Companyreceives a set fee for each Mcf of gas gathered and/or processed. This type ofcontract provides the Company with a steady revenue stream that is notdependent on commodity prices, except to the extent that low prices may cause aproducer to delay drilling or shut in production.  Revenue is recognized under these contractswhen the related services are rendered.

 

Approximately10% of the Company’s plant facilities’ gross margin for the month of December2004 was under contracts with “keepwhole” arrangements or wellhead purchasecontracts.  Under these contracts, theCompany retains the NGLs recovered by the processing facility and keeps theproducers whole by returning to the producers at the tailgate of the plant anamount of gas equal on a Btu basis to the natural gas received at the plantinlet.  The “keepwhole” component of thecontracts permits the Company to benefit when the value of the NGLs is greateras a liquid than as a portion of the residue gas stream.  However, the Company is adversely affectedwhen the value of the NGLs is lower as a liquid than as a portion of theresidue gas stream.  Revenue isrecognized when the product is sold.

 

***Exploration and Production.***  The activities of the Exploration andProduction segment, also referred to as upstream operations, include theexploration and development of gas properties in the Rocky Mountain area,including those where the Company’s gathering and/or processing facilities arelocated.  The Marketing segment sells themajority of the production from these properties and remits to the Explorationand Production segment all of the proceeds from the sales of gas and itsproportional share of transportation charges.

 

***Marketing.***  The Company’s Marketing segment markets gasand NGLs extracted at its gathering, processing and treating facilities andproduced from its exploration and production assets and buys and sells gas andNGLs in the United States and Canada from and to a variety of customers.  In this segment, revenues for sales ofproduct are recognized at the time the gas or NGLs are delivered to thecustomer and title passes.  Revenues inthis segment are sensitive to changes in the market prices of the underlyingcommodities.  The marketing of productspurchased from third-parties typically results in low operating marginsrelative to the sales price.  The Companysells its products under agreements with varying terms and conditions in orderto match seasonal and other changes in demand. Also

 

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includedin this segment are the Company’s Canadian marketing operations, which areconducted through its wholly owned subsidiary WGR Canada, Inc. and which areimmaterial for separate presentation.

 

Duringthe years ended December 31, 2004, 2003 and 2002, the Company sold gas to avariety of customers including end-users, pipelines, energy merchants, localdistribution companies and others.  In2004, no single customer accounted for more than approximately 9% of theCompany’s consolidated revenues from the sale of gas, or 7% of totalconsolidated revenue.   In 2003, nosingle customer accounted for more than 6% of the Company’s consolidatedrevenues from the sale of gas, or 5% of total consolidated revenue.  In 2002, two customers accounted forapproximately 10% of the Company’s consolidated revenues from the sale of gas,or 9% of total consolidated revenue. One of these customers is an energymerchant and the other customer is an electric utility.

 

Duringthe years ended December 31, 2004, 2003 and 2002, the Company sold NGLs to avariety of customers including end-users, fractionators, chemical companies,energy merchants and other customers.  In2004, one customer accounted for approximately 51% of the Company’sconsolidated revenues from the sale of NGLs, or 7% of total consolidatedrevenue.  This customer is a largeintegrated energy company.  In 2003, twocustomers accounted for approximately 49% of the Company’s consolidatedrevenues from the sale of NGLs, or 6% of total consolidated revenue.  One of these customers is a large integratedenergy company and the other is a large petrochemical company.  In 2002, three customers accounted forapproximately 38% of the Company’s consolidated revenues from the sale of NGLs,or 5% of total consolidated revenue.  Oneof these customers is a large integrated energy company, another is a largepetrochemical company and the third is an energy merchant.

 

***Transportation.***  The Transportation segment reflects theoperations of the Company’s MIGC, Inc. and MGTC, Inc. pipelines.   The revenue presented in this segment isderived from transportation of gas for the Company’s Marketing segment andother third parties.  In this segment,the Company realizes revenue on a monthly basis from firm capacity contractsunder which the shipper pays for transport capacity whether or not the capacityis used and from interruptible contracts where a fee is charged based uponvolumes received into the pipeline.  TheTransportation segment’s capacity contracts range in duration from one month tofive years.

 

***Segment Information.***  Thefollowing table sets forth the Company’s segment information as of and for thethree years ended December 31, 2004, 2003 and 2002 (000s).  Due to the Company’s integrated operations,the use of allocations in the determination of business segment information isnecessary.  Inter-segment revenues arevalued at prices comparable to those of unaffiliated customers.  Prior period amounts in the segmentinformation have been reclassified to conform to the presentation used in 2004.

 

**Year EndedDecember 31, 2004 (Restated):**

 
| ** **                                        | ** ** | **Gas  Gathering  and  Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Transportation** | ** ** | **Corporate** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|---------------------------------------------------|------------|-------------------------------------|------------|----------------------------------|------------|---------------|------------|--------------------|------------|---------------|------------|--------------------------|------------|-----------|------------|
| Revenues from  unaffiliated customers:            |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Sale of gas                                       |       | $                                   | 3,666      |                             | $          | 9,554         |       | $                  | 2,495,913  |          | $          | 1,779                    |       | $         | —     |   | $ | — |   | $ | 2,510,912 |   |
| Sale of natural  gas liquids                      |       | 5                                   |       | —                           |       | 467,081       |       | —             |       | —        |       | —                   |       | 467,086   |       |
| Equity hedges:                                    |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Gas                                               |       | 649                                 |       | 6,720                            |       | —        |       | —             |       | —        |       | —                   |       | 7,369     |       |
| Liquids                                           |       | (16,325                             | )          | —                           |       | —        |       | —             |       | —        |       | —                   |       | (16,325   | )          |
| Gathering,  processing and transportation revenue |       | 84,148                              |       | —                           |       | —        |       | 6,726              |       | —        |       | —                   |       | 90,874    |       |
| Total revenues  from unaffiliated customers       |       | 72,143                              |       | 16,274                           |       | 2,962,994     |       | 8,505              |       | —        |       | —                   |       | 3,059,916 |       |
| Inter-segment  revenues                           |       | 1,051,981                           |       | 252,797                          |       | 54,321        |       | 14,128             |       | —        |       | (1,373,227               | )          | —    |       |
| Price risk  management activities                 |       | (12                                 | )          | —                           |       | 20,063        |       | —             |       | —        |       | —                   |       | 20,051    |       |
| Interest income                                   |       | —                              |       | 4                                |       | —        |       | 1                  |       | 20,181        |       | (20,186                  | )          | —    |       |
| Other, net                                        |       | 1,210                               |       | 12                               |       | (43           | )          | 49                 |       | 1,973         |       | —                   |       | 3,201     |       |
| Total revenues                                    |       | 1,125,322                           |       | 269,087                          |       | 3,037,335     |       | 22,683             |       | 22,154        |       | (1,393,413               | )          | 3,083,168 |       |
|                                              |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Product purchases                                 |       | 871,426                             |       | 2,450                            |       | 2,999,426     |       | 4,559              |       | —        |       | (1,337,062               | )          | 2,540,799 |       |
| Plant operating  and transportation expense       |       | 92,143                              |       | 23                               |       | (167          | )          | 7,150              |       | —        |       | (3,281                   | )          | 95,868    |       |
| Oil and gas  exploration and production expense   |       | —                              |       | 110,473                          |       | —        |       | —             |       | —        |       | (32,865                  | )          | 77,608    |       |
| Earnings from  equity investments                 |       | (7,124                              | )          | —                           |       | —        |       | —             |       | —        |       | —                   |       | (7,124    | )          |
| Segment operating  profit                         |       | 168,877                             |       | 156,141                          |       | 38,076        |       | 10,974             |       | 22,154        |       | (20,205                  | )          | 376,017   |       |
|                                              |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Depreciation,  depletion and amortization         |       | 38,585                              |       | 47,911                           |       | 123           |       | 1,655              |       | 7,262         |       | —                   |       | 95,536    |       |
| Selling and  administrative expense               |       | —                              |       | —                           |       | —        |       | —             |       | 52,292        |       | (46                      | )          | 52,246    |       |
| (Gain) loss from  sale of assets                  |       | 224                                 |       | (520                             | )          | —        |       | (15                | )          | 300           |       | 1,299                    |       | 1,288     |       |
| Loss from early  extinguishment of debt           |       | —                              |       | —                           |       | —        |       | —             |       | 10,662        |       | —                   |       | 10,662    |       |
| Interest expense                                  |       | —                              |       | 42                               |       | 295           |       | (328               | )          | 39,739        |       | (20,186                  | )          | 19,562    |       |
| Income before  income taxes                       |       | $                                   | 130,068    |                             | $          | 108,708       |       | $                  | 37,658     |          | $          | 9,662                    |       | $         | (88,101    | ) | $ | (1,272 | ) | $ | 196,723 |   |
|                                              |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Identifiable  assets:                             |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Other allocated  assets                           |       | $                                   | 32,042     |                             | $          | 7,160         |       | $                  | 146,248    |          | $          | 47,457                   |       | $         | 419,139    |   | $ | (76,286 | ) | $ | 575,760 |   |
| Equity investment                                 |       | 35,729                              |       | —                           |       | —        |       | 2,559              |       | 570,638       |       | (573,197                 | )          | 35,729    |       |
| Property and  equipment                           |       | 674,011                             |       | 463,052                          |       | 17            |       | 36,665             |       | 52,733        |       | (569                     | )          | 1,225,909 |       |
| Total  identifiable assets                        |       | $                                   | 741,782    |                             | $          | 470,212       |       | $                  | 146,265    |          | $          | 86,681                   |       | $         | 1,042,510  |   | $ | (650,052 | ) | $ | 1,837,398 |   |

 

69

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**Year EndedDecember 31, 2003 (Restated):**

 
| ** **                                        | ** ** | **Gas  Gathering  and  Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Transportation** | ** ** | **Corporate** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|---------------------------------------------------|------------|-------------------------------------|------------|----------------------------------|------------|---------------|------------|--------------------|------------|---------------|------------|--------------------------|------------|-----------|------------|
| Revenues from unaffiliated customers:             |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Sale of gas                                       |       | $                                   | 5,041      |                             | $          | 4,746         |       | $                  | 2,474,514  |          | $          | 1,098                    |       | $         | —     |   | $ | — |   | $ | 2,485,399 |   |
| Sale of natural  gas liquids                      |       | 11                                  |       | —                           |       | 357,504       |       | —             |       | —        |       | —                   |       | 357,515   |       |
| Equity hedges:                                    |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Gas                                               |       | (2,358                              | )          | (21,505                          | )          | —        |       | —             |       | —        |       | —                   |       | (23,863   | )          |
| Liquids                                           |       | (11,407                             | )          | —                           |       | —        |       | —             |       | —        |       | —                   |       | (11,407   | )          |
| Gathering,  processing and transportation revenue |       | 76,621                              |       | —                           |       | —        |       | 7,051              |       | —        |       | —                   |       | 83,672    |       |
| Total revenues  from unaffiliated customers       |       | 67,908                              |       | (16,759                          | )          | 2,832,018     |       | 8,149              |       | —        |       | —                   |       | 2,891,316 |       |
| Inter-segment  revenues                           |       | 1,081,358                           |       | 221,266                          |       | 38,510        |       | 14,093             |       | —        |       | (1,355,227               | )          | —    |       |
| Price risk  management activities                 |       | (11                                 | )          | (866                             | )          | (13,287       | )          | —             |       | —        |       | —                   |       | (14,164   | )          |
| Interest income                                   |       | —                              |       | 42                               |       | —        |       | 3                  |       | 12,490        |       | (12,535                  | )          | —    |       |
| Other, net                                        |       | 1,967                               |       | 21                               |       | 4             |       | 42                 |       | 565           |       | —                   |       | 2,599     |       |
| Total revenues                                    |       | 1,151,222                           |       | 203,704                          |       | 2,857,245     |       | 22,287             |       | 13,055        |       | (1,367,762               | )          | 2,879,751 |       |
|                                              |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Product purchases                                 |       | 948,518                             |       | 2,289                            |       | 2,820,495     |       | 2,982              |       | —        |       | (1,317,843               | )          | 2,456,441 |       |
| Plant operating  and transportation expense       |       | 82,810                              |       | 328                              |       | 318           |       | 7,680              |       | —        |       | (2,792                   | )          | 88,344    |       |
| Oil and gas  exploration and production expense   |       | —                              |       | 86,856                           |       | —        |       | —             |       | —        |       | (34,610                  | )          | 52,246    |       |
| Earnings from  equity investments                 |       | (7,356                              | )          | —                           |       | —        |       | —             |       | —        |       | —                   |       | (7,356    | )          |
| Segment operating  profit                         |       | 127,250                             |       | 114,231                          |       | 36,432        |       | 11,625             |       | 13,055        |       | (12,517                  | )          | 290,076   |       |
|                                              |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Depreciation,  depletion and amortization         |       | 30,676                              |       | 33,321                           |       | 141           |       | 1,689              |       | 8,078         |       | —                   |       | 73,905    |       |
| Selling and  administrative expense               |       | —                              |       | —                           |       | —        |       | —             |       | 40,481        |       | (58                      | )          | 40,423    |       |
| (Gain) loss from  sale of assets                  |       | 123                                 |       | (194                             | )          | —        |       | 586                |       | 53            |       | (724                     | )          | (156      | )          |
| Interest expense                                  |       | —                              |       | 24                               |       | 262           |       | (154               | )          | 38,030        |       | (12,535                  | )          | 25,627    |       |
| Income before  income taxes                       |       | $                                   | 96,451     |                             | $          | 81,080        |       | $                  | 36,029     |          | $          | 9,504                    |       | $         | (73,587    | ) | $ | 800 |   | $ | 150,277 |   |
|                                              |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Identifiable  assets:                             |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Other allocated  assets                           |       | $                                   | 4,067      |                             | $          | 7,001         |       | $                  | 103,603    |          | $          | 40,628                   |       | $         | 326,537    |   | $ | (66,708 | ) | $ | 415,128 |   |
| Equity investment                                 |       | —                              |       | —                           |       | —        |       | —             |       | 632,622       |       | (593,333                 | )          | 39,289    |       |
| Property and equipment                            |       | 608,623                             |       | 288,954                          |       | 1,531         |       | 39,010             |       | 57,912        |       | 731                      |       | 996,761   |       |
| Total  identifiable assets                        |       | $                                   | 612,690    |                             | $          | 295,955       |       | $                  | 105,134    |          | $          | 79,638                   |       | $         | 1,017,071  |   | $ | (659,310 | ) | $ | 1,451,178 |   |

 

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**Year Ended December 31, 2002 (Restated):**

 
| ** **                                        | ** ** | **Gas  Gathering  and  Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Transportation** | ** ** | **Corporate** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|---------------------------------------------------|------------|-------------------------------------|------------|----------------------------------|------------|---------------|------------|--------------------|------------|---------------|------------|--------------------------|------------|-----------|------------|
| Revenues from  unaffiliated customers:            |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Sale of gas                                       |       | $                                   | 2,156      |                             | $          | 1,497         |       | $                  | 2,086,208  |          | $          | 1,252                    |       | $         | —     |   | $ | — |   | $ | 2,091,113 |   |
| Sale of natural  gas liquids                      |       | 17                                  |       | —                           |       | 317,743       |       | —             |       | —        |       | —                   |       | 317,760   |       |
| Equity hedges:                                    |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Gas                                               |       | 3,238                               |       | 24,846                           |       | —        |       | —             |       | —        |       | —                   |       | 28,084    |       |
| Liquids                                           |       | (8,247                              | )          | —                           |       | —        |       | —             |       | —        |       | —                   |       | (8,247    | )          |
| Gathering,  processing and transportation revenue |       | 56,806                              |       | 281                              |       | —        |       | 8,345              |       | 169           |       | —                   |       | 65,601    |       |
| Total revenues  from unaffiliated customers       |       | 53,970                              |       | 26,624                           |       | 2,403,951     |       | 9,597              |       | 169           |       | —                   |       | 2,494,311 |       |
| Inter-segment  revenues                           |       | 638,807                             |       | 112,868                          |       | 22,868        |       | 15,794             |       | 87            |       | (790,424                 | )          | —    |       |
| Price risk  management activities                 |       | (233                                | )          | 589                              |       | (35,641       | )          | —             |       | —        |       | —                   |       | (35,285   | )          |
| Interest income                                   |       | 44                                  |       | 43                               |       | 10            |       | 1                  |       | 8,514         |       | (8,612                   | )          | —    |       |
| Other, net                                        |       | 3,595                               |       | 19                               |       | 6             |       | 2                  |       | (660          | )          | 1,758                    |       | 4,720     |       |
| Total revenues                                    |       | 696,183                             |       | 140,143                          |       | 2,391,194     |       | 25,394             |       | 8,110         |       | (797,278                 | )          | 2,463,746 |       |
|                                              |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Product purchases                                 |       | 532,963                             |       | 2,698                            |       | 2,380,446     |       | 935                |       | —        |       | (759,863                 | )          | 2,157,179 |       |
| Plant operating  and transportation expense       |       | 74,119                              |       | 170                              |       | 290           |       | 8,133              |       | 234           |       | (1,416                   | )          | 81,530    |       |
| Oil and gas  exploration and production expense   |       | —                              |       | 63,149                           |       | —        |       | —             |       | —        |       | (29,142                  | )          | 34,007    |       |
| Earnings from  equity investments                 |       | (4,453                              | )          | —                           |       | —        |       | —             |       | —        |       | —                   |       | (4,453    | )          |
| Segment operating  profit                         |       | 93,554                              |       | 74,126                           |       | 10,458        |       | 16,326             |       | 7,876         |       | (6,857                   | )          | 195,483   |       |
|                                              |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Depreciation,  depletion and amortization         |       | 41,959                              |       | 26,770                           |       | 158           |       | 1,675              |       | 6,443         |       | —                   |       | 77,005    |       |
| Selling and  administrative expense               |       | —                              |       | —                           |       | —        |       | —             |       | 35,882        |       | (54                      | )          | 35,828    |       |
| (Gain) loss from  sale of assets                  |       | 877                                 |       | (323                             | )          | —        |       | 476                |       | 494           |       | (576                     | )          | 948       |       |
| Interest expense                                  |       | —                              |       | 66                               |       | 132           |       | (26                | )          | 35,391        |       | (8,612                   | )          | 26,951    |       |
| Income before  income taxes                       |       | $                                   | 50,718     |                             | $          | 47,613        |       | $                  | 10,168     |          | $          | 14,201                   |       | $         | (70,334    | ) | $ | 2,385 |   | $ | 54,751 |   |
|                                              |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Identifiable  assets:                             |       |                                |       |                             |       |          |       |               |       |          |       |                     |       |      |       |
| Other allocated  assets                           |       | $                                   | 34,021     |                             | $          | 911           |       | $                  | 102,251    |          | $          | 24,534                   |       | $         | 285,469    |   | $ | (53,907 | ) | $ | 393,279 |   |
| Equity investment                                 |       | 2,839                               |       | —                           |       | —        |       | —             |       | 467,600       |       | (444,823                 | )          | 25,616    |       |
| Property and  equipment                           |       | 551,094                             |       | 225,943                          |       | 7             |       | 42,072             |       | 47,523        |       | 7                        |       | 866,646   |       |
| Total  identifiable assets                        |       | $                                   | 587,954    |                             | $          | 226,854       |       | $                  | 102,258    |          | $          | 66,606                   |       | $         | 800,592    |   | $ | (498,723 | ) | $ | 1,285,541 |   |

 

**NOTE11 - EMPLOYEE BENEFIT PLANS**

 

***Retirement Plan.*** Adiscretionary retirement plan (a defined contribution plan) exists for allCompany employees meeting certain service requirements.  The Company may make annual discretionarycontributions to the plan as determined by the board of directors, and duringthe three years ended December 31, 2004, the match of employee contributionswas a sliding scale of 60% to 100% of the first 5% of employee compensationbased upon years of service. Contributions are made to Fidelity Management Trust Company, astrustee.  The trustee invests the fundsin accordance with the participants’ investment elections into mutual funds anda fund to purchase the Company’s common stock. The discretionary contributions made by the Company were $3.1 million,$2.2 million and $1.9 million, for the years ended December 31, 2004, 2003 and2002, respectively. The matching contributions were approximately $1.5 million,$1.4 million and $1.3 million for the years ended December 31, 2004, 2003 and2002, respectively.

 

***1999 Non-Employee Directors Stock Option Plan. *** Effective March 1999, the board of directorsof the Company adopted a 1999 Non-Employee Directors’ Stock Option Plan (“1999Directors Plan”) that authorized the granting of options to purchase 30,000shares of the Company’s common stock. During 1999, the board approved options grants covering 30,000 shares toseveral board members. Under this plan, each of these options becomesexercisable as to 33 1/3% of the shares covered by it on each anniversary fromthe date of grant.  This plan terminateson the earlier of March 12, 2009 or the date on which all options granted underthe plan have been exercised in full.

 

***1993, 1997 and 1999 Stock Option Plans. *** The 1993 Stock Option Plan (“1993 Plan”), the1997 Stock Option Plan (“1997 Plan”), and the 1999 Stock Option Plan (“1999Plan”) became effective on March 29, 1993, May 21, 1997, and May 21, 1999, respectively,

 

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afterapprovals by the Company’s stockholders. Each plan is intended to be an incentive stock option plan in accordancewith the provisions of Section 422 of the Internal Revenue Code of 1986, asamended.  The Company reserved 2,000,000shares of common stock for issuance upon exercise of options under each of the1993 Plan and the 1997 Plan and 1,500,000 shares of common stock for issuanceupon exercise of options under the 1999 Plan. The 1993 Plan terminated on March 29, 2003.  The 1997 Plan and the 1999 Plan willterminate on the later of May 21, 2007 and May 21, 2009, respectively, or thedate on which all the respective options granted under each of the plans haveexpired or been exercised in full. Although options covering 745,204 shares are available to be grantedunder the 1997 Plan, no further options will be granted under this plan.  During 2004, options covering 140,876 shareswere granted under the 1999 Plan.

 

***Chief Executive Officer and President’sPlan. ***Pursuant to the Employment Agreement, datedOctober 15, 2001, and the Stock Option Agreement, dated as of November 1, 2001,between the Company and Peter A. Dea, the Company’s Chief Executive Officer andPresident, non-qualified stock options were granted for the purchase of 600,000shares of the Company’s common stock. The exercise price of the options was equal to $2.50 below the closingprice per share on the effective date of the Employment Agreement.  The stock options are subject to theconditions of the Agreements and vest equally over four years.  The difference between the closing price onthe effective date and the exercise price is being amortized over four years ascompensation expense.  This option planwill terminate on the earlier of October 15, 2010 or the date on which alloptions granted under the plan have been exercised in full.

 

***2002 Non-Employee Directors Stock Option Plan. *** Effective May 2002, the stockholders approvedthe 2002 Non-Employee Directors’ Stock Option Plan (“2002 Directors Plan”) thatauthorized the granting of options to purchase 220,000 shares of the Company’scommon stock.  The 2002 Directors Plan provides for a three-year vesting schedule whilethe non-employee director serves on the Company’s board.  Under this plan, a newly elected non-employeedirector will be granted 10,000 options to acquire common stock as of the dateof election.  The 2002 Directors Planalso provides for an annual grant on the date of the Company’s annual meetingto each non-employee director of 4,000 options to acquire common stock. Thepurchase price of the stock under each option shall be the fair market value ofthe stock at the time such option is granted and no options shall be re-priced.  The 2002 Directors Plan requires thenon-employee director to exercise the option at the earlier of ten years fromthe date of the plan or within five years of the date each portion vests.  The non-employee director’s right to exerciseoptions under the 2002 Directors Plan is subject to continuous service sincethe grant was made.  If the non-employeedirector dies or becomes disabled (within the meaning of the 2002 DirectorsPlan) or a change of control occurs, then all of the options granted to thenon-employee director shall become 100% exercisable. The 2002 DirectorsPlan will terminate on the later of May 17, 2012 or the date on which alloptions granted under the plan have expired or been exercised in full.   During 2004, 2003 and 2002, a total of 32,000,32,000 and 36,000 options, respectively, were granted under this plan.

 

***2002 Stock Option Plan.***  Effective May 2002, thestockholders approved the 2002 Stock Incentive Plan (“2002 Plan”) thatauthorized the granting of options to purchase 2,500,000 shares of the Company’scommon stock.  No employee may be grantedmore than 250,000 options to acquire common stock in any fiscal year.  The 2002 Plan requires the employee toexercise the option at the earlier of ten years from the date of the 2002 Planor within five years of the date each portion vests. The employee’s right toexercise options under the 2002 Plan is subject to continuous employment sincethe grant was made. If the employee dies, becomes disabled (within the meaningof the 2002 Plan) or a change of control occurs, then all of the optionsgranted to the employee shall become 100% exercisable.  The 2002 Plan will terminate on the laterof May 17, 2012 or the date on which all options granted under the plan haveexpired or been exercised in full.  During 2004, 2003 and 2002, a total of956,841, 1,129,900 and 375,994 options, respectively, were granted under thisplan.

 

Under each of the 1997, 1999 and 2002 plans, theboard of directors of the Company determines and designates from time to time thoseemployees of the Company to whom options are to be granted.  If any option terminates or expires prior tobeing exercised, the shares relating to such option are released and may besubject to re-issuance pursuant to a new option.  The board of directors has the right to,among other things, fix the method by which the price is determined and theterms and conditions for the grant or exercise of any option.  The purchase price of the stock under eachoption shall be the average closing price for the ten days prior to thegrant.   Under the 1997, 1999 and 2002Plans, the board of directors has the authority to set the vesting schedulefrom 20% per year to 33 1/3% per year. Under each of the plans, the employeemust exercise the option within five years of the date each portion vests.

 

Thefollowing table summarizes the number of stock options exercisable andavailable for grant under the Company’s benefit plans at December 31, 2004,2003, 2002:

 

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| ** **                | ** ** | **Per Share  Price Range** | ** ** | **1999  Directors  Plan** | ** ** | **1993  Plan** | ** ** | **1997  Plan** | ** ** | **1999  Plan** | ** ** | **Chief  Executive  Officer’s  Plan** | ** ** | **2002  Stock  Incentive  Plan** | ** ** | **2002  Non-  Employee  Director’s  Plan** | ** ** |
|---------------------------|------------|----------------------------|------------|---------------------------|------------|----------------|------------|----------------|------------|----------------|------------|--------------------------------------------|------------|----------------------------------|------------|-------------------------------------------------|------------|
| **Exercisable:**          |       |                       |       |                      |       |           |       |           |       |           |       |                                       |       |                             |       |                                            |       |
| December 31, 2004         |       | $0.01-5.00                 |       | 6,600                     |       | —         |       | 36,536         |       | —         |       | —                                     |       | —                           |       | —                                          |       |
|                      |       | $5.01-10.00                |       | —                    |       | —         |       | 11,000         |       | —         |       | —                                     |       | —                           |       | —                                          |       |
|                      |       | $10.01-15.00               |       | —                    |       | —         |       | —         |       | 33,672         |       | 450,000                                    |       | —                           |       | —                                          |       |
|                      |       | $15.01-20.00               |       | —                    |       | —         |       | —         |       | 586,038        |       | —                                     |       | 395,961                          |       | 32,000                                          |       |
|                      |       | $20.01-25.00               |       | —                    |       | —         |       | —         |       | —         |       | —                                     |       | 5,000                            |       | —                                          |       |
|                      |       | TOTAL                      |       | 6,600                     |       | —         |       | 47,536         |       | 619,710        |       | 450,000                                    |       | 400,961                          |       | 32,000                                          |       |
|                      |       |                       |       |                      |       |           |       |           |       |           |       |                                       |       |                             |       |                                            |       |
| December 31, 2003         |       | $0.01-5.00                 |       | —                    |       | —         |       | 109,266        |       | —         |       | —                                     |       | —                           |       | —                                          |       |
|                      |       | $5.01-10.00                |       | 16,700                    |       | —         |       | 65,320         |       | 800            |       | —                                     |       | —                           |       | —                                          |       |
|                      |       | $10.01-15.00               |       | —                    |       | —         |       | —         |       | 71,762         |       | 300,000                                    |       | —                           |       | —                                          |       |
|                      |       | $15.01-20.00               |       | —                    |       | —         |       | —         |       | 575,504        |       | —                                     |       | 84,882                           |       | 10,666                                          |       |
|                      |       | TOTAL                      |       | 16,700                    |       | —         |       | 174,586        |       | 648,066        |       | 300,000                                    |       | 84,882                           |       | 10,666                                          |       |
|                      |       |                       |       |                      |       |           |       |           |       |           |       |                                       |       |                             |       |                                            |       |
| December 31, 2002         |       | $0.01-5.00                 |       | —                    |       | —         |       | 182,810        |       | —         |       | —                                     |       | —                           |       | —                                          |       |
|                      |       | $5.01-10.00                |       | 16,700                    |       | 86,560         |       | 136,000        |       | 34,964         |       | —                                     |       | —                           |       | —                                          |       |
|                      |       | $10.01-15.00               |       | —                    |       | 11,632         |       | —         |       | 67,284         |       | 150,000                                    |       | —                           |       | —                                          |       |
|                      |       | $15.01-20.00               |       | —                    |       | 8,578          |       | —         |       | 140,482        |       | —                                     |       | —                           |       | —                                          |       |
|                      |       | TOTAL                      |       | 16,700                    |       | 106,770        |       | 318,810        |       | 242,730        |       | 150,000                                    |       | —                           |       | —                                          |       |
|                      |       |                       |       |                      |       |           |       |           |       |           |       |                                       |       |                             |       |                                            |       |
| **Available  for Grant:** |       |                       |       |                      |       |           |       |           |       |           |       |                                       |       |                             |       |                                            |       |
| December 31, 2004         |       | —                     |       | —                    |       | —         |       | —         |       | 4,500          |       | —                                     |       | 122,340                          |       | 124,000                                         |       |
| December 31, 2003         |       | —                     |       | —                    |       | —         |       | —         |       | 120,876        |       | —                                     |       | 1,006,972                        |       | 156,000                                         |       |
| December 31, 2002         |       | —                     |       | —                    |       | —         |       | —         |       | —         |       | —                                     |       | 2,124,006                        |       | 184,000                                         |       |

 

The following table summarizes the stock optionactivity under the Company’s benefit plans:

 
| ** **                                           | ** ** | **Per  Share Price Range** | ** ** | **1999  Directors  Plan** | ** ** | **1993  Plan** | ** ** | **1997  Plan** | ** ** | **1999  Plan** | ** ** | **Chief  Executive  Officer’s  Plan** | ** ** | **2002  Stock  Incentive  Plan** | ** ** | **2002  Non-  Employee  Directors  Plan** | ** ** |
|------------------------------------------------------|------------|----------------------------|------------|---------------------------|------------|----------------|------------|----------------|------------|----------------|------------|--------------------------------------------|------------|----------------------------------|------------|-------------------------------------------|------------|
| Balance at  12/31/01                                 |       |                       |       | 23,366                    |       | 456,380        |       | 697,640        |       | 1,034,572      |       | 600,000                                    |       | —                           |       | —                                    |       |
| Granted                                              |       | $16.48-16.73               |       | —                    |       | —         |       | —         |       | 340,000        |       | —                                     |       | 375,994                          |       | 36,000                                    |       |
| Exercised                                            |       | $2.30-17.50                |       | (6,666                    | )          | (323,756       | )          | (354,630       | )          | (81,666        | )          | —                                     |       | —                           |       | —                                    |       |
| Forfeited or  expired                                |       | $2.30-18.17                |       | —                    |       | (22,570        | )          | (24,200        | )          | (30,140        | )          | —                                     |       | —                           |       | —                                    |       |
| Balance at  12/31/02                                 |       |                       |       | 16,700                    |       | 110,054        |       | 318,810        |       | 1,262,766      |       | 600,000                                    |       | 375,994                          |       | 36,000                                    |       |
| Granted                                              |       | $16.18-22.33               |       | —                    |       | —         |       | —         |       | —         |       | —                                     |       | 1,129,900                        |       | 32,000                                    |       |
| Exercised                                            |       | $2.30-18.17                |       | —                    |       | (16,028        | )          | (144,224       | )          | (130,402       | )          | —                                     |       | (36,160                          | )          | —                                    |       |
| Forfeited or  expired                                |       | $6.63-18.91                |       | —                    |       | (94,026        | )          | —         |       | (668           | )          | —                                     |       | (12,866                          | )          | (4,000                                    | )          |
| Balance at  12/31/03                                 |       |                       |       | 16,700                    |       | —         |       | 174,586        |       | 1,131,696      |       | 600,000                                    |       | 1,456,868                        |       | 64,000                                    |       |
| Granted                                              |       | $23.56-31.06               |       | —                    |       | —         |       | —         |       | 140,876        |       | —                                     |       | 956,841                          |       | 32,000                                    |       |
| Exercised                                            |       | $2.30-19.02                |       | (10,100                   | )          | —         |       | (127,050       | )          | (375,653       | )          | —                                     |       | (168,900                         | )          | —                                    |       |
| Forfeited or  expired                                |       | $13.32-28.35               |       | —                    |       | —         |       | —         |       | (24,500        | )          | —                                     |       | (72,209                          | )          | —                                    |       |
| Balance at  12/31/04                                 |       |                       |       | 6,600                     |       | —         |       | 47,536         |       | 872,419        |       | 600,000                                    |       | 2,172,600                        |       | 96,000                                    |       |
| Weighted-average  remaining contractual life (years) |       |                       |       | 1.8                       |       | —         |       | 2.3            |       | 5.0            |       | 4.3                                        |       | 6.1                              |       | 5.4                                       |       |

 

The following table summarizes the weighted averageoption exercise price information under the Company’s benefit plans:

 
| ** **           | ** ** | **1999 Directors Plan** | ** ** | **1993  Plan** | ** ** | **1997  Plan** | ** ** | **1999  Plan** | ** ** | **Chief  Executive  Officer’s  Plan** | ** ** | **2002  Stock  Incentive  Plan** | ** ** | **2002  Non-  Employee  Directors  Plan** | ** ** |
|----------------------|------------|-------------------------|------------|----------------|------------|----------------|------------|----------------|------------|--------------------------------------------|------------|----------------------------------|------------|-------------------------------------------|------------|
| Balance at  12/31/01 |       | 2.76                    |       | 9.08           |       | 4.04           |       | 15.81          |       | 12.51                                      |       | —                           |       | —                                    |       |
| Granted              |       | —                  |       | —         |       | —         |       | 16.48          |       | —                                     |       | 16.49                            |       | 18.91                                     |       |
| Exercised            |       | (2.76                   | )          | (7.99          | )          | (3.38          | )          | (11.25         | )          | —                                     |       | —                           |       | —                                    |       |
| Forfeited or expired |       | —                  |       | (17.50         | )          | (2.96          | )          | (13.23         | )          | —                                     |       | —                           |       | —                                    |       |
| Balance at  12/31/02 |       | $                       | 2.76       |           | $          | 9.87           |       | $              | 4.87       |                                       | $          | 16.34                            |       | $                                         | 12.51      |   | $ | 16.49 |   | $ | 18.91 |   |
| Granted              |       | —                  |       | —         |       | —         |       | —         |       | —                                     |       | 18.91                            |       | 19.38                                     |       |
| Exercised            |       | —                  |       | (9.21          | )          | (5.30          | )          | (11.79         | )          | —                                     |       | (16.52                           | )          | —                                    |       |
| Forfeited or expired |       | —                  |       | (14.51         | )          | —         |       | (11.73         | )          | —                                     |       | (16.48                           | )          | (18.91                                    | )          |
| Balance at  12/31/03 |       | $                       | 2.76       |           | $          | —         |       | $              | 4.52       |                                       | $          | 16.87                            |       | $                                         | 12.51      |   | $ | 18.37 |   | $ | 19.15 |   |
| Granted              |       | —                  |       | —         |       | —         |       | 28.35          |       | —                                     |       | 28.45                            |       | 27.69                                     |       |
| Exercised            |       | (2.76                   | )          | —         |       | (4.94          | )          | (16.93         | )          | —                                     |       | (17.86                           | )          | —                                    |       |
| Forfeited or expired |       | —                  |       | —         |       | —         |       | (15.68         | )          | —                                     |       | (18.67                           | )          | —                                    |       |
| Balance at  12/31/04 |       | $                       | 2.76       |           | $          | —         |       | $              | 3.37       |                                       | $          | 18.72                            |       | $                                         | 12.51      |   | $ | 22.83 |   | $ | 21.99 |   |

 

73

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**NOTE 12- QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):**

 

Thefollowing summarizes certain quarterly results of operations (000s, except pershare amounts):

 
| ** **                     | ** ** | **Operating  Revenues** | ** ** | **Gross  Profit (a)** | ** ** | **Income  Before  Cumulative  Effect of  Change in  Accounting  Principle** | ** ** | **Earnings Per  Share of  Common Stock  Before  Cumulative  Effect of Change  in Accounting  Principle** | ** ** | **Net Income** | ** ** | **Earnings Per  Share of  Common  Stock** | ** ** | **Earnings Per  Share of  Common Stock –  Assuming  Dilution** | ** ** |
|--------------------------------|------------|-------------------------|------------|-----------------------|------------|-----------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------|------------|----------------|------------|-------------------------------------------|------------|---------------------------------------------------------------------|------------|
| 2004 quarter ended (as filed): |       |                    |       |                  |       |                                                                        |       |                                                                                                     |       |           |       |                                      |       |                                                                |       |
| March 31                       |       | $                       | 771,216    |                  | $          | 54,130                                                                      |       | $                                                                                                        | 24,374     |           | $          | 0.34                                      |       | $                                                                   | 29,088     |   | $ | 0.41 |   | $ | 0.40 |   |
| June 30                        |       | 726,303                 |       | 50,836                |       | 13,975                                                                      |       | 0.19                                                                                                     |       | 13,975         |       | 0.19                                      |       | 0.19                                                                |       |
| September 30                   |       | 718,255                 |       | 69,498                |       | 35,118                                                                      |       | 0.48                                                                                                     |       | 35,118         |       | 0.48                                      |       | 0.47                                                                |       |
| December 31                    |       | 853,939                 |       | 81,900                |       | 41,034                                                                      |       | 0.55                                                                                                     |       | 41,034         |       | 0.55                                      |       | 0.55                                                                |       |
|                           |       | $                       | 3,069,713  |                  | $          | 256,364                                                                     |       | $                                                                                                        | 114,501    |           | $          | 1.56                                      |       | $                                                                   | 119,215    |   | $ | 1.63 |   | $ | 1.61 |   |
|                           |       |                    |       |                  |       |                                                                        |       |                                                                                                     |       |           |       |                                      |       |                                                                |       |
| 2004 quarter ended (Restated): |       |                    |       |                  |       |                                                                        |       |                                                                                                     |       |           |       |                                      |       |                                                                |       |
| March 31                       |       | $                       | 779,680    |                  | $          | 62,594                                                                      |       | $                                                                                                        | 29,720     |           | $          | 0.42                                      |       | $                                                                   | 34,434     |   | $ | 0.49 |   | $ | 0.49 |   |
| June 30                        |       | 725,838                 |       | 61,033                |       | 13,649                                                                      |       | 0.19                                                                                                     |       | 13,649         |       | 0.19                                      |       | 0.18                                                                |       |
| September 30                   |       | 693,679                 |       | 44,922                |       | 19,465                                                                      |       | 0.26                                                                                                     |       | 19,465         |       | 0.26                                      |       | 0.26                                                                |       |
| December 31                    |       | 883,971                 |       | 111,932               |       | 60,211                                                                      |       | 0.81                                                                                                     |       | 60,211         |       | 0.81                                      |       | 0.80                                                                |       |
|                           |       | $                       | 3,083,168  |                  | $          | 280,481                                                                     |       | $                                                                                                        | 123,045    |           | $          | 1.68                                      |       | $                                                                   | 127,759    |   | $ | 1.75 |   | $ | 1.73 |   |
|                           |       |                    |       |                  |       |                                                                        |       |                                                                                                     |       |           |       |                                      |       |                                                                |       |
| 2003 quarter ended (as filed): |       |                    |       |                  |       |                                                                        |       |                                                                                                     |       |           |       |                                      |       |                                                                |       |
| March 31                       |       | $                       | 888,106    |                  | $          | 65,490                                                                      |       | $                                                                                                        | 30,099     |           | $          | 0.42                                      |       | $                                                                   | 23,375     |   | $ | 0.32 |   | $ | 0.31 |   |
| June 30                        |       | 660,491                 |       | 48,935                |       | 20,900                                                                      |       | 0.29                                                                                                     |       | 20,900         |       | 0.29                                      |       | 0.28                                                                |       |
| September 30                   |       | 666,800                 |       | 49,193                |       | 20,889                                                                      |       | 0.29                                                                                                     |       | 20,889         |       | 0.29                                      |       | 0.28                                                                |       |
| December 31                    |       | 658,613                 |       | 46,812                |       | 19,055                                                                      |       | 0.27                                                                                                     |       | 19,055         |       | 0.27                                      |       | 0.26                                                                |       |
|                           |       | $                       | 2,874,010  |                  | $          | 210,430                                                                     |       | $                                                                                                        | 90,943     |           | $          | 1.27                                      |       | $                                                                   | 84,219     |   | $ | 1.17 |   | $ | 1.13 |   |
|                           |       |                    |       |                  |       |                                                                        |       |                                                                                                     |       |           |       |                                      |       |                                                                |       |
| 2003 quarter ended (Restated): |       |                    |       |                  |       |                                                                        |       |                                                                                                     |       |           |       |                                      |       |                                                                |       |
| March 31                       |       | $                       | 895,935    |                  | $          | 73,319                                                                      |       | $                                                                                                        | 35,043     |           | $          | 0.50                                      |       | $                                                                   | 28,319     |   | $ | 0.40 |   | $ | 0.38 |   |
| June 30                        |       | 663,311                 |       | 51,755                |       | 22,423                                                                      |       | 0.31                                                                                                     |       | 22,423         |       | 0.31                                      |       | 0.30                                                                |       |
| September 30                   |       | 672,286                 |       | 54,679                |       | 24,693                                                                      |       | 0.34                                                                                                     |       | 24,693         |       | 0.34                                      |       | 0.33                                                                |       |
| December 31                    |       | 648,219                 |       | 36,418                |       | 12,500                                                                      |       | 0.17                                                                                                     |       | 12,500         |       | 0.17                                      |       | 0.17                                                                |       |
|                           |       | $                       | 2,879,751  |                  | $          | 216,171                                                                     |       | $                                                                                                        | 94,659     |           | $          | 1.32                                      |       | $                                                                   | 87,935     |   | $ | 1.22 |   | $ | 1.18 |   |

 

----

(a)          Excludesselling and administrative, interest and income tax expenses, (gains) or losseson sale of assets and the cumulative effect of the change in accountingprinciple.

 

74

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**SUPPLEMENTALINFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):**

 

***Costs.*** The following tables set forth capitalizedcosts at December 31, 2004, 2003 and 2002 and costs incurred for oil and gasproducing activities for the years ended December 31, 2004, 2003 and 2002(000s):

 
| ** **                                   | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|----------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Capitalized  costs:                          |       |     |       |     |       |     |       |
| Proved properties                            |       | $        | 475,448    |     | $          | 315,635  |       | $ | 239,579 |   |
| Unproved properties                          |       | 134,519  |       | 83,384   |       | 64,451   |       |
| Total                                        |       | 609,967  |       | 399,019  |       | 304,030  |       |
| Less  accumulated depreciation and depletion |       | (149,624 | )          | (111,658 | )          | (79,050  | )          |
| Net  capitalized costs                       |       | $        | 460,343    |     | $          | 287,361  |       | $ | 224,980 |   |
|                                         |       |     |       |     |       |     |       |
| Costs  incurred:                             |       |     |       |     |       |     |       |
| Acquisition  of properties                   |       |     |       |     |       |     |       |
| Proved                                       |       | $        | 47,775     |     | $          | 14,202   |       | $ | 426 |   |
| Unproved                                     |       | 36,776   |       | 10,279   |       | 2,770    |       |
| Development  costs                           |       | 95,466   |       | 60,479   |       | 48,648   |       |
| Exploration  costs                           |       | 38,098   |       | 18,089   |       | 22,547   |       |
| Total costs  incurred                        |       | $        | 218,115    |     | $          | 103,049  |       | $ | 74,391 |   |

 

***Results of Operations.***** **The results of operations for oil and gasproducing activities, excluding corporate overhead and interest costs, for theyears ended December 31, 2004, 2003 and 2002 are as follows (000s):

 
| ** **                                | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Revenues  from sale of oil and gas:       |       |     |       |     |       |     |       |
|                                      |       |     |       |     |       |     |       |
| Sales                                     |       | $        | 10,767     |     | $          | 5,905    |       | $ | 2,227 |   |
| Transfers                                 |       | 251,585  |       | 220,107  |       | 112,137  |       |
| Total                                     |       | 262,352  |       | 226,012  |       | 114,364  |       |
| Production  costs                         |       | (106,732 | )          | (86,800  | )          | (65,536  | )          |
| Exploration  costs                        |       | (7,093   | )          | (6,764   | )          | (3,543   | )          |
| Depreciation,  depletion and amortization |       | (46,977  | )          | (31,385  | )          | (25,691  | )          |
| Income tax  expense                       |       | (68,426  | )          | (57,342  | )          | (7,558   | )          |
| Results of  operations                    |       | $        | 33,124     |     | $          | 43,721   |       | $ | 12,036 |   |

 

***Reserve Quantity Information. ***Reserveestimates are subject to numerous uncertainties inherent in the estimation ofquantities of proved reserves and in the projection of future rates ofproduction and the timing of development expenditures.  The accuracy of such estimates is a functionof the quality of available data and of engineering and geologicalinterpretation and judgment.  Estimatesof economically recoverable reserves and of future net cash flows expectedthere from prepared by different engineers or by the same engineers atdifferent times may vary substantially. Results of subsequent drilling, testingand production may cause either upward or downward revisions of previousestimates. Further, the volumes considered to be commercially recoverablefluctuate with changes in commodity prices and operating costs. Any significantrevision of reserve estimates could materially adversely affect the Company’sfinancial condition, results of operations and cash flows.

 

Thefollowing table sets forth information for the years ended December 31, 2004,2003 and 2002 with respect to changes in the Company’s proved (i.e. proveddeveloped and undeveloped) reserves, all of which are in the United States.

 

75

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| ** **                                  | ** ** | **Natural Gas  (MMcf)** | ** ** | **Crude Oil  (MBbls)** | ** ** |
|---------------------------------------------|------------|-------------------------|------------|------------------------|------------|
| December 31,  2001                          |       | 470,237                 |       | 661                    |       |
| Revisions of  previous estimates            |       | (88,344                 | )          | 51                     |       |
| Extensions  and discoveries                 |       | 246,704                 |       | 554                    |       |
| Purchases of  reserves in place             |       | (532                    | )          | —                 |       |
| Production                                  |       | (47,401                 | )          | (53                    | )          |
| December 31,  2002                          |       | 580,664                 |       | 1,213                  |       |
| Revisions of  previous estimates            |       | (65,474                 | )          | 571                    |       |
| Extensions  and discoveries                 |       | 191,751                 |       | 887                    |       |
| Purchases of  reserves in place             |       | 14,005                  |       | 57                     |       |
| Production                                  |       | (52,222                 | )          | (75                    | )          |
| December 31,  2003                          |       | 668,724                 |       | 2,653                  |       |
| Revisions of  previous estimates            |       | (82,300                 | )          | (85                    | )          |
| Extensions  and discoveries                 |       | 241,300                 |       | 1,058                  |       |
| Purchases of  reserves in place             |       | 26,676                  |       | 112                    |       |
| Sales of  reserves in place                 |       | (9,072                  | )          | —                 |       |
| Production                                  |       | (54,892                 | )          | (97                    | )          |
| December 31,  2004                          |       | 790,436                 |       | 3,641                  |       |
|                                        |       |                    |       |                   |       |
| Proved  developed reserves, included above: |       |                    |       |                   |       |
| December 31,  2001                          |       | 252,266                 |       | 262                    |       |
| December 31,  2002                          |       | 265,300                 |       | 400                    |       |
| December 31,  2003                          |       | 282,374                 |       | 823                    |       |
| December 31,  2004                          |       | 316,563                 |       | 1,209                  |       |

 

***Standardized Measures of Discounted Future Net Cash Flows.*** Estimated discounted future net cash flows andchanges therein were determined in accordance with SFAS No. 69, “Disclosuresabout Oil and Gas Producing Activities.” Certain information concerning the assumptions used in computing thevaluation of proved reserves and their inherent limitations are discussedbelow.  The Company believes suchinformation is essential for a proper understanding and assessment of the datapresented.

 

Futurecash inflows are computed by applying year-end prices of oil and gas relatingto the Company’s proved reserves to the year-end quantities of those reserves.

 

Theassumptions used to compute estimated future cash inflows do not necessarilyreflect the Company’s expectations of actual revenues or costs, or theirpresent worth.  In addition, variationsfrom the expected production rate also could result directly or indirectly fromfactors outside of the Company’s control, such as unexpected delays indevelopment, changes in prices or regulatory or environmental policies.  The reserve valuation further assumes thatall reserves will be disposed of by production. However, if reserves are sold in place, additional economicconsiderations could also affect the amount of cash eventually realized.

 

Futuredevelopment and production costs are computed by estimating the expenditures tobe incurred in developing and producing the proved oil and gas reserves at theend of the year, based on year-end costs and assuming continuation of existingeconomic conditions.  Also included inthis caption are asset retirement obligations.

 

Futureincome tax expenses are computed by applying the appropriate year-end statutorytax rates, with consideration of future tax rates already legislated, to thefuture pre-tax net cash flows relating to the Company’s proved oil and gasreserves.  Permanent differences in oiland gas related tax credits and allowances are recognized.

 

Anannual discount rate of 10% was used to reflect the timing of the future netcash flows relating to proved oil and gas reserves.

 

Informationwith respect to the Company’s estimated discounted future cash flows from itsoil and gas properties for the years ended December 31, 2004, 2003 and 2002 isas follows (000s):

 

76

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| ** **                                                                                        | ** ** | **2004**  | ** ** | **2003**  | ** ** | **2002**  | ** ** |
|---------------------------------------------------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Future cash  inflows                                                                              |       | $         | 3,872,043  |      | $          | 3,152,573 |       | $ | 1,587,891 |   |
| Future  production costs                                                                          |       | (950,891  | )          | (710,999  | )          | (463,471  | )          |
| Future  development costs                                                                         |       | (411,257  | )          | (275,302  | )          | (193,255  | )          |
| Future  income tax expense                                                                        |       | (838,615  | )          | (740,314  | )          | (305,263  | )          |
| Future net  cash flows                                                                            |       | 1,671,280 |       | 1,425,958 |       | 625,902   |       |
| 10% annual  discount for estimated timing of cash flows                                           |       | (872,035  | )          | (740,598  | )          | (265,250  | )          |
| Standardized measure of discounted future  net cash flows relating to proved oil and gas reserves |       | $         | 799,245    |      | $          | 685,360   |       | $ | 360,652 |   |

 

Principalchanges in the Company’s estimated discounted future net cash flows for theyears ended December 31, 2004, 2003 and 2002 are as follows (000s):

 
| ** **                                                               | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|--------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| As of  January 1,                                                        |       | $        | 685,360    |     | $          | 360,652  |       | $ | 171,370 |   |
| Sales and  transfers of oil and gas produced, net of production costs    |       | (155,620 | )          | (139,211 | )          | (50,828  | )          |
| Net changes  in prices and production costs related to future production |       | (35,978  | )          | 578,659  |       | 263,448  |       |
| Development  costs incurred during the period                            |       | 95,466   |       | 60,479   |       | 40,753   |       |
| Changes in  estimated future development costs                           |       | (78,593  | )          | (22,565  | )          | (42,869  | )          |
| Changes in  extensions and discoveries                                   |       | 365,896  |       | 272,110  |       | 148,114  |       |
| Revisions of  previous quantity estimates                                |       | (161,703 | )          | (321,395 | )          | (87,705  | )          |
| Purchases  (sales) of reserves in place                                  |       | 25,643   |       | 22,898   |       | (586     | )          |
| Accretion of  discount                                                   |       | 104,118  |       | 53,655   |       | 24,118   |       |
| Net change  in income taxes                                              |       | (45,344  | )          | (179,922 | )          | (105,163 | )          |
| As of  December 31,                                                      |       | $        | 799,245    |     | $          | 685,360  |       | $ | 360,652 |   |

 

**ITEM9.****              ****CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ANDFINANCIAL****DISCLOSURE**

 

None.

 

**ITEM9A. CONTROLS AND PROCEDURES**

 

***Disclosure Controls and Procedures.***

 

The Company’s management evaluated, under thesupervision and with the participation of the Chief Executive Officer and ChiefFinancial Officer, the effectiveness of the Company’s disclosure controls andprocedures, as such term is defined under Rule 13a-15(e) under the SecuritiesExchange Act of 1934, as of the end of the period covered by this Annual Reporton Form 10-K/A.  Based on thisevaluation, the Chief Executive Officer and Chief Financial Officer haveconcluded that because of the material weakness in internal control overfinancial reporting identified in Management’s Report on Internal Control overFinancial Reporting (restated) appearing in Item 8 on page 43, our disclosure controls and procedures were ineffective asof December 31, 2004, to ensure that information we are required to disclose inreports that we file or submit under the Securities Exchange Act of 1934 is recorded,processed, summarized and reported within the time periods specified inSecurities and Exchange Commission rules and forms and that such information isaccumulated and communicated to the Company’s management, including its ChiefExecutive Officer and Chief Financial Officer, as appropriate, to allow timelydecisions regarding required disclosures. Notwithstanding this material weakness, management believes thatthe Company’s financial condition, results of operations and cash flows arefairly stated as of December 31, 2004 and 2003 and for each of the threeyears in the period ended December 31, 2004.

 

***Remediation Effortsto Address This Material Weakness.***

 

In the fourth quarter of 2005, we implementedcontrols to ensure that all contracts accounted for as derivatives are reviewedas to their terms and the markets on which they are traded to reaffirm thateach contract meets the definition of a derivative.  This control will be performed on a monthlybasis.

 

***Changes in Internal Control Over FinancialReporting.***

 

There were no changes inour internal control over financial reporting during the quarter endedDecember 31, 2004, that have materially affected, or are reasonably likelyto materially affect, our internal control over financial reporting.

 

**ITEM 9B. OTHER INFORMATION**

 

None.

 

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**PARTIII**

 

**ITEM10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT**

 

**ITEM11. EXECUTIVE COMPENSATION**

 

**ITEM12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATEDSTOCKHOLDER MATTERS**

 

**ITEM13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS**

 

**ITEM14. PRINCIPAL ACCOUNTANT FEES AND SERVICES**

 

Pursuantto instruction G (3) to Form 10-K, Items 10, 11, 12, 13 and 14 are omittedbecause the Company will file a definitive proxy statement (the “ProxyStatement”) pursuant to Regulation 14A under the Securities Exchange Act of1934 not later than 120 days after the close of the fiscal year.  The information required by such Items willbe included in the Proxy Statement to be so filed for the Company’s annualmeeting of stockholders scheduled for May 6, 2005 and is hereby incorporated byreference.

 

**ITEM15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES**

 

(a)The following documents are filed as part of this report:

 

(1) Financial Statements:

 

Referenceis made to page 38 for a list of all financial statements filed as a part ofthis report.

 

(2) Financial Statement Schedules:

 

Nonerequired.

 

(3)  Exhibits:

 

3.1                Certificate of Incorporation ofWestern Gas Resources, Inc.  (previouslyfiled as Exhibit 3.1 to our Registration Statement on Form S-1, RegistrationNo. 33-31604 and incorporated herein by reference).

 

3.2                Certificateof Amendment to the Certificate of Incorporation of Western Gas Resources,Inc.  (previously filed as Exhibit 3.2 toour Registration Statement on Form S-1, Registration No. 33-31604 andincorporated herein by reference).

 

3.3                Certificateof Designation, Preferences and Rights of Series A Junior ParticipatingPreferred Stock (previously filed as part of Exhibit 1 to our Form 8-A filed onMarch 30, 2001 and incorporated herein by reference).

 

3.4                Certificateof Designation of the $2.625 Cumulative Convertible Preferred Stock of WesternGas Resources, Inc.  (previously filed inour Current Report on Form 8-K filed on February 25, 1994 and incorporatedherein by reference).

 

3.5               Amended and Restated Bylawsof Western Gas Resources, Inc., adopted by the Board of Directors on May 7,2004 (previously filed as Exhibit 99.1 to our Current Report on Form 8-K filedon May 11, 2004 and incorporated herein by reference).

 

4.1                RightsAgreement, dated as of March 22, 2001 between Western Gas Resources, Inc., andFleet National Bank as Rights Agent, including exhibits thereto (previouslyfiled as Exhibit 1 to our Form 8-A filed on March 30, 2001 and incorporatedherein by reference).

 

4.2                Indenturebetween Western Gas Resources, Inc. and Guarantors to Chase Bank of Texas,National Association, Trustee for $225,000,000 Senior Subordinated Notes Due2009, dated June 15, 1999  (previouslyfiled as Exhibit 28 to our Quarterly Report on Form 10-Q filed on August 13,1999 and incorporated herein by reference).

 

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4.3                WesternGas Resources, Inc. First Supplemental Indenture to 10% Senior SubordinatedNotes due 2009 dated October 19, 1999 (previously filed as Exhibit 4.10 to ourAnnual Report on Form 10-K filed on March 15, 2001 and incorporated herein byreference).

 

4.4                WesternGas Resources, Inc. Second Supplemental Indenture to 10% Senior SubordinatedNotes due 2009 dated September 29, 2000 (previously filed as Exhibit 4.11 toour Annual Report on Form 10-K filed on March 15, 2001 and incorporated hereinby reference).

 

4.5                WesternGas Resources, Inc. Third Supplemental Indenture to 10% Senior SubordinatedNotes due 2009 dated January 3, 2001 (previously filed as Exhibit 4.12 to ourAnnual Report on Form 10-K filed on March 15, 2001 and incorporated herein byreference).

 

10.1              Registration Rights Agreement amongWestern Gas Resources, Inc., WGP, Inc., Heetco, Inc., NV, Dean Phillips, Inc.,Sauvage Gas Company and Sauvage Gas Service, Inc.  (previously filed as Exhibit 10.14 to ourRegistration Statement on Form S-4, Registration No. 33-39588 dated March 27,1991 and incorporated herein by reference).

 

10.2               Amendment No. 1 to RegistrationRights Agreement, dated as of May 1, 1991, between Western Gas Resources, Inc.,Bill Sanderson, WGP, Inc., Dean Phillips, Inc., Heetco, Inc. NV, Sauvage GasCompany and Sauvage Gas Service, Inc. (previously filed as Exhibit 4.2 to our Quarterly Report on Form 10-Qfiled for the quarter ended June 30, 1991 and incorporated herein byreference).

 

10.3              Third Amended and Restated MasterShelf Agreement, dated as of December 19, 1991 (effective as of January 13,2003), by and among Western Gas Resources, Inc. and The Prudential InsuranceCompany of America, Pruco Life Insurance Company, Prudential InvestmentManagement Company, Inc. and ING Life Insurance & Annuity Company (previouslyfiled as Exhibit 10.29 to our Annual Report on Form 10-K filed on March 24,2003 and incorporated herein by reference).

 

10.4              Letter Amendment No. 1 to ThirdAmended and Restated Master Shelf Agreement, dated as of April 24, 2003, by andamong Western Gas Resources, Inc., The Prudential Insurance Company of America,Pruco Life Insurance Company, Prudential Investment Management, Inc. and INGLife Insurance & Annuity Company (previously filed as Exhibit 10.5 to ourQuarterly Report on Form 10Q filed on May 13, 2003 and incorporated herein byreference).

 

10.5              Letter Amendment No. 2 to ThirdAmended and Restated Master Shelf Agreement, dated as of June 29, 2004, by andamong Western Gas Resources, Inc. and The Prudential Insurance Company ofAmerica, Pruco Life Insurance Company, Prudential Investment Management, Inc.,ING Life Insurance & Annuity Company and each Purchaser listed on thePurchaser Schedule attached Thereto (previously filed as Exhibit 10.6 to ourCurrent Report on Form 8-K filed on July 1, 2004 and incorporated herein byreference).

 

10.6              Amended and Restated CreditAgreement, dated as of June 29, 2004, among Western Gas Resources, Inc., asBorrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, BNPParibas, JPMorgan Chase Bank, The Royal Bank of Scotland plc and Wachovia Bank,National Association, as Co-Syndication Agents, Union Bank of California, N.A.,U.S. Bank National Association and Wells Fargo Bank, N.A., as Co-DocumentationAgents, and the Other Lenders a Party Thereto (previously filed as Exhibit 10.1to our Current Report on Form 8-K filed on July 1, 2004 and incorporated hereinby reference).

 

10.7              First Amendment to Amended andRestated Credit Agreement, dated as of December 20, 2004, by and among WesternGas Resources, Inc. and bank of America, N.A., as Agent and the Lenders underthe Original Agreement (previously filed as Exhibit 10.1 to our Current Reporton Form 8-K filed on December 22, 2004 and incorporated herein by reference).

 

10.8              Continuing Guaranty, dated as ofJune 29, 2004, by MIGC, Inc., Western Gas Resources — Texas, Inc., MGTC, Inc.,Mountain Gas Resources, Inc. Lance Oil & Gas Company, Inc. and Western GasWyoming, L.L.C. in favor of Bank of America, N.A., as Administrative Agent(previously filed as Exhibit 10.2 to our Current Report on Form 8-K filed onJuly 1, 2004 and incorporated herein by reference).

 

10.9              Amended and Restated PledgeAgreement, dated as of June 29, 2004, by Western Gas Resources, Inc., in favorof Bank of America, N.A., as Administrative Agent (previously filed as Exhibit10.3 to our Current Report on Form 8-K filed on July 1, 2004 and incorporatedherein by reference).

 

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10.10            Amended and Restated SubsidiaryPledge Agreement, dated as of June 29, 2004, by MIGC, Inc., in favor of Bank ofAmerica, N.A., as Administrative Agent (previously filed as Exhibit 10.4 to ourCurrent Report on Form 8-K filed on July 1, 2004 and incorporated herein byreference).

 

10.11            Amended and Restated IntercreditorAgreement, dated as of June 29, 2004, by and among the Banks, Bank of America,N.A., as Administrative Agent for the Banks and The Prudential InsuranceCompany of America, Pruco Life Insurance Company, ING Life Insurance &Annuity Company, Prudential Investment Management, Inc., Pruco Life InsuranceCompany of New Jersey, Gibralter Life Insurance Co., Ltd., RGA ReinsuranceCompany, American Bankers Life Assurance Company of Florida, Inc., FortisBenefits Insurance Company and Connecticut General Life Insurance Company,consented to agreed by Western Gas Resources, Inc. and its subsidiaries listedtherein (previously filed as Exhibit 10.5 to our Current Report on Form 8-Kfiled on July 1, 2004 and incorporated herein by reference).

 

10.12            Credit Agreement, dated as of April24, 2003, among Western Gas Resources, Inc., as Borrower, Bank of America,N.A., as Administrative Agent and L/C Issuer, Bank One, NA and Fleet NationalBank, as Co-Syndication Agents, The Royal Bank of Scotland plc and WachoviaBank, National Association, as Co-Documentation Agents, and the Other LendersParty Thereto (previously filed as Exhibit 10.2 to our Quarterly Report on Form10-Q filed on May 13, 2003 and incorporated by reference herein).

 

10.13           Intercreditor Agreement, datedas of April 24, 2003, by and among the banks (as defined therein), Bank ofAmerica, N.A., as Administrative Agent for the banks and The PrudentialInsurance Company of America, Pruco Life Insurance Company, ING Life Insurance& Annuity Company and Prudential Investment Management, Inc., consented toagreed by Western Gas Resources, Inc. and its subsidiaries listed therein(previously filed as Exhibit 10.3 to Western Gas Resources, Inc., 10-Q datedMarch 31, 2002 and incorporated herein by reference).

 

10.14            Restated Retirement Plan of WesternGas Resources, Inc., dated May 1, 2001 (previously filed as Exhibit 4.9 toour Registration Statement on Form S-8 filed on August 14, 2002 andincorporated herein by reference).

 

10.15            Western Gas Resources, Inc., 1997Stock Option Plan (previously filed as Exhibit 10.29 to our Annual Report onForm 10-K filed on March 11, 2004 and incorporated herein by reference). *

 

10.16            First Amendment to the Western GasResources, Inc. 1997 Stock Option Plan (previously filed as Exhibit 10.30 toour Annual Report on Form 10-K filed on March 11, 2004 and incorporated hereinby reference). *

 

10.17            Second Amendment to the Western GasResources, Inc. 1997 Stock Option Plan (previously filed as Exhibit 10.31 toour Annual Report on Form 10-K filed on March 11, 2004 and incorporated hereinby reference). *

 

10.18            Western Gas Resources, Inc., 1999Stock Option Plan. (Previously filed as Exhibit 4.7 to our RegistrationStatement on Form S-8, Registration No. 333-95255, filed on January 24, 2000and incorporated herein by reference). *

 

10.19            First Amendment to the Western GasResources, Inc. 1999 Stock Option Plan (previously filed as Exhibit 10.33 toour Annual Report on Form 10-K filed on March 11, 2004 and incorporated hereinby reference). *

 

10.20            Second Amendment to the Western GasResources, Inc. 1999 Stock Option Plan (previously filed as Exhibit 10.34 toour Annual Report on Form 10-K filed on March 11, 2004 and incorporated hereinby reference). *

 

10.21            Western Gas Resources, Inc. 2002Stock Option Plan (previously filed as Exhibit 10.35 to our Annual Report onForm 10-K filed on March 11, 2004 and incorporated herein by reference).  *

 

10.22            First Amendment to the Western GasResources, Inc. 2002 Stock Option Plan (previously filed as Exhibit 10.36 toour Annual Report on Form 10-K filed on March 11, 2004 and incorporated hereinby reference). *

 

10.23            Western Gas Resources, Inc.Non-Employee Director’s Stock Option Plan (previously filed as part of Exhibit4.7 to our Registration Statement on Form S-8, Registration No. 333-95259,filed on January 24, 2000 and incorporated herein by reference). *

 

10.24            Western Gas Resources, Inc. 2002Non-Employee Director’s Stock Option Plan (previously filed as Exhibit 10.38 toour Annual Report on Form 10-K filed on March 11, 2004 and incorporated hereinby reference). *

 

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10.25            Stock Option Agreement, effectiveNovember 1, 2001, by and between Western Gas Resources, Inc. and Peter A. Dea(previously filed as Exhibit 99.1 to our Registration Statement on Form S-8filed on December 21, 2002, and incorporated herein by reference).*

 

10.26            2001 Employment Agreement, datedJune 14, 2001, by and between Western Gas Resources, Inc. and Edward A. Aabak,together with 2001 Indemnification Agreement (previously filed as Exhibit 10.41to our Annual Report on Form 10-K filed on March 11, 2004 and incorporatedherein by reference). *

 

10.27            2001 Employment Agreement, datedJune 14, 2001, by and between Western Gas Resources, Inc. and John F. Chandler,together with 2001 Indemnification Agreement (previously filed as Exhibit 10.42to our Annual Report on Form 10-K filed on March 11, 2004 and incorporatedherein by reference). *

 

10.28            2001 Employment Agreement, datedOctober 15, 2001, by and between Western Gas Resources, Inc. and William J.Krysiak, together with 2001 Indemnification Agreement (previously filed asExhibit 10.43 to our Annual Report on Form 10-K filed on March 11, 2004 andincorporated herein by reference). *

 

10.29            2001 Employment Agreement, datedJune 14, 2001, by and between Western Gas Resources, Inc. and John C. Walter,together with 2001 Indemnification Agreement (previously filed as Exhibit 10.44to our Annual Report on Form 10-K filed on March 11, 2004 and incorporatedherein by reference). *

 

10.30            Employment Agreement, dated October15, 2001, by and between Western Gas Resources, Inc. and Peter A. Dea, togetherwith Indemnification Agreement, dated November 1, 2001 (previously filed asexhibits to the Stock Option Plan filed on Registration Statement on Form S-8,Registration Number 333-7573 and incorporated herein by reference). *

 

11.1Statement regarding computation of per share earnings.

 

21.1List of Subsidiaries of Western Gas Resources, Inc.

 

23.1Consent of PricewaterhouseCoopers LLP.  †

 

23.2Consent of Netherland, Sewell & Associates, Inc.  †

 

31.1  Section 302 Certification of the ChiefExecutive Officer.  †

 

31.2  Section 302 Certification of the ChiefFinancial Officer.  †

 

32.1Section 906 Certification of the Chief Executive Officer and ChiefFinancial Officer.  †

 

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*   Management contract or compensating plan orarrangement.

†Indicates exhibits filed with this Form 10-K.

 

(b)  Exhibits required by Item 601 of RegulationS-K. See (a) (3) above.

 

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SIGNATURES

 

Pursuantto the requirements of Section 13 or 15(d) of the Securities Exchange Act of1934, the Registrant has duly caused this report to be signed on its behalf bythe undersigned, thereunto duly authorized, in the City of Denver, State ofColorado on December 19, 2005.

 
|   | WESTERN  GAS RESOURCES, INC. |                                             |
|--------|------------------------------|--------------------------------------------------|
|   | (Registrant)                 |                                             |
|   |                         |
|   |                         |
|   | By:                          | /s/  Peter A. Dea                                |   |
|   |                         | Peter  A. Dea                                    |
|   |                         | Chief  Executive Officer, President and Director |
|        |                              |                                                  |  |  |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons on behalf of the Registrant and inthe capacities and on the dates indicated.

 

 
| /s/  Peter A. Dea          |                                          | Chief  Executive Officer, President and Director   | December 19,  2005 |
|----------------------------|-----------------------------------------------|----------------------------------------------------|-------------------------|
| Peter  A. Dea              | (Principal  Executive Officer)                |                                               |
|                       |                                          |                                               |
|                       |                                          |                                               |
| /s/  William J. Krysiak    |                                          | Executive  Vice President -Chief Financial Officer | December 19,  2005 |
| William  J. Krysiak        | (Principal  Financial and Accounting Officer) |                                               |
|                       |                                          |                                               |
|                       |                                          |                                               |
| /s/  James A. Senty        |                                          | Chairman  of the Board                             | December 19,  2005 |
| James  A. Senty            |                                          |                                               |
|                       |                                          |                                               |
|                       |                                          |                                               |
| /s/  Walter L. Stonehocker |                                          | Vice  Chairman of the Board                        | December 19,  2005 |
| Walter  L. Stonehocker     |                                          |                                               |
|                       |                                          |                                               |
|                       |                                          |                                               |
| /s/  Dean Phillips         |                                          | Director                                           | December 19,  2005 |
| Dean  Phillips             |                                          |                                               |
|                       |                                          |                                               |
|                       |                                          |                                               |
| /s/  Joseph E. Reid        |                                          | Director                                           | December 19,  2005 |
| Joseph  E. Reid            |                                          |                                               |
|                       |                                          |                                               |
|                       |                                          |                                               |
| /s/  Richard B. Robinson   |                                          | Director                                           | December 19,  2005 |
| Richard  B. Robinson       |                                          |                                               |

 

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| /s/  Bill M. Sanderson |   | Director | December 19,  2005 |
|------------------------|--------|----------|-------------------------|
| Bill  M. Sanderson     |   |     |
|                   |   |     |
|                   |   |     |
| /s/  Brion G. Wise     |   | Director | December 19,  2005 |
| Brion  G. Wise         |   |     |

 

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