**SECURITIESAND EXCHANGE COMMISSION**

 

**Washington, D.C. 20549**

 

**FORM 10-Q/A**

**(Amendment No. 1)**

 

**(MarkOne)**

 

| **ý** | ** ** | **QUARTERLY REPORT PURSUANT TO  SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                             |
|------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** ** | ** ** | ** **                                                                                                                                                                                                                                         |
| ** ** | ** ** | **FOR  THE QUARTERLY PERIOD ENDED MARCH 31, 2005**                                                                                                                                                                                            |
| ** ** | ** ** | ** **                                                                                                                                                                                                                                         |
| ** ** | ** ** | **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 itscharter)

 
| **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

 

**No Changes**

(Former name, former address and former fiscal year, if changed sincelast report).

 

Indicateby check mark whether the registrant (1) has filed all reports required tobe filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject tosuch filing requirements for the past 90 days. Yes ý  No o

 

Indicateby check mark whether the registrant is an accelerated filer (as defined inRule 12b-2 of the Exchange Act). Yes ý  No o

 

OnMay 4, 2005, there were 74,226,162 shares of the registrant’s Common Stockoutstanding.

 

 

----

 

**ExplanatoryNote:**

 

Our Quarterly Report on Form 10-Q for thequarter ended March 31, 2005, initially filed with the Securities andExchange Commission, or the SEC, on May 9, 2005, or the OriginalFiling, is being amended by this Form 10-Q/A to reflect restatements ofour Consolidated Balance Sheet at March 31, 2005 and December 31,2004; and our Consolidated Statement of Operations, Consolidated Statement ofCash Flows and Consolidated Statement of Changes in Stockholders’ Equity foreach of the three months ended March 31, 2005 and 2004, and the notesthereto.

 

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. OnNovember 8, 2005, after the release of our third quarter 2005 results andprior to the filing of the Form 10-Q for the quarter ended September 30,2005, it came to our attention that these contracts may not meet the definitionof a derivative.  On November 21,2005, we announced that our management and our audit committee had completed areview of the accounting treatment of our gas storage and gas transportationcontracts and determined that these contracts do not meet the definition of aderivative under generally accepted accounting principles. Specifically, aftera detailed review of the contracts and the market for those contracts, we determinedthat these contracts do not meet the definition of a derivative as:(i) the market for these types of contracts is not sufficiently liquid forus to receive fair value in a ready market and (ii) if any contract isassigned, there is no assurance that we will be relieved of our rights andobligations under that contract.

 

For a more detailed description of theserestatements, see the footnote “Restatement of Consolidated FinancialStatements” to the accompanying Consolidated Financial Statements and thesection entitled “Restatement” in Management’s Discussion and Analysis ofFinancial Condition and Results of Operations contained in thisForm 10-Q/A. Except for the foregoing amended information, thisForm 10-Q/A continues to describe conditions as of the date of theOriginal Filing, including our expectations with respect to our 2005 capitalbudget and other forward-looking information, and we have not updated thedisclosures contained herein to reflect events that occurred at a later date.Other events occurring after the filing of the Original Filing or otherdisclosures necessary to reflect subsequent events have been or will beaddressed in either our restated Quarterly Report on Form 10-Q/A for thequarterly period ended June 30, 2005 or our Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2005, all of whichare being filed concurrently with the filing of this Form 10-Q/A, or inother reports filed with the SEC subsequent to the date of this filing.

 

2

----

 

**Western Gas Resources, Inc.**

**Form 10-Q/A**

**Table of Contents**

 
| PART I - Financial Information |                                                                                                     |
|-------------------------------------|----------------------------------------------------------------------------------------------------------|
|                                |                                                                                                     |   |
|                                | Explanatory Note                                                                                         |   |
|                                |                                                                                                     |   |
| Item 1.                             | Financial Statements                                                                                     |   |
|                                |                                                                                                     |   |
|                                | Consolidated Balance Sheet - March 31,  2005 and December 31, 2004                             |   |
|                                |                                                                                                     |   |
|                                | Consolidated Statement of Cash Flows -  Three Months Ended March 31, 2005 and 2004                  |   |
|                                |                                                                                                     |   |
|                                | Consolidated Statement of Operations -  Three Months Ended March 31, 2005 and 2004                  |   |
|                                |                                                                                                     |   |
|                                | Consolidated Statement of Changes in  Stockholders’ Equity - Three Months Ended March 31, 2005 |   |
|                                |                                                                                                     |   |
|                                | Notes to Consolidated Financial Statements                                                               |   |
|                                |                                                                                                     |   |
| Item 2.                             | Management’s Discussion and Analysis of Financial Condition and  Results of Operations              |   |
|                                |                                                                                                     |   |
| Item 3.                             | Quantitative and Qualitative Disclosures  about Market Risk                                              |   |
|                                |                                                                                                     |   |
| Item 4.                             | Controls and Procedures                                                                                  |   |
|                                |                                                                                                     |   |
| PART II - Other Information    |                                                                                                     |
|                                |                                                                                                     |   |
| Item 1.                             | Legal Proceedings                                                                                        |   |
|                                |                                                                                                     |   |
| Item 6.                             | Exhibits                                                                                                 |   |
|                                |                                                                                                     |   |
| Signatures                          |                                                                                                     |

 

3

----

 

**PART I - FINANCIAL INFORMATION**

 

**ITEM 1.      FINANCIAL STATEMENTS**

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Unaudited)

(Dollars in thousands, except share data)

 
| ** **                                                                                                           | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                                                                                           | ** ** | **2005**           | ** ** | **2004**              | ** ** |
| ** **                                                                                                           | ** ** | **Restated**       | ** ** | **Restated**          | ** ** |
| ASSETS                                                                                                               |       |               |       |                  |       |
| Current  assets:                                                                                                     |       |               |       |                  |       |
| Cash and cash equivalents                                                                                            |       | $                  | 1,725      |                  | $          | 390 |   |
| Trade accounts receivable, net                                                                                       |       | 364,459            |       | 385,811               |       |
| Margin deposits                                                                                                      |       | 15,588             |       | 7,939                 |       |
| Inventory                                                                                                            |       | 64,592             |       | 94,604                |       |
| Assets from price risk management  activities                                                                        |       | 2,837              |       | 19,893                |       |
| Deferred income taxes                                                                                                |       | 9,432              |       | —                |       |
| Other                                                                                                                |       | 6,134              |       | 12,494                |       |
| Total current assets                                                                                                 |       | 464,767            |       | 521,131               |       |
| Property and  equipment:                                                                                             |       |               |       |                  |       |
| Gas gathering, processing and  transportation                                                                        |       | 1,191,722          |       | 1,150,904             |       |
| Oil and gas properties and equipment  (successful efforts method)                                                    |       | 512,175            |       | 495,314               |       |
| Construction in progress                                                                                             |       | 199,183            |       | 150,273               |       |
|                                                                                                                 |       | 1,903,080          |       | 1,796,491             |       |
| Less: Accumulated depreciation, depletion  and amortization                                                          |       | (598,233           | )          | (570,582              | )          |
| Total property and equipment, net                                                                                    |       | 1,304,847          |       | 1,225,909             |       |
| Other  assets:                                                                                                       |       |               |       |                  |       |
| Gas purchase contracts (net of accumulated  amortization of $41,124 and $40,652, respectively)                       |       | 34,426             |       | 27,704                |       |
| Assets from price risk management  activities                                                                        |       | 424                |       | 249                   |       |
| Equity investments                                                                                                   |       | 36,108             |       | 35,729                |       |
| Other                                                                                                                |       | 26,403             |       | 26,676                |       |
| Total other assets                                                                                                   |       | 97,361             |       | 90,358                |       |
| TOTAL ASSETS                                                                                                         |       | $                  | 1,866,975  |                  | $          | 1,837,398 |   |
|                                                                                                                 |       |               |       |                  |       |
| LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                            |       |               |       |                  |       |
| Current  liabilities:                                                                                                |       |               |       |                  |       |
| Accounts payable                                                                                                     |       | $                  | 387,310    |                  | $          | 400,672 |   |
| Accrued expenses                                                                                                     |       | 58,592             |       | 60,472                |       |
| Liabilities from price risk management  activities                                                                   |       | 28,979             |       | 4,321                 |       |
| Deferred income taxes                                                                                                |       | —             |       | 5,618                 |       |
| Dividends payable                                                                                                    |       | 3,710              |       | 3,704                 |       |
| Total current liabilities                                                                                            |       | 478,591            |       | 474,787               |       |
| Long-term  debt                                                                                                      |       | 385,900            |       | 382,000               |       |
| Liabilities  from price risk management activities                                                                   |       | 309                |       | 180                   |       |
| Other  long-term liabilities                                                                                         |       | 53,187             |       | 51,827                |       |
| Deferred  income taxes payable, net                                                                                  |       | 255,444            |       | 243,835               |       |
|                                                                                                                 |       |               |       |                  |       |
| Total  liabilities                                                                                                   |       | 1,173,431          |       | 1,152,629             |       |
|                                                                                                                 |       |               |       |                  |       |
| Stockholders’  equity:                                                                                          |       |               |       |                  |       |
| Common stock, par value $0.10; 100,000,000  shares authorized; 74,212,479 and 74,078,733 shares issued, respectively |       | 7,444              |       | 7,430                 |       |
| Treasury stock, at cost; 50,032 common  shares in treasury                                                           |       | (788               | )          | (788                  | )          |
| Additional paid-in capital                                                                                           |       | 394,962            |       | 392,437               |       |
| Retained earnings                                                                                                    |       | 297,424            |       | 281,428               |       |
| Accumulated other comprehensive income                                                                               |       | (5,498             | )          | 4,262                 |       |
|                                                                                                                 |       |               |       |                  |       |
| Total stockholders’ equity                                                                                      |       | 693,544            |       | 684,769               |       |
|                                                                                                                 |       |               |       |                  |       |
| TOTAL  LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                     |       | $                  | 1,866,975  |                  | $          | 1,837,398 |   |

 

Theaccompanying notes are an integral part of the consolidated financialstatements.

 

4

----

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(Dollars in thousands)

 
| ** **                                                                              | ** ** | **Three Months Ended  March 31,** | ** ** |
|-----------------------------------------------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                                                              | ** ** | **2005**                               | ** ** | **2004** | ** ** |
|                                                                                    |       |                                   |       |   |   |
| Reconciliation  of net income to net cash provided by operating activities:             |       |                                   |       |   |   |
| Net income                                                                              |       | $                                      | 19,706     |   | $ | 34,434 |   |
| Add income  items that do not affect cash:                                              |       |                                   |       |   |   |
| Depreciation, depletion and amortization                                                |       | 29,078                                 |       | 22,626 |   |
| Loss on sale of assets                                                                  |       | 28                                     |       | — |   |
| Deferred income taxes                                                                   |       | 4,078                                  |       | 13,583 |   |
| Non-cash change in fair value of  derivatives                                           |       | 28,677                                 |       | (2,245 | ) |
| Cumulative effect of change in accounting  principle                                    |       | —                                 |       | (4,714 | ) |
| Compensation expense from common stock  options                                         |       | 273                                    |       | 181 |   |
| Other non-cash items, net                                                               |       | (1,220                                 | )          | (2,940 | ) |
|                                                                                    |       |                                   |       |   |   |
| Adjustments  to working capital to arrive at net cash provided by operating activities: |       |                                   |       |   |   |
| Decrease in trade accounts receivable                                                   |       | 13,908                                 |       | 9,939 |   |
| Decrease in product inventory                                                           |       | 29,654                                 |       | 39,927 |   |
| (Increase) decrease in other current assets                                             |       | (994                                   | )          | 642 |   |
| (Increase) in other assets and liabilities,  net                                        |       | (674                                   | )          | (171 | ) |
| (Decrease) increase in accounts payable                                                 |       | (10,603                                | )          | 5,302 |   |
| Increase in accrued expenses                                                            |       | 5,485                                  |       | 7,932 |   |
|                                                                                    |       |                                   |       |   |   |
| Net cash  provided by operating activities                                              |       | 117,396                                |       | 124,496 |   |
|                                                                                    |       |                                   |       |   |   |
| Cash flows  from investing activities:                                                  |       |                                   |       |   |   |
|                                                                                    |       |                                   |       |   |   |
| Purchases of property and equipment,  including acquisitions                            |       | (115,332                               | )          | (35,441 | ) |
| Distributions from equity investees                                                     |       | 324                                    |       | — |   |
| Proceeds from the dispositions of property  and equipment                               |       | 767                                    |       | 315 |   |
|                                                                                    |       |                                   |       |   |   |
| Net cash  used in investing activities                                                  |       | (114,241                               | )          | (35,126 | ) |
|                                                                                    |       |                                   |       |   |   |
| Cash flows  from financing activities:                                                  |       |                                   |       |   |   |
|                                                                                    |       |                                   |       |   |   |
| Proceeds from exercise of common stock  options                                         |       | 2,307                                  |       | 2,918 |   |
| Change in outstanding checks                                                            |       | (4,283                                 | )          | 11,091 |   |
| Borrowings on revolving credit facility                                                 |       | 807,065                                |       | 260,850 |   |
| Payments on revolving credit facility                                                   |       | (803,165                               | )          | (354,850 | ) |
| Borrowings on long-term debt                                                            |       | 25,000                                 |       | — |   |
| Payments on long-term debt                                                              |       | (25,000                                | )          | — |   |
| Debt issue costs                                                                        |       | (40                                    | )          | — |   |
| Payments for redemption of preferred stock                                              |       | —                                 |       | (672 | ) |
| Dividends paid                                                                          |       | (3,704                                 | )          | (3,056 | ) |
|                                                                                    |       |                                   |       |   |   |
| Net cash  used in financing activities                                                  |       | (1,820                                 | )          | (83,719 | ) |
|                                                                                    |       |                                   |       |   |   |
| Net increase  in cash and cash equivalents                                              |       | 1,335                                  |       | 5,651 |   |
|                                                                                    |       |                                   |       |   |   |
| Cash and  cash equivalents at beginning of period                                       |       | 390                                    |       | 26,116 |   |
|                                                                                    |       |                                   |       |   |   |
| Cash and  cash equivalents at end of period                                             |       | $                                      | 1,725      |   | $ | 31,767 |   |

 

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

 

5

----

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited)

(Dollars in thousands, except share and per share amounts)

 
| ** **                                                                                         | ** ** | **Three Months Ended  March 31,** | ** ** |
|----------------------------------------------------------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                                                                         | ** ** | **2005**                               | ** ** | **2004** | ** ** |
| ** **                                                                                         | ** ** | **Restated**                           | ** ** | **Restated** | ** ** |
|                                                                                               |       |                                   |       |   |   |
| Revenues:                                                                                          |       |                                   |       |   |   |
| Sale of gas                                                                                        |       | $                                      | 696,219    |   | $ | 665,310 |   |
| Sale of natural gas liquids                                                                        |       | 132,969                                |       | 92,915 |   |
| Gathering, processing and transportation  revenue                                                  |       | 23,880                                 |       | 16,829 |   |
| Price risk management activities                                                                   |       | (20,248                                | )          | 2,984 |   |
| Other                                                                                              |       | 1,287                                  |       | 1,642 |   |
| Total revenues                                                                                     |       | 834,107                                |       | 779,680 |   |
|                                                                                               |       |                                   |       |   |   |
| Costs and  expenses:                                                                               |       |                                   |       |   |   |
| Product purchases                                                                                  |       | 707,354                                |       | 657,342 |   |
| Plant and transportation operating expense                                                         |       | 27,699                                 |       | 21,934 |   |
| Oil and gas exploration and production  expense                                                    |       | 24,896                                 |       | 17,110 |   |
| Depreciation, depletion and amortization                                                           |       | 29,078                                 |       | 22,626 |   |
| Loss on sale of assets                                                                             |       | 28                                     |       | — |   |
| Selling and administrative expense                                                                 |       | 12,532                                 |       | 9,946 |   |
| (Earnings) from equity investments                                                                 |       | (2,134                                 | )          | (1,926 | ) |
| Interest expense                                                                                   |       | 3,520                                  |       | 5,802 |   |
| Total costs and expenses                                                                           |       | 802,973                                |       | 732,834 |   |
| Income  before taxes                                                                               |       | 31,134                                 |       | 46,846 |   |
| Provision  for income taxes:                                                                       |       |                                   |       |   |   |
| Current                                                                                            |       | 7,350                                  |       | 3,543 |   |
| Deferred                                                                                           |       | 4,078                                  |       | 13,583 |   |
| Total provision for income taxes                                                                   |       | 11,428                                 |       | 17,126 |   |
|                                                                                               |       |                                   |       |   |   |
| Income before cumulative effect of changes  in accounting principles                               |       | 19,706                                 |       | 29,720 |   |
|                                                                                               |       |                                   |       |   |   |
| Cumulative effect of change in accounting  principle net of tax of $2,710                          |       | —                                 |       | 4,714 |   |
|                                                                                               |       |                                   |       |   |   |
| Net income                                                                                         |       | 19,706                                 |       | 34,434 |   |
|                                                                                               |       |                                   |       |   |   |
| Preferred stock requirements                                                                       |       | —                                 |       | (816 | ) |
|                                                                                               |       |                                   |       |   |   |
| Income attributable to common stock                                                                |       | $                                      | 19,706     |   | $ | 33,618 |   |
|                                                                                               |       |                                   |       |   |   |
| Net income per share of common stock before  cumulative effect of changes in accounting principles |       | $                                      | 0.27       |   | $ | 0.42 |   |
|                                                                                               |       |                                   |       |   |   |
| Cumulative effect of change in accounting  principle                                               |       | $                                      | —     |   | $ | 0.07 |   |
|                                                                                               |       |                                   |       |   |   |
| Earnings per share of common stock                                                                 |       | $                                      | 0.27       |   | $ | 0.49 |   |
|                                                                                               |       |                                   |       |   |   |
| Weighted average shares of common stock  outstanding                                               |       | 74,148,269                             |       | 68,365,900 |   |
|                                                                                               |       |                                   |       |   |   |
| Income attributable to common stock -  assuming dilution                                           |       | $                                      | 19,706     |   | $ | 34,434 |   |
|                                                                                               |       |                                   |       |   |   |
| Earnings per share of common stock -  assuming dilution                                            |       | $                                      | 0.26       |   | $ | 0.47 |   |
|                                                                                               |       |                                   |       |   |   |
| Weighted average shares of common stock  outstanding - assuming dilution                           |       | 75,559,318                             |       | 73,651,610 |   |

 

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

 

6

----

 

WESTERN GAS RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(Dollars in thousands, except share amounts)

 
| ** **                                             | ** ** | ** **     | ** ** | ** **       | ** ** | ** ** | ** ** | ** **   | ** ** | ** **     | ** ** | ** **   | ** ** | **Accumulated**    | ** ** | ** **        | ** ** |
|--------------------------------------------------------|------------|----------------|------------|------------------|------------|------------|------------|--------------|------------|----------------|------------|--------------|------------|--------------------|------------|-------------------|------------|
| ** **                                             | ** ** | ** **     | ** ** | **Shares**       | ** ** | ** ** | ** ** | ** **   | ** ** | ** **     | ** ** | ** **   | ** ** | **Other**          | ** ** | **Total**         | ** ** |
| ** **                                             | ** ** | **Shares**     | ** ** | **of  Common**   | ** ** | ** ** | ** ** | ** **   | ** ** | **Additional** | ** ** | ** **   | ** ** | **Comprehensive**  | ** ** | **Stock-**        | ** ** |
| ** **                                             | ** ** | **of  Common** | ** ** | **Stock**        | ** ** | **Common** | ** ** | **Treasury** | ** ** | **Paid-In**    | ** ** | **Retained** | ** ** | **Income  (Loss)** | ** ** | **holders’** | ** ** |
| ** **                                             | ** ** | **Stock**      | ** ** | **in  Treasury** | ** ** | **Stock**  | ** ** | **Stock**    | ** ** | **Capital**    | ** ** | **Earnings** | ** ** | **Net of  Tax**    | ** ** | **Equity**        | ** ** |
|                                                   |       |           |       |             |       |       |       |         |       |           |       |         |       |               |       |              |       |
| Balance at  December 31, 2004 (Restated)          |       | 74,078,733     |       | 50,032           |       | $          | 7,430      |         | $          | (788           | )          | $            | 392,437    |               | $          | 281,428           |       | $ | 4,262 |   | $ | 684,769 |   |
| Comprehensive  income:                                 |       |           |       |             |       |       |       |         |       |           |       |         |       |               |       |              |       |
| Net income, first  quarter of 2005 (Restated)          |       | —         |       | —           |       | —     |       | —       |       | —         |       | 19,706       |       | —             |       | 19,706            |       |
| Translation  adjustments                               |       | —         |       | —           |       | —     |       | —       |       | —         |       | —       |       | (2,271             | )          | (2,271            | )          |
| Other  comprehensive income                            |       |           |       |             |       |       |       |         |       |           |       |         |       |               |       |              |       |
| From equity  investees                                 |       | —         |       | —           |       | —     |       | —       |       | —         |       | —       |       | 77                 |       | 77                |       |
| Reclassification  adjustment for settled contracts     |       | —         |       | —           |       | —     |       | —       |       | —         |       | —       |       | (316               | )          | (316              | )          |
| Changes in fair  value of outstanding hedge positions  |       | —         |       | —           |       | —     |       | —       |       | —         |       | —       |       | (7,305             | )          | (7,305            | )          |
| Change in  estimated ineffectiveness                   |       | —         |       | —           |       | —     |       | —       |       | —         |       | —       |       | 55                 |       | 55                |       |
| Fair value of new  hedge positions                     |       | —         |       | —           |       | —     |       | —       |       | —         |       | —       |       | —             |       | —            |       |
| Change in  accumulated derivative comprehensive income |       | —         |       | —           |       | —     |       | —       |       | —         |       | —       |       | (7,566             | )          | (7,566            | )          |
| Total  comprehensive income, net of tax                |       | —         |       | —           |       | —     |       | —       |       | —         |       | —       |       | —             |       | 9,946             |       |
| Stock options  exercised                               |       | 133,746        |       | —           |       | 14         |       | —       |       | 2,293          |       | —       |       | —             |       | 2,307             |       |
| Compensation  expense from common stock options        |       | —         |       | —           |       | —     |       | —       |       | 273            |       | —       |       | —             |       | 273               |       |
| Tax benefit  related to stock options exercised        |       | —         |       | —           |       | —     |       | —       |       | (41            | )          | —       |       | —             |       | (41               | )          |
| Dividends  declared on common stock                    |       | —         |       | —           |       | —     |       | —       |       | —         |       | (3,710       | )          | —             |       | (3,710            | )          |
|                                                   |       |           |       |             |       |       |       |         |       |           |       |         |       |               |       |              |       |
| Balance at  March 31, 2005 (Restated)             |       | 74,212,479     |       | 50,032           |       | $          | 7,444      |         | $          | (788           | )          | $            | 394,962    |               | $          | 297,424           |       | $ | (5,498 | ) | $ | 693,544 |   |

 

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

 

7

----

 

WESTERN GAS RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

***GENERAL***

 

Wehave prepared the accompanying unaudited interim consolidated financialstatements under the rules and regulations of the SEC.  As provided by such rules andregulations, we have condensed or omitted certain information and notesnormally included in annual financial statements prepared in conformity withaccounting principles generally accepted in the United States of America.

 

Theinterim consolidated financial statements presented herein should be read inconjunction with the Consolidated Financial Statements and Notes theretoincluded in our Annual Report on Form 10-K/A for the year endedDecember 31, 2004.  The interimConsolidated Financial Statements as of March 31, 2005 and for thethree-month periods ended March 31, 2005 and 2004 included herein areunaudited but reflect, in the opinion of management, all adjustments (whichinclude only normal recurring adjustments) necessary to fairly present theresults for such periods.  The results ofoperations for the three months ended March 31, 2005 are not necessarilyindicative of the results of operations expected for the year endedDecember 31, 2005.

 

InMarch 2005, we revised our classification in the Statement of Cash Flowsfor the quarter ended March 31, 2004, of the Change in the balance ofoutstanding checks from a component of Net cash provided by operatingactivities 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$11.1 million for the quarter ended March 31, 2004, with a correspondingdecrease in cash flows used in financing activities.

 

***RESTATEMENT OF CONSOLIDATED FINANCIALSTATEMENTS***

 

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 of FAS133 as reflected in our consolidated financial statements.  Historically, we recorded these contracts atfair value with the changes in fair value reflected in earnings. OnNovember 8, 2005, after the release of our third quarter 2005 results andprior to the filing of the Form 10-Q for the quarter endedSeptember 30, 2005, it came to our attention that these contracts may notmeet the definition of a derivative.  OnNovember 21, 2005, we announced that our management and our auditcommittee had completed a review of the accounting treatment of our gas storageand gas transportation contracts and determined that these contracts do notmeet the definition of a derivative under generally accepted accountingprinciples. Specifically, after a detailed review of the contracts and themarket for those contracts, we determined that these contracts do not meet thedefinition of a derivative as: (i) the market for these types of contractsis not sufficiently liquid for us to receive fair value in a ready market and(ii) if any contract is assigned, there is no assurance that we will berelieved of our rights and obligations under that contract.  Accordingly,we have restated our audited financial statements for the years from 2001through 2004, included herein and the beginning retained earnings as ofJanuary 1, 2002.

 

Historically, the non-cash mark-to-market valuationof the gas storage and transportation contracts, which were considered to bederivatives, effectively offset non-cash mark-to-market changes to the forwardderivative contracts to sell our stored or transported natural gas.  The changes in both of these mark-to-marketvaluations were reflected in Price risk management activities on theConsolidated statement of operations and as reported in the marketingsegment.  After the adjustments tocorrect the prior accounting for the gas storage and gas transportationcontracts, the non-cash mark-to-market of the future sale derivative contractson the sale of gas will fluctuate through earnings with changes in marketprices and will not be offset by a corresponding mark-to-market on the gasstorage and transportation contracts.  Asthe stored or transported natural gas is sold and the forward sale derivativesare settled, we will realize the benefit of the storage and transportationtransactions through earnings.

 

The following table summarizes the impact of theaccounting adjustments necessary to correct the treatment of storage andtransportation contracts on our previously reported Net income in our originalQuarterly Report on Form 10-Q for the period ended March 31, 2005 asfiled on May 9, 2005 (000s):

 

8

----

 
| ** **                                       | ** ** | **Three months ending** | ** ** |
|--------------------------------------------------|------------|-------------------------|------------|
| ** **                                       | ** ** | **March 31, 2005** | ** ** | **March 31, 2004** | ** ** |
| Net income  as previously reported               |       | $                       | 32,628     |   | $ | 29,088 |   |
| Accounting  correction for derivatives (pre-tax) |       | (20,207                 | )          | 8,463 |   |
| Tax impact of above                              |       | 7,285                   |       | (3,117 | ) |
| Net income  as restated                          |       | $                       | 19,706     |   | $ | 34,434 |   |

 

Thefollowing is a summary of the impact of these accounting adjustments on ourConsolidated Balance Sheet and Consolidated Statement of Operations aspreviously reported in the original Quarterly Report on Form 10-Q as filedon May 9, 2005.  The aforementionedrestatement adjustments do not affect cash flows provided by operating activities,net cash used in investing activities and net cash provided by (used in)financing activities, although certain components of cash flows provided byoperating activities have been restated.

 

Consolidated Balance Sheet

 
| ** **                                                   | ** ** | **For the period ending** | ** ** |
|--------------------------------------------------------------|------------|---------------------------|------------|
| ** **                                                   | ** ** | **March 31, 2005**   | ** ** | **December 31, 2004** | ** ** |
| ** **                                                   | ** ** | **As**                    | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** |
| **(000s)**                                                   | ** ** | **Reported**              | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** |
| Assets:                                                      |       |                      |       |   |   |   |   |   |   |
| Current assets from price risk management  activities        |       | 20,859                    |       | 2,837 |   | 22,238 |   | 19,893 |   |
| Deferred income taxes                                        |       | —                    |       | 9,432 |   | — |   | — |   |
| Long-term assets from price risk management  activities      |       | 536                       |       | 424 |   | 618 |   | 249 |   |
| Total Assets                                                 |       | $                         | 1,875,677  |   | $ | 1,866,975 |   | $ | 1,840,112 |   | $ | 1,837,398 |   |
|                                                         |       |                      |       |   |   |   |   |   |   |
| Liabilities and Stockholders’ equity                    |       |                      |       |   |   |   |   |   |   |
| Current liabilities from price risk management  activities   |       | 31,206                    |       | 28,979 |   | 11,099 |   | 4,321 |   |
| Deferred income taxes                                        |       | —                    |       | — |   | — |   | 5,618 |   |
| Long-term liabilities from price risk  management activities |       | 310                       |       | 309 |   | 417 |   | 180 |   |
| Deferred income taxes payable, net                           |       | 251,737                   |       | 255,444 |   | 247,893 |   | 243,835 |   |
| Total liabilities                                            |       | 1,171,952                 |       | 1,173,431 |   | 1,158,084 |   | 1,152,629 |   |
|                                                         |       |                      |       |   |   |   |   |   |   |
| Stockholders’ equity                                    |       |                      |       |   |   |   |   |   |   |
| Retained earnings                                            |       | 307,605                   |       | 297,424 |   | 278,687 |   | 281,428 |   |
| Total stockholders’ equity                              |       | 703,725                   |       | 693,544 |   | 682,028 |   | 684,769 |   |
| Total liabilities and stockholders’ equity              |       | $                         | 1,875,677  |   | $ | 1,866,975 |   | $ | 1,840,112 |   | $ | 1,837,398 |   |

 

Consolidated Statement of Operations

 
| ** **                                                                                     | ** ** | **Quarter Ended**       | ** ** |
|------------------------------------------------------------------------------------------------|------------|-------------------------|------------|
| ** **                                                                                     | ** ** | **March 31, 2005** | ** ** | **March 31, 2004** | ** ** |
| ** **                                                                                     | ** ** | **As**                  | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** |
| **(000s)**                                                                                     | ** ** | **Reported**            | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** |
| Revenues:                                                                                      |       |                    |       |   |   |   |   |   |   |
| Price risk management activities                                                               |       | (40                     | )          | (20,248 | ) | (5,480 | ) | 3,096 |   |
| Total revenues                                                                                 |       | $                       | 854,315    |   | $ | 834,107 |   | $ | 771,216 |   | $ | 779,680 |   |
|                                                                                           |       |                    |       |   |   |   |   |   |   |
| Income before income taxes                                                                     |       | 51,342                  |       | 31,134 |   | 38,382 |   | 46,846 |   |
| Provision for income taxes:                                                                    |       |                    |       |   |   |   |   |   |   |
| Deferred                                                                                       |       | 11,364                  |       | 4,078 |   | 10,465 |   | 13,583 |   |
| Total provision for income taxes                                                               |       | 18,714                  |       | 11,428 |   | 14,008 |   | 17,126 |   |
| Income before cumulative effect of change  in accounting principle                             |       | 32,628                  |       | 19,706 |   | 24,374 |   | 29,720 |   |
| Net income                                                                                     |       | 32,628                  |       | 19,706 |   | 29,088 |   | 34,434 |   |
| Income attributable to common stock                                                            |       | 32,628                  |       | 19,706 |   | 28,272 |   | 33,618 |   |
| Earnings per share of common stock before  cumulative effect of change in accounting principle |       | 0.44                    |       | 0.27 |   | 0.34 |   | 0.42 |   |
| Earnings per share of common stock                                                             |       | 0.44                    |       | 0.27 |   | 0.41 |   | 0.49 |   |
| Income attributable to common stock -  assuming dilution                                       |       | 32,628                  |       | 19,706 |   | 29,088 |   | 34,434 |   |
| Earnings per share of common stock -  assuming dilution                                        |       | $                       | 0.43       |   | $ | 0.26 |   | $ | 0.39 |   | $ | 0.47 |   |

 

9

----

 

Thenet impact of this restatement was to adjust Net income by ($12.9) million and$5.3 million for the three months ended March 31, 2005 and 2004,respectively.  The net impact of thisrestatement was to adjust Earnings per share of common stock — assumingdilution by ($0.17) and $0.08 for the three months ended March 31, 2005and 2004, respectively.

 

##### ***EQUITY TRANSACTIONS***

##### *** ***

***Conversion of Preferred Stock.*** InDecember 2003, we issued a notice of redemption for a total of 800,000 sharesof our $2.625 cumulative convertible preferred stock.  The holders of these shares had the right toconvert them into shares of our common stock in lieu of receiving theredemption price in cash.   InJanuary 2004, we issued an additional 1,979,244 shares of common stock toholders who elected to convert their shares and paid $672,000 in cash proceedsto 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 to holders who elected to convert their sharesand paid $391,000 in cash proceeds to complete this redemption.  After these redemptions, the $2.625 cumulativeconvertible preferred stock was delisted from trading on the New York StockExchange and was deregistered by the SEC.

 

***EARNINGS PER SHARE OF COMMON STOCK***

 

Earningsper share of common stock are computed by dividing income attributable tocommon stock by the weighted average shares of common stock outstanding.  In addition, earnings per share of commonstock - assuming dilution is computed by dividing income attributable to commonstock by the weighted average shares of common stock outstanding as adjustedfor potential common shares.  Incomeattributable to common stock is net income less preferred stock dividends.   The following table presents the dividendsdeclared by us for each class of our outstanding equity securities (dollars inthousands, except per share amounts):

 

| ** **                     | ** ** | **Quarter Ended March 31,** | ** ** |
|--------------------------------|------------|----------------------------------|------------|
| ** **                     | ** ** | **2005**                         | ** ** | **2004** | ** ** |
| Common Stock                   |       | $                                | 3,710      |   | $ | 1,765 |   |
| Preferred  Stock               |       | —                           |       | 789 |   |
| Total  Dividends Declared      |       | $                                | 3,710      |   | $ | 2,554 |   |
|                           |       |                             |       |   |   |
| Dividends  Declared Per Share: |       |                             |       |   |   |
| Common Stock                   |       | $                                | 0.05       |   | $ | 0.03 |   |
| Preferred  Stock               |       | $                                | —     |   | $ | 0.66 |   |

 

Commonstock options and, until the final conversion or redemption in April 2004,our $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.

 
| ** **                                                               | ** ** | **Quarter Ended March 31,** | ** ** |
|--------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                               | ** ** | **2005**                         | ** ** | **2004** | ** ** |
| Weighted  average shares of common stock outstanding                     |       | 74,148,269                       |       | 68,365,900 |   |
| Potential  common shares from:                                           |       |                             |       |   |   |
| Common stock options                                                     |       | 1,411,049                        |       | 1,815,528 |   |
| $2.625 Cumulative Convertible Preferred  Stock                           |       | —                           |       | 3,470,182 |   |
| Weighted  average shares of common stock outstanding - assuming dilution |       | 75,559,318                       |       | 73,651,610 |   |

 

Thecalculation of fully diluted earnings per share reflects potential commonshares and any related preferred dividends.

 

10

----

 

***ACCUMULATED OTHER COMPREHENSIVE INCOME***

 

Includedin Accumulated other comprehensive income at March 31, 2005 were unrealizedlosses of $7.2 million from the fair value of derivatives designated as cashflow hedges and unrealized losses of $2.3 million of cumulative foreigncurrency translation adjustments.

 

Includedin Accumulated other comprehensive income at March 31, 2004 wereunrealized losses of $2.9 million from the fair value of derivatives designatedas cash flow hedges and unrealized gains of $1.4 million of cumulative foreigncurrency translation adjustments.

 

##### ***REVENUE RECOGNITION***

##### *** ***

 In the Gas Gathering, Processing and Treatingsegment, we recognize revenue for our services at the time the service isperformed. We record revenue from our gas and NGL marketing activities,including sales of our equity production, upon transfer of title.  In accordance with EITF 03-11, we recordrevenue on our physical gas and NGL marketing activities on a gross basisversus sales net of purchases basis because we obtain title to all the gas andNGLs that we buy including third-party purchases, bear the risk of loss andcredit exposure on these transactions, and it is our intention upon enteringthese contracts to take physical delivery of the product.  Gas imbalances on our production areaccounted for using the sales method. Gas imbalances on our production at March 31, 2005 and 2004 areimmaterial.  For our marketingactivities, we utilize mark-to-market accounting for our derivatives.  In the Transportation segment, we realizerevenue on a monthly basis from firm capacity contracts under which the shipperpays for transport capacity whether or not the capacity is used and frominterruptible contracts where a fee is charged based upon volumes deliveredfrom the pipeline.

 

***CUMULATIVE EFFECT OF CHANGES IN ACCOUNTINGPRINCIPLES***

 

***Depreciation, Depletion and Amortization forOil and Gas Properties.***  We follow the successful efforts method ofaccounting for oil and gas exploration and production activities.  Effective January 1, 2004, we redefined theasset groupings for the calculation of depreciation and depletion on our oiland gas properties from a well-by-well basis to a field wide basis for each ofthe Jonah, Pinedale and Sand Wash fields and to a grouping of all wells drilledinto related coal seams for the Powder River Basin.  The cumulative effect of the change indepreciation and depletion methodology for the quarter ended March 31, 2004 wasa benefit of $4.7 million, net of tax, or $0.07 per share of common stock -assuming dilution, and is presented in the Consolidated Statement of Operationsunder the caption Cumulative effect of change in accounting principle, net oftax.

 

***DERIVATIVE INSTRUMENTS AND HEDGINGACTIVITIES***

 

Thenet gain recognized in earnings through Sale of residue gas and Sale of naturalgas liquids during the first three months of 2005 from hedging activities was$487,000.  Also during this period werecognized a loss from hedge ineffectiveness of $87,000 through Price riskmanagement activities.

 

Thegains and losses currently reflected in Accumulated other comprehensive incomewill be reclassified to earnings as the hedged gas or NGLs is sold.  Based on the prices for our products onMarch 31, 2005, approximately $7.2 million of losses in Accumulated othercomprehensive income is anticipated to be reclassified to earnings in 2005.

 

***SUPPLEMENTARY CASH FLOW INFORMATION***

 

Interestpaid was $6.1 million and $3.0 million for the three months endedMarch 31, 2005 and 2004, respectively. No income taxes were paid in the three months ended March 31, 2005and 2004.

 

***STOCK COMPENSATION***

 

Aspermitted under SFAS No. 123, “Accounting for Stock-Based Compensation,”we have 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.”  We have complied with the pro formadisclosure requirements of SFAS No. 123 as required under thepronouncement.  We realize an income taxbenefit from the exercise of non-qualified stock options related to the amountby which the market price at the date of exercise exceeds the optionprice.  This tax benefit is credited toadditional paid-in capital.

 

11

----

 

Weare required to record compensation expense (if not previously accrued) equalto the number of unexercised re-priced options multiplied by the amount bywhich our stock price at the end of any quarter exceeds $10.50 per share.  We had options covering 27,000 and 48,438common shares outstanding at March 31, 2005 and 2004, respectively, whichwere treated as repriced options.  Basedon our stock price at March 31, 2005 of $34.45 per share and our stockprice at March 31, 2004 of $25.42 per share, expense of $140,000 and$181,000, respectively, was recorded in the three months ended March 31,2005 and 2004.

 

SFASNo. 123 requires pro forma disclosures for each period that a statement ofoperations is presented.  The followingis a summary of the options to purchase our common stock granted and theweighted average fair value per share of the options granted during thequarters ended March 31, 2005 and 2004, respectively.

 
| ** **                             | ** ** | **Quarter Ended March 31,** | ** ** |
|----------------------------------------|------------|----------------------------------|------------|
| **2002 Plan**                          | ** ** | **2005**                         | ** ** | **2004** | ** ** |
| Options  granted                       |       | 83,000                           |       | 35,000 |   |
| Weighted  average fair value per share |       | $                                | 15.65      |   | $ | 11.26 |   |
|                                        |            |                                  |            |  |  |  |  |

 

Duringthe quarter ended March 31, 2005, the values for the options granted wereestimated using the Black-Scholes option-pricing model with the followingassumptions:

 
| ** **                      | ** ** | **2002 Plan** | ** ** |
|---------------------------------|------------|---------------|------------|
| Risk-free  interest rate        |       | 4.38          | %          |
| Expected  life (in years)       |       | 7             |       |
| Expected  volatility            |       | 37            | %          |
| Expected  dividends (quarterly) |       | $             | 0.05       |   |
|                                 |            |               |            |  |

 

UnderSFAS No. 123, the fair market value of the options at the grant date isamortized over the appropriate vesting period for purposes of calculatingcompensation expense.  If we had recordedcompensation expense for our grants under our stock-based compensation plansconsistent with the fair value method under this pronouncement, our net income,income attributable to common stock, earnings per share of common stock andearnings per share of common stock - assuming dilution would approximate thepro forma amounts below (dollars in thousands, except per share amounts):

 
| ** **                                                                                                                                     | ** ** | **Quarter Ended March 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                                                     | ** ** | **2005**                         | ** ** | **2005** | ** ** | **2004** | ** ** | **2004** | ** ** |
| ** **                                                                                                                                     | ** ** | **As Reported Restated**         | ** ** | **Pro Forma Restated** | ** ** | **As Reported Restated** | ** ** | **Pro Forma Restated** | ** ** |
| Net income                                                                                                                                     |       | $                                | 19,706     |   | $ | 18,027 |   | $ | 34,434 |   | $ | 33,293 |   |
| Income attributable to common stock                                                                                                            |       | 19,706                           |       | 18,027 |   | 33,618 |   | 32,477 |   |
| Earnings per share of common stock                                                                                                             |       | 0.27                             |       | 0.24 |   | 0.49 |   | 0.48 |   |
| Earnings per share of common stock -  assuming dilution                                                                                        |       | 0.26                             |       | 0.24 |   | 0.47 |   | 0.45 |   |
| Stock-based employee compensation cost, net  of related tax effects, included in net income                                                    |       | 178                              |       | — |   | 115 |   | — |   |
| Stock-based employee compensation cost, net  of related tax effects, includable in net income if the fair value based  method had been applied |       | $                                | —     |   | $ | 1,857 |   | $ | — |   | $ | 1,256 |   |

 

***SEGMENT REPORTING***

 

Weoperate in four principal business segments, as follows:  Gas Gathering, Processing and Treating;Exploration and Production; Marketing; and Transportation.  Management separately monitors these segmentsfor performance against our internal forecast, and these segments areconsistent with our internal financial reporting package.  These segments have been identified basedupon the differing products and services, regulatory environment and theexpertise required for these operations.

 

***Gas Gathering, Processing andTreating.***  In this segment, collectively with theMarketing and Transportation segments referred to as the midstream operations,we connect producers’ wells (including those of our Exploration and Productionsegment) to our gathering systems for delivery to our processing or treatingplants, process the

 

12

----

 

natural gas to extract NGLs and treat thenatural gas in order to meet pipeline specifications.  In some areas, where no processing isrequired, we gather and compress producers’ gas and deliver it to pipelines forfurther delivery to market.  Except forvolumes taken in kind by our producers, the Marketing segment sells the residuegas and NGLs extracted at most of our facilities.

 

Substantiallyall gas flowing through our gathering, processing and treating facilities issupplied under three types of contracts providing for the purchase, treating orprocessing of natural gas for periods ranging from one month to twenty years orin some cases for the life of the oil and gas lease.  Approximately 70% of our plant facilities’gross margin, or revenues at the plant less product purchases, for the month ofMarch 2005 was under percentage-of-proceeds agreements in which we aretypically responsible for the marketing of the gas and NGLs.  Under these agreements, we pay producers aspecified percentage of the net proceeds received from the sale of the gas andthe NGLs.

 

Approximately19% of our plant facilities’ gross margin for the month of March 2005 wasunder contracts that are primarily fee-based from which we receive a set feefor each Mcf of gas gathered and/or processed. This type of contract providesus with a steady revenue stream that is not dependent on commodity prices,except to the extent that low prices may cause a producer to delay drilling.

 

Approximately11% of our plant facilities’ gross margin for the month of March 2005 wasunder contracts with “keepwhole” arrangements or wellhead purchase contracts.  Under these contracts, we retain the NGLsrecovered by the processing facility and keep the producers whole by returningto the producers at the tailgate of the plant an amount of residue gas equal ona Btu basis to the natural gas received at the plant inlet.  The “keepwhole” component of the contractspermits us to benefit when the value of the NGLs is greater as a liquid than asa portion of the residue gas stream. However, we are adversely affected when the value of the NGLs is loweras a liquid than as a portion of the residue gas stream.

 

***Exploration and Production.***  Theactivities of the Exploration and Production segment include the explorationand development of gas properties in the Rocky Mountain area and otherunconventional gas plays, including those where our gathering and/or processingfacilities are located.  The Marketingsegment sells the majority of the production from these properties and remitsto the Exploration and Production segment all of the proceeds from the sales ofits gas net of transportation charges.

 

***Marketing.***  OurMarketing segment buys and sells gas and NGLs in the United States and Canadafrom and to a variety of customers. Revenues in this segment are sensitive to changes in the market pricesof the underlying commodities.  Themarketing of products purchased from third parties typically results in lowsales margins relative to the sales price. We sell our products under agreements with varying terms and conditionsin order to match seasonal and other changes in demand.  Also included in this segment are ourCanadian marketing operations, which are conducted through our wholly ownedsubsidiary WGR Canada, Inc. and are immaterial for separate presentation.

 

***Transportation.***  TheTransportation segment reflects the operations of Western’s MIGC, Inc. andMGTC, Inc. pipelines.   The majorityof the revenue presented in this segment is derived from transportation ofresidue gas for our Marketing segment and other third parties.  The Transportation segment’s firm capacitycontracts range in duration from seven months to approximately five years.

 

***Segment Information.*** The following tables set forth our segmentinformation as of and for the three months ended March 31, 2005 and 2004(dollars in thousands).  Due to ourintegrated operations, the use of allocations in the determination of businesssegment information is necessary. Inter-segment revenues are valued at prices comparable to those ofunaffiliated customers.  Prior periodCorporate Plant operating and transportation expense of $935,000 in the interimsegment information has been reclassified to the Gas Gathering and Processingsegment to conform to the presentation used in 2005.

 

13

----

 

**Quarter Ended March 31, 2005:**

**Restated**

 
| ** **                                       | ** ** | **Gas  Gathering  and  Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Trans-portation** | ** ** | **Corporate** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|--------------------------------------------------|------------|-------------------------------------|------------|----------------------------------|------------|---------------|------------|---------------------|------------|---------------|------------|--------------------------|------------|-----------|------------|
| Revenues from  unaffiliated customers:           |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| Sale of gas                                      |       | $                                   | (227       | )                                | $          | 4,035         |       | $                   | 690,333    |          | $          | 745                      |       | $         | —     |   | $ | — |   | $ | 694,886 |   |
| Sale of natural  gas liquids                     |       | 49                                  |       | —                           |       | 133,766       |       | —              |       | —        |       | —                   |       | 133,815   |       |
| Equity hedges:                                   |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| Gas                                              |       | 107                                 |       | 1,226                            |       | —        |       | —              |       | —        |       | —                   |       | 1,333     |       |
| Liquids                                          |       | (846                                | )          | —                           |       | —        |       | —              |       | —        |       | —                   |       | (846      | )          |
| Gathering,  processing andtransportation revenue |       | 22,292                              |       | (162                             | )          | —        |       | 1,750               |       | —        |       | —                   |       | 23,880    |       |
| Total revenues  from unaffiliated customers      |       | 21,375                              |       | 5,099                            |       | 824,099       |       | 2,495               |       | —        |       | —                   |       | 853,068   |       |
| Inter-segment  revenues                          |       | 275,854                             |       | 69,268                           |       | 17,704        |       | 3,442               |       | 10            |       | (366,278                 | )          | —    |       |
| Price risk  management activities                |       | (87                                 | )          | —                           |       | (20,161       | )          | —              |       | —        |       | —                   |       | (20,248   | )          |
| Interest income                                  |       | —                              |       | 4                                |       | —        |       | —              |       | 9,502         |       | (9,506                   | )          | —    |       |
| Other, net                                       |       | 1,105                               |       | 2                                |       | —        |       | —              |       | 180           |       | —                   |       | 1,287     |       |
| Total revenues                                   |       | 298,247                             |       | 74,373                           |       | 821,642       |       | 5,937               |       | 9,692         |       | (375,784                 | )          | 834,107   |       |
|                                             |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| Product purchases                                |       | 221,453                             |       | 1,279                            |       | 840,044       |       | 858                 |       | —        |       | (356,280                 | )          | 707,354   |       |
| Plant and  transportation operating expense      |       | 26,639                              |       | 4                                |       | 1             |       | 1,812               |       | —        |       | (757                     | )          | 27,699    |       |
| Oil and gas  exploration and production expense  |       | —                              |       | 34,138                           |       | —        |       | —              |       | —        |       | (9,242                   | )          | 24,896    |       |
| (Earnings) from  equity investments              |       | (2,134                              | )          | —                           |       | —        |       | —              |       | —        |       | —                   |       | (2,134    | )          |
| Segment-operating  profit (loss)                 |       | 52,289                              |       | 38,952                           |       | (18,403       | )          | 3,267               |       | 9,692         |       | (9,505                   | )          | 76,292    |       |
|                                             |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| Depreciation,  depletion and amortization        |       | 11,279                              |       | 15,629                           |       | 35            |       | 403                 |       | 1,732         |       | —                   |       | 29,078    |       |
| Selling and  administrative expense              |       | —                              |       | —                           |       | —        |       | —              |       | 12,542        |       | (10                      | )          | 12,532    |       |
| (Gain) loss from  sale of assets                 |       | 31                                  |       | —                           |       | —        |       | (3                  | )          | —        |       | —                   |       | 28        |       |
| Interest expense                                 |       | 5                                   |       | 1                                |       | 2             |       | (154                | )          | 13,172        |       | (9,506                   | )          | 3,520     |       |
| Income before  income tax                        |       | $                                   | 40,974     |                             | $          | 23,322        |       | $                   | (18,440    | )             | $          | 3,021                    |       | $         | (17,754    | ) | $ | 11 |   | $ | 31,134 |   |
|                                             |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| Identifiable  assets:                            |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| Equity investment                                |       | $                                   | 36,108     |                             | —     |          | —     |                | $          | 1,071         |       | $                        | 757,071    |      | $          | (758,142 | ) | $ | 36,108 |   |
| Property and  equipment                          |       | 712,270                             |       | $                                | 503,184    |          | $          | 15                  |       | 35,862        |       | 53,516                   |       | —    |       | 1,304,847 |   |
| Other allocated  assets                          |       | 5,251                               |       | 19,210                           |       | 116,149       |       | 48,960              |       | 434,545       |       | (98,095                  | )          | 526,020   |       |
| Total  identifiable assets                       |       | $                                   | 753,629    |                             | $          | 522,394       |       | $                   | 116,164    |          | $          | 85,893                   |       | $         | 1,245,132  |   | $ | (856,237 | ) | $ | 1,866,975 |   |

 

**Quarter Ended March 31, 2004:**

**Restated**

 
| ** **                                        | ** ** | **Gas  Gathering  and  Processing** | ** ** | **Exploration  and  Production** | ** ** | **Marketing** | ** ** | **Trans-portation** | ** ** | **Corporate** | ** ** | **Eliminating  Entries** | ** ** | **Total** | ** ** |
|---------------------------------------------------|------------|-------------------------------------|------------|----------------------------------|------------|---------------|------------|---------------------|------------|---------------|------------|--------------------------|------------|-----------|------------|
| Revenues from  unaffiliated customers:            |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| Sale of gas                                       |       | $                                   | 924        |                             | $          | 2,239         |       | $                   | 659,936    |          | $          | 562                      |       | $         | —     |   | $ | — |   | $ | 663,663 |   |
| Sale of natural  gas liquids                      |       | 1                                   |       | —                           |       | 95,306        |       | —              |       | —        |       | —                   |       | 95,307    |       |
| Equity hedges:                                    |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| Gas                                               |       | 149                                 |       | 1,500                            |       | —        |       | —              |       | —        |       | —                   |       | 1,649     |       |
| Liquids                                           |       | (2,392                              | )          | —                           |       | —        |       | —              |       | —        |       | —                   |       | (2,392    | )          |
| Gathering,  processing and transportation revenue |       | 15,086                              |       | —                           |       | —        |       | 1,743               |       | —        |       | —                   |       | 16,829    |       |
| Total revenues  from unaffiliated customers       |       | 13,768                              |       | 3,739                            |       | 755,242       |       | 2,305               |       | —        |       | —                   |       | 775,054   |       |
| Inter-segment  revenues                           |       | 257,652                             |       | 55,931                           |       | 12,805        |       | 3,434               |       | —        |       | (329,822                 | )          | —    |       |
| Price risk  management activities                 |       | (21                                 | )          | —                           |       | 3,005         |       | —              |       | —        |       | —                   |       | 2,984     |       |
| Interest income                                   |       | —                              |       | —                           |       | —        |       | —              |       | 4,009         |       | (4,009                   | )          | —    |       |
| Other, net                                        |       | 341                                 |       | 1                                |       | (2            | )          | —              |       | 1,302         |       | —                   |       | 1,642     |       |
| Total revenues                                    |       | 271,740                             |       | 59,671                           |       | 771,050       |       | 5,739               |       | 5,311         |       | (333,831                 | )          | 779,680   |       |
|                                              |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| Product purchases                                 |       | 215,577                             |       | 628                              |       | 759,869       |       | 1,581               |       | —        |       | (320,313                 | )          | 657,342   |       |
| Plant and  transportation operating expense       |       | 21,099                              |       | 248                              |       | (242          | )          | 1,760               |       | —        |       | (931                     | )          | 21,934    |       |
| Oil and gas exploration  and production expense   |       | —                              |       | 25,681                           |       | —        |       | —              |       | —        |       | (8,571                   | )          | 17,110    |       |
| (Earnings) from  equity investments               |       | (1,926                              | )          | —                           |       | —        |       | —              |       | —        |       | —                   |       | (1,926    | )          |
| Segment-operating  profit                         |       | 36,990                              |       | 33,114                           |       | 11,423        |       | 2,398               |       | 5,311         |       | (4,016                   | )          | 85,220    |       |
|                                              |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| Depreciation,  depletion and amortization         |       | 9,001                               |       | 10,991                           |       | 17            |       | 416                 |       | 2,201         |       | —                   |       | 22,626    |       |
| Selling and  administrative expense               |       | —                              |       | —                           |       | —        |       | —              |       | 9,961         |       | (15                      | )          | 9,946     |       |
| (Gain) loss from  sale of assets                  |       | —                              |       | —                           |       | —        |       | —              |       | —        |       | —                   |       | —    |       |
| Interest expense                                  |       | —                              |       | 34                               |       | 95            |       | (62                 | )          | 9,744         |       | (4,009                   | )          | 5,802     |       |
| Income before  income tax                         |       | $                                   | 27,989     |                             | $          | 22,089        |       | $                   | 11,311     |          | $          | 2,044                    |       | $         | (16,595    | ) | $ | 8 |   | $ | 46,846 |   |
|                                              |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| Identifiable  assets:                             |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| Equity investment                                 |       | —                              |       | —                           |       | —        |       | —              |       | $             | 483,720    |                     | $          | (443,954  | )          | $ | 39,766 |   |
| Property and  equipment                           |       | $                                   | 623,219    |                             | $          | 304,721       |       | $                   | 17         |          | $          | 38,503                   |       | 54,346    |       | (569 | ) | 1,020,237 |   |
| Other allocated  assets                           |       | 5,974                               |       | 4,737                            |       | 58,474        |       | 27,152              |       | 319,475       |       | (52,120                  | )          | 363,692   |       |
| Total  identifiable assets                        |       | $                                   | 629,193    |                             | $          | 309,458       |       | $                   | 58,491     |          | $          | 65,655                   |       | $         | 857,541    |   | $ | (496,643 | ) | $ | 1,423,695 |   |

 

14

----

 

***LEGAL PROCEEDINGS***

 

***Gracey et al. v. Western GasResources, Inc. et al., United States District Court, Southern District ofNew York, CaseNo. 03-CV-6186 (vm) (S.D.N.Y.). ***On September 17, 2004, the plaintiffs,traders of natural gas futures contracts on NYMEX filed this action on behalfof themselves and a putative class of others similarly situated.  In the complaint, the plaintiffs claim thatthe Company manipulated the prices of natural gas futures on the NYMEX inviolation of the Commodity Exchange Act, or CEA, by reporting allegedly“inaccurate, misleading and false trading information” to trade publicationsthat compile and publish indices of natural gas spot prices.  In addition, the complaint asserts that theCompany aided and abetted the alleged CEA violations of others.  The plaintiffs seek to recover actual damageson behalf of themselves and a class of natural gas futures traders, and theircosts of litigation including attorney’s fees. The Company believes that the claims are without merit and intends tovigorously contest the allegations in this case.

 

***Other Litigation.**** * We are involved in various otherlitigation and administrative proceedings arising in the normal course ofbusiness.  In the opinion of ourmanagement, any liabilities that may result from these claims will not,individually or in the aggregate, have a material adverse effect on ourfinancial position, results of operations or cash flow.

 

***RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS***

 

Wecontinually monitor and revise our accounting policies as new rules areissued.  At this time, there are severalnew accounting pronouncements that have recently been issued, but not yetadopted, which will have an impact on our accounting when they become effectivein 2005.  The following pronouncementshave been issued but not yet adopted.

 

**SFAS No. 123(R).**  SFAS No. 123(R), “*Share Based Payment”*was issued inDecember 2004 and now must be adopted for annual periods that begin afterJune 15, 2005.  This pronouncementrequires companies to expense the fair value of employee stock options andother forms of stock based compensation. We intend to adopt this pronouncement in the first quarter of 2006.  Currently, we are complying with the proforma disclosure requirements of SFAS No. 123, *“Accounting for Stock Based Compensation.*”  If SFAS No. 123(R) had been in effectduring the first quarter of 2005, Earnings per share of common stock - assumingdilution in the first quarter ended March 31, 2005 would have been $0.22per share of common stock or a reduction of approximately $0.02 per share ofcommon stock from the actual results for the first quarter of 2005.

 

**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 theCompany for inventory costs incurred in fiscal years beginning afterJune 15, 2005, and will be applied prospectively.  SFAS No. 151 amends APB OpinionNo. 43, Chapter 4, “Inventory Pricing” to clarify the accounting forabnormal amounts of costs and the allocation of fixed productionoverheads.  We believe that the adoptionof SFAS No. 151 will not affect our results of operations, financialposition 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 the Company for nonmonetary asset exchanges occurring in fiscal

 

15

----

 

periods beginning after June 15, 2005,and will be applied prospectively.  SFASNo. 153 amends APB Opinion No. 29, “*Accountingfor Nonmonetary Transactions”*. The guidance in APB Opinion No. 29 is based on the principle thatexchanges of nonmonetary assets should be measured based on the fair value ofthe assets exchanged but included certain exceptions to that principle.  SFAS No. 153 amends APB OpinionNo. 29 to eliminate the exception for nonmonetary exchanges of similarproductive assets and replaces it with a general exception for exchanges ofnonmonetary assets that do not have commercial substance.  A nonmonetary exchange has commercialsubstance if the future cash flows of the entity are expected to change significantlyas a result of the exchange.  We willadopt SFAS No. 153 as required.

 

**EITF No. 04-13.  **At itsNovember 2004 meeting, the Emerging Issues Task Force, or EITF, of theFASB began discussion of Issue No. 04-13, “*Accounting for Purchases and Sales of Inventory with the SameCounterparty*.”  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 material impact onour results of operations, financial position or cash flows.

 

Inorder to minimize transportation costs or make product available at a locationof our customer’s preference, from time to time, we will enter into arrangementsto buy product from a party at one location and arrange to sell a like quantityof product to this same party at another location.  In accordance with EITF 03-11, we recordrevenue on these transactions on a gross basis versus sales net of purchasesbasis because we obtain title to the product that we buy, bear the risk ofloss, credit and performance exposure on these transactions, and take physicaldelivery of the product.  For thequarters ended March 31, 2005 and 2004, we recorded revenues of $28.7million and $25.2 million, respectively, and product purchases of $26.7 millionand $23.9 million, respectively, for transactions which were entered intoconcurrently and with the intent to buy and sell like quantities with the samecounterparty at different locations and at market prices at those locations.

 

**FSP FAS 19-1.**  In April 2005, the FASBStaff issued FASB Staff Position, or FSP, FAS 19-1, “Accounting forSuspended Well Costs.” This FSP amends SFAS 19, “Financial Accounting andReporting by Oil and Gas Producing Companies,” as it pertains to capitalizingthe costs of drilling exploratory wells pending determination of whether thewell has found proved reserves.  FSP FAS19-1 states that exploratory well costs should continued to be capitalized ifthe well has found a sufficient quantity of reserves to justify its completionas a producing well and the entity is making progress assessing reserves andthe economic and operational viability of the project.  This FSP is effective in the second quarterof 2005.  We do not believe that this FSPwill have a material impact on our results of operations, financial position orcash flows.

 

**FASB Interpretation No. 47. **FASB Interpretation No. 47, “Accounting for Conditional AssetRetirement Obligations, an interpretation of FASB Statement No. 143”, orFIN 47, was issued in March 2005 and is effective in fiscal periodsbeginning after December 31, 2005. FIN 47 clarifies the term “conditional asset retirement obligation” asused in FASB Statement 143, “Accounting for Asset Retirement Obligations”.  Conditional asset retirement obligations asused in FASB Statement 143 refers to a legal obligation to perform an assetretirement activity in which the timing and (or) method of settlement areconditional on a future event that may or may not be within the control of theentity. The obligation to perform an asset retirement activity is unconditionaleven though uncertainty exists about the timing and (or) method of settlement.Accordingly, an entity is required to recognize a liability for the fair valueof a conditional asset retirement obligation if the fair value of the liabilitycan be reasonably estimated. When sufficient information exists, uncertaintyabout the timing and (or) method of settlement should be factored into themeasurement of the liability. This interpretation is not expected to have amaterial impact on our results of operation, financial position or cash flows.

 

16

----

 

**ITEM 2.    MANAGEMENT’S DISCUSSION ANDANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

 

Thefollowing discussion and analysis relates to factors that have affected ourconsolidated financial condition and results of operations for the three monthsended March 31, 2005 and 2004. Certain prior year amounts have been reclassified to conform to thepresentation used in 2005.  You shouldalso refer to our interim consolidated financial statements and notes theretoincluded elsewhere in this document. This section, as well as other sections in this Form 10-Q/A,contain “forward-looking statements” within the meaning of the PrivateSecurities Litigation Reform Act of 1995, which can be identified by the use offorward-looking terminology, such as “may,” “intend,” “will,” “expect,” “anticipate,”“estimate,” or “continue” or the negative thereof or other variations thereonor comparable terminology.  In additionto the important factors referred to herein, numerous factors affecting the gasprocessing industry generally and in the specific markets for gas and NGLs inwhich we operate could cause actual results to differ materially from those insuch forward-looking statements.

 

***Restatement of Previously IssuedFinancial Statements***

 

Uponadoption of FAS 133 in 2001, we analyzed our gas storage and gas transportationcontracts in detail, and determined that these contracts had thecharacteristics of a derivative under generally accepted accounting principles.On November 21, 2005, we announced that our management and our audit committeehave completed a review of the accounting treatment of our gas storage and gastransportation contracts and determined that these contracts do not meet thedefinition of a derivative. Specifically, after a detailed review of the contracts and the market forthose contracts, we subsequently determined that these contracts do not meetthe definition of a derivative as: (i) the market for these types ofcontracts is not sufficiently liquid for us to receive fair value in a readymarket and (ii) if any contract is assigned, there is no assurance that wewill be relieved of our rights and obligations under that contract.

 

Historically,the non-cash mark-to-market valuation of the gas storage and transportationcontracts which, prior to the restatement were considered to be derivatives,effectively offset non-cash mark-to-market changes to the forward derivativecontracts to sell our stored or transported natural gas.  After the adjustments to correct the prioraccounting for these contracts as derivatives, the non-cash mark-to-market ofthe forward derivative contract on the sale of gas will fluctuate throughearnings with changes in market prices and will not be offset by acorresponding mark to market on the gas storage and transportation contracts.  As the stored or transported natural gas issold and the forward sale derivatives are settled, we will realize the benefitof the storage and transportation transactions through earnings.

 

The effect of the restatement for each of thequarters ended March 31, 2005 and 2004 is as follows (amounts inthousands, except per share amounts). For additional information on the nature and impact of these accountingcorrections provided in Note 2, “Restatement of Consolidated FinancialStatements,” please refer to our Consolidated Financial Statements includedelsewhere in this Form 10-Q/A.:

 
| ** **                            | ** ** | **Quarter ended March 31,** | ** ** |
|---------------------------------------|------------|----------------------------------|------------|
| ** **                            | ** ** | **2005**                         | ** ** | **2004** | ** ** |
| ** **                            | ** ** | **As**                           | ** ** | **As** | ** ** | **As** | ** ** | **As** | ** ** |
| ** **                            | ** ** | **Reported**                     | ** ** | **Restated** | ** ** | **Reported** | ** ** | **Restated** | ** ** |
| Total  revenues                       |       | $                                | 854,315    |   | $ | 834,107 |   | $ | 771,216 |   | $ | 779,680 |   |
| Income  before taxes                  |       | 51,342                           |       | 31,134 |   | 38,382 |   | 46,846 |   |
| Net income                            |       | 32,628                           |       | 19,706 |   | 29,088 |   | 34,434 |   |
| Earnings per  share-assuming dilution |       | 0.43                             |       | 0.26 |   | 0.39 |   | 0.47 |   |
| Cash flow  from operating activities  |       | $                                | 117,396    |   | $ | 117,396 |   | $ | 124,496 |   | $ | 124,496 |   |

 

***Company Overview***

 

***Business Strategy. *** Maximizing the value of ourexisting core assets 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.

 

17

----

 

***Industry and Company Overview.  ***In North America, our industry hasexperienced several consecutive years of declining natural gas productiondespite increased drilling activity. Most of the major gas producing areas, such as the Gulf of Mexico, aremature and are in production decline.  Weare concentrating our efforts in the Rocky Mountain area and otherunconventional gas plays, where there are estimated to be large quantities ofundeveloped gas.  In the U.S, the federalgovernment largely retains the mineral rights to these undeveloped reserves;accordingly, the development and production of these reserves require permitsfrom several governmental agencies including the Bureau of Land Management, orBLM.  We are well positioned for futureproduction growth with a large inventory of undeveloped drilling locations inthe Powder River, the Greater Green River and San Juan Basins to meet thegrowing demand for clean burning natural gas. In addition, our experience and technical expertise position us toacquire new opportunities to develop natural gas in the Rocky Mountainregion.  Our challenges will be toaccomplish these goals with the difficulties encountered by the industry inobtaining the necessary permits from the BLM, and state agencies such as theWyoming Department of Environmental Quality, or DEQ.  We believe that our technical expertise indeveloping environmentally responsible solutions to the problems encountered inthe development of gas reserves will be a competitive advantage in overcomingthese challenges.  Additionally, to datewe have been successful in obtaining drilling rigs and related oil fieldservices to accomplish our drilling plans. However, we believe that as we expand into new areas and continue thedevelopment of the areas in which we currently participate, obtaining rigs,related services and experienced employees will become increasingly difficult.

 

Ouroperations are conducted through the following four business segments:

 

***Exploration and Production. ***We explore for, develop and produce natural gas reserves independentlyand to enhance and support our existing gathering and processing operations.Our producing properties are primarily located in the Powder River, GreaterGreen River, San Juan, and Sand Wash Basins. These plays provide low geologic risk, and are multi-year developmentprojects.  These provide us with theopportunity to steadily increase our production volume over time at reasonableoperating and low finding and development costs.  In the first quarter of 2005 our averageproduction sold was 164 MMcfe per day, which is a 13% increase over the dailyaverage production volume sold in the first quarter of 2004.

 

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, coal bed methane, biogenic, and shalegas plays to evaluate acquisitions of either additional leaseholds, proven andundeveloped reserves or companies with operations primarily focused in theRockies.  We may also evaluateunconventional gas reservoirs in areas outside the Rockies where we canleverage our related exploration, production and gathering expertise.  In January 2005, we opened an office inCalgary, Alberta, Canada to evaluate opportunities in the Western CanadianSedimentary Basin.  Overall, atMarch 31, 2005, we have acquired the drilling rights on approximately 1.6million net acres in various Rocky Mountain basins and continue to expand ourleasehold positions.

 

***Gathering, Processing andTreating. ***Our core operations are in well-establishedareas such as the Permian, Anadarko, Powder River, Greater Green River, and SanJuan Basins.  We connect natural gas fromgas and oil wells to our gathering systems for delivery to our processing ortreating plants under contracts with terms ranging from one month to life oflease. At our plants we process natural gas to extract NGLs and treat naturalgas in order to meet pipeline specifications. We provide these services to major oil and gas companies, to independentproducers of various sizes and for our own production.  We believe that our low cost of operations,our high on-line time and our safety records are key elements in our ability tocompete effectively and provide reliable service to our customers.  Our expertise in gathering, processing andtreating operations can enhance the economics of developing new upstreamprojects.

 

Thissegment of our operations has provided a stream of operating profit that isavailable for reinvestment into other projects or other segments of ourbusiness.  Overall throughput in ourfacilities during the first quarter of 2005 remained relatively constant ascompared to the same period in 2004 and averaged a total of 1.4 Bcf per day.

 

***Transportation. *** In the Powder River Basin, weown one interstate pipeline, MIGC, Inc., and one intrastate pipeline,MGTC, Inc., which transport natural gas for producers and energy marketersunder fee schedules regulated by state or federal agencies.

 

***Marketing. ***The primary goal of our gas-marketing segment is to ensure that theproduct from our processing facilities and upstream activities is deliveredtimely to the market.  Additionally, ourgas marketing operations seek

 

18

----

 

to preserve and enhance the value receivedfor 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 firm transportationcapacity on interstate pipelines and our gas storage positions, combined withthe stable supply of gas from our facilities and production, enable us torespond quickly to changing market conditions and to take advantage of seasonalprice variations and peak demand periods.

 

***RESULTS OF OPERATIONS***

 

**Three months ended March 31, 2005 compared to the threemonths ended March 31, 2004**

**(Dollars in thousands, except per share amounts and operatingdata).**

 
| ** **                                            | ** ** | **Three Months Ended  March 31,** | ** ** | ** **   | ** ** |
|-------------------------------------------------------|------------|----------------------------------------|------------|--------------|------------|
| ** **                                            | ** ** | **2005**                               | ** ** | **2004**     | ** ** | **Percent** | ** ** |
| ** **                                            | ** ** | **Restated**                           | ** ** | **Restated** | ** ** | **Change** | ** ** |
|                                                  |       |                                   |       |         |       |   |   |
| **Financial  results:**                               |       |                                   |       |         |       |   |   |
| Revenues                                              |       | $                                      | 834,107    |         | $          | 779,680 |   | 7 |   |
| Net income                                            |       | 19,706                                 |       | 34,434       |       | (43 | ) |
| Earnings per  share of common stock                   |       | 0.27                                   |       | 0.49         |       | (45 | ) |
| Earnings per  share of common stock-assuming dilution |       | 0.26                                   |       | 0.47         |       | (45 | ) |
| Net cash  provided by operating activities            |       | 117,396                                |       | 124,496      |       | (6 | ) |
| Net cash  used in investing activities                |       | (114,241                               | )          | (35,126      | )          | 225 |   |
| Net cash  used in financing activities                |       | $                                      | (1,820     | )            | $          | (83,719 | ) | (97 | ) |
|                                                  |       |                                   |       |         |       |   |   |
| **Operating  data:**                                  |       |                                   |       |         |       |   |   |
| Average gas  sales (MMcf/D)                           |       | 1,302                                  |       | 1,367        |       | (5 | ) |
| Average NGL  sales (MGal/D)                           |       | 1,763                                  |       | 1,611        |       | 9 |   |
| Average gas  prices ($/Mcf)                           |       | $                                      | 5.91       |         | $          | 5.32 |   | 11 |   |
| Average NGL  prices ($/Gal)                           |       | $                                      | 0.84       |         | $          | 0.63 |   | 33 |   |

 

Netincome decreased $14.7 million for the three months ended March 31, 2005compared to the same period in 2004.  Inthis quarter, we had higher production of equity gas volumes and higher productprices as compared to the first quarter of 2004.  More than offsetting the benefit of the higherproduction and prices, was a decrease in the non-cash mark-to-market valuationof our gas storage and gas transportation contracts and an increase inoperating costs and depreciation, depletion and amortization in the firstquarter of 2005 and the cumulative effect of a change in accounting principlein the first quarter of 2004.  Effectiveas of January 1, 2004, we revised our depreciation and depletionmethodology for our oil and gas properties. This change in accounting principle resulted in a cumulative reductionof depreciation for periods prior to 2004 of $4.7 million, net of tax, in thequarter ended March 31, 2004.

 

Revenuesfrom the sale of gas increased $31.0 million to $696.2 million for the threemonths ended March 31, 2005 compared to the same period in 2004.  This increase was primarily due to anincrease in product prices in the three months ended March 31, 2005.  Average gas prices realized by us increased$0.59 per Mcf to $5.91 per Mcf for the quarter ended March 31, 2005compared to the same period in 2004. Included in the realized gas price were approximately $1.3 million ofgains recognized in the three months ended March 31, 2005 related tofutures positions on equity gas volumes. We have entered into additional futures positions for approximately 61%of our equity gas for the remainder of 2005. See further discussion in “Item 3. Quantitative and QualitativeDisclosures About Market Risk”.  Averagegas sales volumes decreased by 5% to 1,302 MMcf per day for the quarter endedMarch 31, 2005 compared to the same period in 2004.

 

Revenuesfrom the sale of NGLs increased $40.1 million to $133.0 million for the threemonths ended March 31, 2005 compared to the same period in 2004.  This increase is primarily due to an increasein product prices.  Average NGL pricesrealized by us increased $0.21 per gallon to $0.84 per gallon for the threemonths ended March 31, 2005 compared to the same period in 2004.  Included in the realized NGL price wereapproximately $846,000 of losses recognized in the three months ended March 31,2005 related to futures positions on equity NGL volumes.  We have entered into additional futurespositions for approximately 32% of our equity NGL production for the remainderof 2005.  See further discussion in “Item3. Quantitative and Qualitative Disclosures About Market Risk”.  Average NGL sales volumes increased 9% to1,763 MGal per day for the three months ended March 31, 2005 compared tothe same period in 2004.  This increasein sales volume was primarily due to the acquisition of various gathering andprocessing assets in the first quarter of 2005.

 

19

----

 

Theeffect of Price risk management activities changed from $2.9 million for thequarter ended March 31, 2004 to ($20.2) million for the quarter endingMarch 31, 2005.  This change was dueto the non-cash mark-to-market adjustments of our risk managementactivities.  This account is primarilyimpacted by changes in the forward price of natural gas in the 2005 quarter ascompared to 2004 quarter and the impact of those price changes on the fair valueof the forward sale derivatives for our gas in storage.

 

Productpurchases increased by $50.0 million for the quarter ended March 31, 2005compared to the same period in 2004 as a result of the increase in productprices.  Overall, combined product purchasesas a percentage of sales of all products decreased slightly to 86% in the firstquarter of 2005 as compared to the first quarter of 2004.  This decrease is due to the reduction inthird party sales volumes of natural gas.

 

Plantand transportation operating expense increased by $5.8 million for the quarterended March 31, 2005 compared to the same period in 2004.  The increase was primarily due to increasesin property tax expenses, labor costs, repairs and maintenance, and third partygathering expenses.

 

Oiland gas exploration and production expenses increased by $7.8 million for thequarter ended March 31, 2005 compared to the same period in 2004.  The increase was substantially due toincreased lease operating expenses, or LOE, in the Powder River Basin coal beddevelopment, the newly acquired production assets in the San Juan Basin, andunsuccessful well expense of $1.7 million primarily related to an exploratorywell in the Sand Wash area. Overall, LOE averaged $0.87 per Mcf in the 2005period compared to $0.64 per Mcf in 2004. The increase in LOE is substantially due to higher water handlingcharges on dewatering wells in several new pilot areas that have no offsettinggas production as yet, contract labor, and fuel and operating costs of wellheadblowers in the Powder River Basin as well as increased costs related toinitiating operations of the San Juan Basin production assets.

 

Depreciation,depletion and amortization, or DD&A, increased by $6.5 million in thequarter ended March 31, 2005 compared to the same period in 2004.   In total, we had a $2.3 million increase inDD&A in our midstream operations primarily due to our expanding CBMgathering system in the Powder River Basin and the February 2005acquisition of additional midstream assets in the Greater Green RiverBasin.  We also had $4.6 million increasein DD&A in our upstream operations primarily due to our continueddevelopment in the Powder River Basin, downward revisions to reserves in the PowderRiver Basin, and our October 2004 acquisition of producing properties inthe San Juan Basin.

 

Sellingand administrative expenses increased by $2.6 million in the quarter endedMarch 31, 2005 compared to the same period in 2004.  This increase is due to higher compensationand benefit costs, audit fees and legal fees.

 

***Cash Flow Information***

 

Cashflows from operating activities decreased by $7.1 million in the first quarterof 2005 compared to the first quarter of 2004. This decrease was primarily dueto the timing of cash receipts and payables.

 

Cashflows used in investing activities increased by $79.1 million in the firstquarter of 2005 compared to the first quarter of 2004.  This increase was primarily due to anincreased level of capital expenditures including the February 2005acquisition of additional midstream assets in the Greater Green River Basin.

 

Cashflows used in financing activities decreased by $81.9 million in the firstquarter of 2005 compared to the first quarter of 2004.  This decrease was due to a significantreduction in our outstanding debt in the first quarter of 2004, as compared tothe utilization of funds provided by financing activities to fund our capitalinvestments in 2005.

 

***Segment Information***

 

***Gas Gathering, Processing andTreating.***  The Gas Gathering, Processing and Treatingsegment realized segment-operating profit of $52.3 million for the three monthsended March 31, 2005 compared to $37.0 million in the same period in2004.  The increase in operating profitin this segment in 2004 is primarily due to higher realized prices and theresulting increase in net margin as shown below.  

 

20

----

 

| ** **                                                  | ** ** | **Quarter Ended March 31,** | ** ** |
|-------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                  | ** ** | **2005**                         | ** ** | **2004** | ** ** |
| Gross Margin  ($/Mcf)(1)                                    |       | $                                | 0.64       |   | $ | 0.49 |   |
| Segment  Plant operating and transportation expense ($/Mcf) |       | 0.22                             |       | 0.18 |   |
| Net Margin  ($/Mcf)                                         |       | $                                | 0.42       |   | $ | 0.31 |   |
| Average gas  volumes gathered (MMcf/D)                      |       |                             | 1,356      |   |   | 1,312 |   |

 

----

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

 

***Exploration and Production.***  TheExploration and Production segment realized segment-operating profit of $39.0million in the first quarter of 2005 compared to $33.1 million in 2004. Theincrease is due to increased equity production, higher product prices, and theacquisition of production assets in the San Juan basin in the fourth quarter of2004.   During the first quarter of 2005,our production of natural gas as compared to the same period in 2004 increasedby 9% to 14.3 Bcfe.  The following tablesets forth the average sales price received for our oil and gas products in thethree months ended March 31, 2005 and 2004.

 

| ** **                                              | ** ** | **Three Months Ended March 31,** | ** ** |
|---------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                              | ** ** | **2005**                              | ** ** | **2004** | ** ** |
| Average  sales price: (1)                               |       |                                  |       |   |   |
| Oil ($/Bbl)                                             |       | $                                     | 43.83      |   | $ | 35.43 |   |
| Gas ($/Mcf),  excluding the effect of hedging positions |       | 4.89                                  |       | 4.39 |   |
| Gas ($/Mcf),  including the effect of hedging positions |       | 4.97                                  |       | 4.51 |   |
|                                                    |       |                                  |       |   |   |
| Production  and other costs:                            |       |                                  |       |   |   |
| Lease  operating expense ($/Mcfe)                       |       | 0.87                                  |       | 0.64 |   |
| Production  tax expense ($/Mcfe)                        |       | 0.47                                  |       | 0.51 |   |
| Gathering  and transportation expense ($/Mcfe)(2)       |       | 0.83                                  |       | 0.71 |   |
| Other  expenses ($/Mcfe)                                |       | 0.01                                  |       | 0.01 |   |
| Total costs ($/Mcfe)                                    |       | $                                     | 2.18       |   | $ | 1.87 |   |

 

----

(1)                                  The prices received for NGLs are included inthe price received for gas.

(2)                                  Of the total Gathering and transportationexpense, approximately $0.63 per Mcfe and $0.66 per Mcfe in the quarters endedMarch 31, 2005 and 2004, respectively, was the result of inter-segmentcharges.

 

***Marketing.***  TheMarketing segment realized a segment-operating loss of ($18.4) million for thethree months ended March 31, 2005 compared to segment-operating profit of$11.4 million in the same period of 2004.  The decrease in segment-operating profit issubstantially the result of a $23.2 million increase in the non-cashmark-to-market losses from our price risk management activities related tofuture sales of gas utilizing our storage and transportation 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 $3.3 million forthe three months ended March 31, 2005 compared to $2.4 million in the sameperiod of 2004.  The Transportationsegment includes the results from the MIGC and MGTC pipelines in the PowderRiver Basin.

 

**Liquidityand Capital Resources**

 

Our sources of liquidity and capital resources historically have beennet cash provided by operating activities, funds available under our financingfacilities and proceeds from offerings of debt and equity securities.  In the past, these sources have beensufficient to meet our needs and finance the growth of our business.  We can give no assurance that the historicalsources of liquidity and capital resources will be available for future developmentand acquisition projects, and we may be required to seek additional oralternative financing sources.  Productprices, hedges of equity production, sales of inventory, the volume of naturalgas processed by our facilities, the volume of natural gas produced from ourproducing properties, the margin on third-party product purchased for resale,as well as the timely collection of our receivables are all expected to havesignificant influences on our future net cash provided by operating activities.  Additionally, our future growth will bedependent upon obtaining additions to dedicated plant reserves, acquisitions,new project development, marketing results, efficient operation of ourfacilities and our ability to obtain financing at favorable terms.

 

Duringthe past several years, we have been successful in developing additionalreserves of natural gas and increasing our equity natural gas production.  However, the overall level of drilling andproduction associated with our producing properties will depend upon, amongother factors, the price for gas, availability of transportation capacity tomarket centers, the energy and environmental policy and regulation bygovernmental agencies, the

 

21

----

 

drilling schedules of the operators of ournon-operated properties, the issuance of drilling and water disposal permits,the available of oil field services, 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 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.

 

Althoughsome of our plants have experienced natural declines in dedicated reserves,overall we have been successful in connecting additional reserves to more thanoffset these declines.  However, theoverall level of drilling associated with our plant facilities will dependupon, among other factors, the prices for oil and gas, the drilling budgets ofthird-party producers, availability of transportation capacity to marketcenters, the energy and environmental policy and regulation by governmentalagencies, the pace at which drilling permits are received, and the availabilityof foreign oil and gas, none of which is within our control. There is noassurance that we will continue to be successful in replacing the dedicatedreserves processed at our facilities. Any prolonged reduction in prices for natural gas and NGLs may depressthe levels of exploration, development and production by third parties.  Lower levels of these activities could resultin a corresponding decline in the demand for our gathering, processing and treatingservices.  A reduction in any of theseactivities could have a material adverse effect on our financial condition,results of operations and cash flows.

 

Webelieve that the amounts available to be borrowed under our financingfacilities, together with net cash provided by operating activities, willprovide us with sufficient funds to connect new reserves, maintain our existingfacilities and complete our current capital expenditure program.  Depending on the timing and the amount of ourfuture projects, we may be required to seek additional sources of capital.  Our ability to secure such capital isrestricted by our financing facilities, although we may request additionalborrowing capacity from our lenders, seek waivers from our lenders to permit usto borrow funds from third-parties, seek replacement financing facilities fromother lenders, use stock as a currency for acquisitions, sell existing assetsor use a combination of alternatives. While we believe that we would be able to secure additional financing,if required, we can provide no assurance that we will be able to do so or as tothe terms of any additional financing. 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.

 

***Sources and Uses of Funds*****.**  Oursources and uses of funds for the quarter ended March 31, 2005 aresummarized as follows (dollars in thousands):

 

| **Sources of funds:**                                            |   |    |    |
|------------------------------------------------------------------|--------|---------|---------|
| Borrowings under the revolving credit  facility                  |   | $       | 807,065 |   |
| Borrowings under the master shelf agreement                      |   | 25,000  |    |
| Proceeds from the dispositions of property  and equipment        |   | 767     |    |
| Net cash provided by operating activities                        |   | 117,396 |    |
| Distributions from equity investments                            |   | 324     |    |
| Proceeds from exercise of common stock  options                  |   | 2,307   |    |
| Total sources of funds                                           |   | $       | 952,859 |   |
|                                                             |   |    |    |
| **Uses of  funds:**                                              |   |    |    |
| Payments related to long-term debt  (including debt issue costs) |   | $       | 828,205 |   |
| Capital expenditures                                             |   | 115,332 |    |
| Change in balance of outstanding checks                          |   | 4,283   |    |
| Common dividends paid                                            |   | 3,704   |    |
| Total uses of funds                                              |   | $       | 951,524 |   |

 

***Capital Investment Program.***  Wecurrently anticipate capital expenditures in 2005 of approximately $376.4million.   The 2005 capital budget is a24% increase over the amount expended in 2004. This increase is the result of an expected increase in drilling activityin each of our upstream areas and additional drilling activity by third partyproducers whose acreage is dedicated to our midstream facilities.  Overall, capital expenditures in the PowderRiver Basin CBM development and in the Greater Green River Basin operationsrepresent 34% and 29%, respectively, of the total 2005 budget.  Due to drilling and regulatory uncertaintiesthat are beyond our control, we can make no

 

22

----

 

assurance that our capital budget for 2005will not change or that we will actually incur this level of capitalexpenditures.  This budget may beincreased to provide for acquisitions if approved by our board of directors.

 

The2005 capital budget and our capital expenditures during the quarter endedMarch 31, 2005 are presented in the following table (dollars in millions).

 
| **Type of Capital Expenditure**                              | ** ** | **2005 Capital  Budget** | ** ** | **Capital Expenditures  During the  Quarter Ended  March 31, 2005** | ** ** |
|--------------------------------------------------------------|------------|--------------------------|------------|--------------------------------------------------------------------------|------------|
| Gathering,  processing, treating and pipeline assets (1)     |       | $                        | 132.8      |                                                                     | $          | 27.9 |   |
| Exploration  and production and lease acquisition activities |       | 204.3                    |       | 56.7                                                                     |       |
| Acquisition  of Greater Green River Basin midstream assets   |       | 28.0                     |       | 28.0                                                                     |       |
| Information  technology and other items                      |       | 3.0                      |       | .6                                                                       |       |
| Capitalized  interest and overhead                           |       | 8.3                      |       | 2.8                                                                      |       |
| Total Capital Expenditures                                   |       | $                        | 376.4      |                                                                     | $          | 116.0 |   |

 

----

(1) Includes$13.7 million budgeted in 2005 and $1.2 million expended in the quarter endedMarch 31, 2005 for maintaining existing facilities.

 

***Contractual Commitments andObligations***

 

##### ***Contractual Cash Obligations. ***Asummary of our contractual cash obligations as of March 31, 2005 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 |       | $                      | 4,531      |                   | $          | 654 |   | $ | 1,931 |   | $ | 1,946 |   | $ | — |   |
| Operating  Leases                          |       | 83,255                 |       | 12,941                 |       | 33,172 |   | 25,334 |   | 11,808 |   |
| Firm  Transportation Capacity Agreements   |       | 243,598                |       | 29,564                 |       | 72,959 |   | 59,932 |   | 81,143 |   |
| Firm Storage  Capacity Agreements          |       | 30,500                 |       | 6,925                  |       | 9,830 |   | 4,819 |   | 8,926 |   |
| Long-term  Debt                            |       | 385,900                |       | 10,000                 |       | 20,000 |   | 230,900 |   | 125,000 |   |
| Interest on  Long-term Debt (1)            |       | 93,612                 |       | 13,981                 |       | 35,044 |   | 28,696 |   | 15,891 |   |
| Total  Contractual Cash Obligations        |       | $                      | 841,396    |                   | $          | 74,065 |   | $ | 172,936 |   | $ | 351,627 |   | $ | 242,768 |   |

 

----

(1) Theinterest rate assumed on the revolving credit facility at March 31, 2005is 4.1% per annum.

 

***Guarantee of Fort Union ProjectFinancing.***   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 ofthe gathering header and treating system have been project financed by FortUnion.  This debt is amortizing on an annualbasis and is scheduled to be fully paid in 2009.   Our requirement to fund under this guaranteewould be reduced by the value of assets held by Fort Union.  This guarantee is not reflected on ourConsolidated Balance Sheet.

 

***Operating Leases. **** *In the ordinary course of our business operations, we enter intooperating leases for office space, and for office, communication,transportation and compression equipment. Payments made on these leases are a component of operating expenses andare reflected on the Consolidated Statement of Operations and, as operatingleases, are not reflected on our Consolidated Balance Sheet.  Our leases have terms ranging from one monthto ten years and the majority of the leases have return or fair market purchaseoptions available at various times during the lease.   If we were to exercise the purchase optionson all the leased compression equipment, these purchase options would requirethe capital expenditure of approximately $44.9 million between 2007 and 2013.

 

***Firm Transportation Capacity.*** Access to firm transportation is also a significant element of ourbusiness strategy.  Firm transportationensures that our equity production has access to downstream markets and allowsus to capture incremental profit when pricing differentials between physicallocations occur.    Firm transportationagreements generally require the payment of fixed monthly fees regardless ofthe quantity of gas that flows under a particular agreement.  These agreements are not reflected on ourConsolidated Balance Sheet.

 

23

----

 

AtMarch 31, 2005, the fixed fees associated with our existing contracts forfirm transportation capacity during 2005 will average approximately $0.16 perMcf.  The associated contract periodsrange from one month to twelve years. Under firm transportation contracts, we are required to pay the feesassociated with these contracts whether or not the transportation is used.

 

***Firm Storage Capacity Agreements*****.**  Wecustomarily store gas in underground storage facilities to ensure an adequatesupply for long-term sales contracts and to capture seasonal pricedifferentials.  As of March 31,2005, we had contracts in place for approximately 15.6 Bcf of storage capacityat various third-party facilities.  Firmstorage agreements generally require the payment of fixed monthly feesregardless of the quantity of gas that is in storage under a particularagreement.  Of the total storage capacityunder contract, approximately 5.0 Bcf is under contract to our Canadiansubsidiary, WGR Canada, Inc., and Western guarantees the subsidiary’sperformance under these contracts.  Thissubsidiary is wholly owned by us and fully consolidated in our financialstatements.

 

Thefees associated with these contracts in 2005 will average $0.59 per Mcf ofannual capacity.  The associated contractperiods at March 31, 2005 had an average term of 39 months.  At March 31, 2005, we held gas in ourcontracted storage facilities and in imbalances of approximately 13.4 Bcf at anaverage cost of $5.83 per Mcf compared to 4.9 Bcf at an average cost of $5.03per Mcf at March 31, 2004.  Thesepositions are for storage withdrawals within the next 14 months.  At the time we place product into storage, wecontract for the sale of that product, physically or financially, and do notspeculate on the future value of the product. These agreements for storage capacity are not reflected on ourConsolidated Balance Sheet.

 

Fromtime to time, we lease NGL storage space at major trading locations tofacilitate the distribution of products. At March 31, 2005, we held NGLsin storage at various third-party facilities of 3,669 MGal, consistingprimarily of propane and ethane, at an average cost of $0.45 per galloncompared to 2,863 MGal at an average cost of $0.30 per gallon at March 31,2004.

 

**Long-term Debt**

 

***Revolving Credit Facility. ***The commitment under the revolving credit facility totals $500 millionand matures in June 2009.  AtMarch 31, 2005, $230.9 million was outstanding under this facility.   Loans made under this facility are securedby a pledge of the capital stock of our significant subsidiaries, and thesesubsidiaries also guarantee the borrowings under the facility.

 

Theborrowings under the credit facility bear interest at Eurodollar rates or abase rate, as requested by us, plus an applicable percentage based on our debtto capitalization ratio.  The base rateis the agent’s published prime rate.  Wealso pay a quarterly commitment fee ranging between 0.20% and 0.375%, dependingon our debt to capitalization ratio. This fee is paid on unused amounts of the commitment.  At March 31, 2005, the interest ratepayable on borrowings under this facility was approximately 4.1% perannum.  Under the credit facility, we aresubject to a number of covenants, including: maintaining a total debt tocapitalization ratio of not more than 55% and maintaining a ratio of EBITDA, asdefined in the credit facility, to interest over the last four quarters inexcess of 3.0 to 1.0.  The creditfacility ranks equally with borrowings under our master shelf agreement withThe Prudential Insurance Company.  Thisfacility has been rated Ba1 by Moody’s and BB+ by S&P.

 

***Master Shelf Agreement. ***Amounts outstanding under the master shelf agreement at March 31,2005 are as indicated 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 July 28 of 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    |               |       |                   |                |                              |                                               |   |

 

Ourborrowings under the master shelf agreement are secured by a pledge of thecapital stock of our significant subsidiaries. These subsidiaries also guarantee 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.

 

24

----

 

InDecember 2004, we gave notice to Prudential of our intention to prepay a$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, we issued a new $25 million note to Prudential, dueJanuary 2015 and bearing interest at 5.57% per annum.  During 2005, we will make scheduled paymentstotaling $10.0 million on these notes. We intend to fund these repayments with funds available under therevolving credit facility.

 

***Upstream Operations***

 

Avital aspect of our long-term business plan is to double proven natural gasreserves and equity production of natural gas from the level atDecember 31, 2001 over a five-year period. In order to achieve this goal, we will focus on continued development ofour leasehold positions in the Powder River Basin CBM development, the GreaterGreen River Basin, the San Juan Basin, and the Sand Wash basin. Each of ourexisting upstream projects is fully integrated with our midstreamoperations.  In other words, in each ofthese areas, we provide the gathering, compression, processing, marketing ortransportation services for both our own production and for third-party operators.  Additionally, we are actively pursuing newexploration, development and producing property acquisition opportunities.

 

Our principal upstream operations are summarized in the followingtable:

 
| **Production Area**     | ** ** | **Gross Acres  Under Lease  at  March 31,  2005** | ** ** | **Net Acres  Under  Lease at  March 31,  2005** | ** ** | **Average Net  Production for  the Quarter  Ended  March 31,  2005(1)** | ** ** | **Gross Productive  Gas Wells at March 31,  2005** | ** ** | **Net Productive  Gas Wells at March 31,  2005** | ** ** |
|-------------------------|------------|--------------------------------------------------------|------------|------------------------------------------------------|------------|------------------------------------------------------------------------------|------------|---------------------------------------------------------|------------|-------------------------------------------------------|------------|
| Powder River  Basin     |       | 1,048,000                                              |       | 535,000                                              |       | 112                                                                          |       | 4,309                                                   |       | 2,045                                                 |       |
| Jonah/Pinedale  Field   |       | 160,000                                                |       | 28,000                                               |       | 36                                                                           |       | 237                                                     |       | 28                                                    |       |
| San Juan  Basin         |       | 34,000                                                 |       | 26,000                                               |       | 10                                                                           |       | 139                                                     |       | 128                                                   |       |
| Sand Wash  Basin        |       | 146,000                                                |       | 137,000                                              |       | 5                                                                            |       | 19                                                      |       | 19                                                    |       |
| Denver-Julesburg  Basin |       | 395,000                                                |       | 340,000                                              |       | —                                                                       |       | —                                                  |       | —                                                |       |
| Other                   |       | 573,000                                                |       | 500,000                                              |       | 1                                                                            |       | 12                                                      |       | 2                                                     |       |
| Total                   |       | 2,356,000                                              |       | 1,566,000                                            |       | 164                                                                          |       | 4,716                                                   |       | 2,222                                                 |       |

 

----

(1) Representsnet production sold in Mmcfe per day.

 

***Drilling Results.***** **The following table sets forth the number of wells we drilled duringthe three months ended March 31, 2005 and 2004 in each of our majorproducing areas.  This information shouldnot be considered indicative of future performance, nor should it be assumedthat there is necessarily any correlation between the number of productivewells drilled, quantities of reserves found or economic value.  Productive wells are defined as those thatproduce commercial quantities of hydrocarbons whether or not they produce areasonable rate of return.

 

| ** **                             | ** ** | **Quarter Ended March 31,** | ** ** |
|----------------------------------------|------------|----------------------------------|------------|
| **Productive Area**                    | ** ** | **2005**                         | ** ** | **2004** | ** ** |
| ** **                             | ** ** | **Gross**                        | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Powder River Basin CBM**             |       |                             |       |   |   |   |   |   |   |
| Productive  wells drilled:             |       | 173                              |       | 88 |   | 161 |   | 83 |   |
|                                   |       |                             |       |   |   |   |   |   |   |
| **Jonah/Pinedale Field**               |       |                             |       |   |   |   |   |   |   |
| Productive  wells drilled:             |       | 19                               |       | 2 |   | 12 |   | 1 |   |
| Dry  exploratory wells drilled:        |       | 1                                |       | 0 |   | 0 |   | 0 |   |
|                                   |       |                             |       |   |   |   |   |   |   |
| **San Juan Basin**                     |       |                             |       |   |   |   |   |   |   |
| Productive  wells drilled:             |       | 17                               |       | 16 |   | 0 |   | 0 |   |
|                                   |       |                             |       |   |   |   |   |   |   |
| **Sand Wash Basin**                    |       |                             |       |   |   |   |   |   |   |
| Productive  wells drilled:             |       | 0                                |       | 0 |   | 3 |   | 3 |   |
| Dry  exploratory wells drilled:        |       | 1                                |       | 1 |   | 0 |   | 0 |   |
|                                   |       |                             |       |   |   |   |   |   |   |
| **Other**                              |       |                             |       |   |   |   |   |   |   |
| Exploratory  productive wells drilled: |       | 2                                |       | 1 |   | 0 |   | 0 |   |

 

25

----

 

***Powder River Basin Coal BedMethane. ***We continue to develop our Powder River BasinCBM reserves and expand the associated gathering system in northeastWyoming.  Our net production sold fromthe Powder River Basin CBM averaged 112 MMcf per day in the first quarter of2005.

 

Ourproduction from the Big George coal continues to increase and was 89 MMcf perday gross at March 31, 2005, or 37 MMcf per day net, from the All NightCreek Unit, Pleasantville, SG Palo, Bullwhacker, Schoonover and Kingsbury Unitareas.  In the Big George coal, as ofApril 2005, we had 748 wells dewatering and producing gas, 431 wellsdewatering and 634 wells drilled and in various stages of completion andhook-up in preparation for dewatering and production.

 

Drillingin the Powder River Basin is dependent on the receipt of various regulatorypermits, including BLM drilling permits, DEQ water discharge permits, and theWyoming 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 effective and cost efficientmethods.

 

Our2005 capital budget for the Powder River Basin coal bed project is estimated at$81.2 million, of which $29.1million was spent in the first quarter of2005.  In 2005, we plan to participate inthe drilling of 730 gross wells, or 365 net wells, in the Big George andrelated coals and an additional 120 gross wells, or 60 net wells, in the Wyodakand related coals.  An estimated 640wells of the 850-well program will be on federal leaseholds and requiredrilling permits from the Bureau of Land Management, or BLM.  The remaining 210 well locations are on feeor state leaseholds.  Together with ourco-developer, as of March 5, 2005, we have drilling permits approved for421 of the federal wells planned for 2005. Federal drilling permit applications for another 581 locations have beensubmitted to the BLM.  Timely receipt ofthese permits would allow us to complete our planned 2005-drilling program, anda portion of our 2006-drilling program, on federal leaseholds.

 

Approximately300 gross wells in our 2005-drilling program will require permits to treatproduced water.  The remainder of thewells to be drilled in 2005 will require more conventional types of waterdischarge permits, such as reservoir containment or surface discharge.  To date, we, together with our co-developerin this area, have received water discharge permits from the DEQ forapproximately 49% of the wells we plan to drill in 2005.  An additional 484 permit applications havebeen submitted to the DEQ which, when combined with permits received, is morethan enough necessary to complete our 2005 drilling program.  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 water dischargepermits, the success of our drilling program, or the dewatering time as ourdevelopment progresses into the western and northern parts of the Powder RiverBasin.

 

OnApril 30, 2003, the BLM issued the final Record of Decision, or ROD, forthe Powder River Basin Oil & Gas Environmental Impact Statement, orEIS.  The ROD requires additional surveysfor plant and animal species, cultural surveys and noxious weed mitigationprior to the BLM granting a drilling permit. A number of cases have been filed by environmental groups against theBLM in Wyoming disputing the validity of the environmental impact statement andROD.  Due to our interests in developingfederal leases in the Powder River Basin, we are an intervenor defendant ineach of the foregoing cases.  In one ofthese cases filed in the United States District Court of Montana, the Court wasasked to address the adequacy of the Montana Powder River Basin ROD and whetherthe BLM should have issued a single EIS for the Powder River Basin.  Under an Order dated March 4, 2005, theCourt found that a single EIS for the Powder River Basin is not required underNEPA. As these cases proceed, the BLM, in the event of any adverse rulings, maybe required to perform further environmental analysis and, in addition, couldbe ordered to cease issuing drilling permits until it has completed suchfurther analysis.   Consequently, ourability to receive permits and develop our leases may be delayed or restrictedby the outcome of these cases.

 

OnAugust 10, 2004, the Tenth Circuit Court of Appeals issued its decision inPennaco Energy, Inc. v. United States Department of the Interior.  The court upheld a decision by the InteriorBoard of Land Appeals, or IBLA, that the BLM had not complied with the NationalEnvironmental Policy Act in issuing three federal leases to Pennaco

 

26

----

 

Energy, Inc. in the Powder River Basinfor coalbed methane development.  We arenot a party to the case, and the IBLA and Tenth Circuit decisions do notdirectly address any federal leases held by us. However, we hold approximately 70,000 net acres of federal leasehold inthe Powder River Basin, which may potentially be affected by the response tothe Pennaco case.  In order to resolvethe issues raised in the Pennaco decision and related issues, the BLM filed forand received public comment on two proposed environmental assessments.  After completion of the environmentalassessments, we are advised that the BLM believes the issues raised in thePennaco decision will be resolved.  Wecannot predict what other actions the Department of Interior or third partiesmight take in response to this matter, or how the decision and actions taken bythe BLM in response to the decision may affect the pace of federal leasing orpermitting and development in the Powder River Basin.

 

Acomplaint was filed on January 31, 2005 in the U.S. District Court ofWyoming against the BLM and the Department of Interior.  The complaint alleges that the BLM violatedNEPA “as described in Pennaco Energy, Inc. v. United States Departmentof the Interior” because the BLM did not consider the effects of CBMdevelopment prior to issuing five leases including one issued to us.  The plaintiffs have asked the court for a“review of the issuance” of these leases.   We cannot predict what actions, if any, the Department of the Interior,third parties, or the Court might take in response to this case, or how theseactions may affect the pace of federal drilling or permitting and developmentof the Powder River Basin.

 

***Jonah/Pinedale Fields.***  Ourexploration and production assets in the Green River Basin of southwest Wyomingare located in the Pinedale Anticline and Jonah Field areas.  During 2005, we expect to participate in thedrilling of 80 gross wells, or approximately nine net wells, on the PinedaleAnticline.  Our capital budget for 2005in the Pinedale Anticline area provides for expenditures of approximately $47.9million for drilling costs and production equipment, of which $16.8 million wasspent in the first quarter of 2005.  Dueto drilling and regulatory uncertainties, which are beyond our control, therecan be no assurance that we will incur this level of capital expenditure during2005.

 

***Midstream Operations***

 

Ourmidstream operations consist of our gathering, processing, treating, marketingand transportation operations.  Animportant element of our long-term business plan is to meet or exceedthroughput projections in these areas and to optimize their profitability.  To achieve this goal, we must continue ourefforts to add to natural gas throughput levels through new well connectionsand through the expansion or acquisition of gathering or processingsystems.  We also seek to increase theefficiency of our operations by modernization of equipment and theconsolidation of existing facilities.

 

***Gas Gathering, Processing andTreating.*** Weoperate a variety of gathering, processing and treating facilities, or plantoperations, as presented on the Principal Gathering and Processing FacilitiesTable set forth below.  Our operationsare located in some of the most actively drilled oil and gas producing basinsin the United States.  Six of ourprocessing plants can further separate, or fractionate, the mixed NGL streaminto ethane, propane, normal butane and natural gasoline to obtain a highervalue for the NGLs, and three of our plants are capable of processing andtreating natural gas containing hydrogen sulfide or other impurities thatrequire removal prior to delivery to market pipelines.   In addition to our integrated upstream andmidstream operations in the Powder River and Green River Basins in Wyoming, andin the San Juan Basin in New Mexico, our core assets include our plantoperations located in west Texas and Oklahoma. We believe that our core assets have stable production rates, provide asignificant operating cash flow and continue to provide us with strategicgrowth opportunities.

 

InFebruary 2005, we closed on the purchase of certain natural gas gatheringand processing assets in the eastern Greater Green River Basin forapproximately $28.0 million, before closing adjustments.  We currently plan to integrate portions ofthe acquired systems into our Red Desert plant and our Table Rock, Wamsutterand Desert Springs gathering systems during the third quarter of 2005.

 

Inthe first quarter of 2005, we agreed to acquire a 200 MMcf per day cryogenicprocessing facility for $9.0 million.  Weintend to expend an additional $28.5 million to install this facility andexpand our Chaney Dell/Westana processing and gathering complex.  We currently expect that this facility willbe operational in the second quarter of 2006.

 

27

----

 

***Principal Gathering and ProcessingFacilities Table.***  The following table provides informationconcerning our principal gathering, processing and treating facilities atMarch 31, 2005.

 
| ** **                    | ** ** | **Year**                | ** ** | **Gas**                      | ** ** | **Gas**                               | ** ** | **Average for the Quarter Ended  March 31, 2005** | ** ** |
|-------------------------------|------------|-------------------------|------------|------------------------------|------------|---------------------------------------|------------|--------------------------------------------------------|------------|
| **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                                   |       | 89                                                     |       | 81 |   | — |   |
| Midkiff/Benedum               |       | 1949                    |       | 2,332                        |       | 165                                   |       | 141                                                    |       | 93 |   | 810 |   |
| Mitchell Puckett Treating (5) |       | 1972                    |       | 126                          |       | 120                                   |       | 36                                                     |       | 22 |   | 1 |   |
| Wyoming                       |       |                    |       |                         |       |                                  |       |                                                   |       |   |   |   |   |
| Coal Bed Methane Gathering    |       | 1990                    |       | 1,369                        |       | 548                                   |       | 387                                                    |       | 356 |   | — |   |
| Desert Springs Gathering      |       | 1979                    |       | 65                           |       | 10                                    |       | 6                                                      |       | 6 |   | 21 |   |
| Fort Union Gas Gathering(12)  |       | 1999                    |       | 167                          |       | 635                                   |       | 469                                                    |       | 469 |   | — |   |
| Granger Complex (6)(7)(8)     |       | 1987                    |       | 714                          |       | 325                                   |       | 289                                                    |       | 248 |   | 396 |   |
| Granger Straddle Plant        |       | 2004                    |       | —                       |       | 200                                   |       | 155                                                    |       | — |   | 12 |   |
| Hilight Complex (6)           |       | 1969                    |       | 657                          |       | 124                                   |       | 17                                                     |       | 13 |   | 60 |   |
| Kitty/Amos Draw (6)           |       | 1969                    |       | 321                          |       | 17                                    |       | 5                                                      |       | 3 |   | 24 |   |
| Newcastle (6)                 |       | 1981                    |       | 146                          |       | 5                                     |       | 3                                                      |       | 2 |   | 21 |   |
| Patrick Draw(6) (9)      |       | 1997                    |       | 284                          |       | 150                                   |       | 23                                                     |       | 19 |   | 54 |   |
| Red Desert (6)                |       | 1979                    |       | 125                          |       | 42                                    |       | 18                                                     |       | 31 |   | 58 |   |
| Rendezvous (10)               |       | 2001                    |       | 238                          |       | 275                                   |       | 326                                                    |       | 326 |   | — |   |
| Reno Junction (7)             |       | 1991                    |       | —                       |       | —                                |       | —                                                 |       | — |   | 110 |   |
| Table Rock Gathering          |       | 1979                    |       | 100                          |       | 20                                    |       | 13                                                     |       | 13 |   | — |   |
| Wamsutter Gathering (11)      |       | 1979                    |       | 242                          |       | 50                                    |       | 44                                                     |       | 40 |   | 25 |   |
| Wind River Gathering          |       | 1979                    |       | 137                          |       | 80                                    |       | 46                                                     |       | 46 |   | — |   |
| Oklahoma                      |       |                    |       |                         |       |                                  |       |                                                   |       |   |   |   |   |
| Chaney Dell/Westana           |       | 1966                    |       | 3,307                        |       | 175                                   |       | 191                                                    |       | 168 |   | 302 |   |
| New Mexico                    |       |                    |       |                         |       |                                  |       |                                                   |       |   |   |   |   |
| San Juan River (5)            |       | 1955                    |       | 277                          |       | 60                                    |       | 25                                                     |       | 20 |   | 36 |   |
| Utah                          |       |                    |       |                         |       |                                  |       |                                                   |       |   |   |   |   |
| Four Corners Gathering        |       | 1988                    |       | 104                          |       | 15                                    |       | 3                                                      |       | 2 |   | 15 |   |
| Yellow Creek (9) (13)    |       | 1985                    |       | —                       |       | —                                |       | —                                                 |       | — |   | 66 |   |
| Total                         |       |                    |       | 11,100                       |       | 3,296                                 |       | 2,286                                                  |       | 1,958 |   | 2,011 |   |

 

----

(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 datainclude our interests and the interests of other joint interest owners and producersof gas volumes dedicated to the facility. Unless otherwise indicated, all facilities shown in the table aregathering, processing or treating facilities.

(2)                      Gas throughput capacity is as of March 31, 2005 and representscapacity in accordance with design specifications unless other constraintsexist, 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 isconnected to that facility; volumes exclude NGLs fractionated forthird-parties.

(5)                      Sour gas facility (capable of processing or treating gas containinghydrogen sulfide and/or carbon dioxide).

(6)                      Processing facility that includes fractionation (capable of fractionatingraw NGLs into end-use products).

(7)                      NGL production includes conversion of third-party feedstock toiso-butane.

(8)                      The Granger Complex includes the Lincoln Road facility.  The volume information for this facility isreported with the volume information for Granger.

(9)                      This facility was acquired in a transaction, which closed onFebruary 1, 2005.

(10)                Themajority of the gas gathered by the Rendezvous gas gathering system isdelivered to our Granger facility and is included with the volume informationreported for Granger.

(11)                Aportion of the gas gathered by the Wamsutter gas gathering system is deliveredto our Red Desert facility and is included with the volume information reportedfor Red Desert.

(12)                Aportion of the gas gathered by Fort Union is also reported under Coal BedMethane Gathering.

(13)                NGLfractionation facility that receives product from a third-party owned liquidspipeline.

 

28

----

 

***Transportation Operations***

 

We own and operate MIGC, Inc., an interstate pipeline located inthe Powder River Basin, and MGTC, Inc., an intrastate pipeline located innortheast Wyoming.  MIGC charges aFederal Energy Regulatory Commission, or FERC, approved tariff and is connectedto pipelines owned by Colorado Interstate Gas Company, Williston BasinInterstate Pipeline Company, Kinder Morgan Interstate Pipeline Co., WyomingInterstate Company, Ltd. and MGTC.  MIGCearns fees on a monthly basis from firm capacity contracts under which theshipper 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.  Contracts with thirdparties for capacity on MIGC range in duration from one month to approximatelyfive years, and the fees charged averaged $0.35 per Mcf in the first quarter of2005.  MGTC, a public utility, providestransportation and gas sales to various cities in Wyoming at rates that aresubject to the approval of the Wyoming Public Service Commission.

 

Thefollowing table provides information concerning our principal transportationassets at March 31, 2005.

 
| ** **                        | ** ** | ** **                  | ** ** | ** **                | ** ** | **Average for the Quarter Ended  March 31, 2005** | ** ** |
|-----------------------------------|------------|-----------------------------|------------|---------------------------|------------|--------------------------------------------------------|------------|
| **Transportation Facilities (1)** | ** ** | **Year Placed  In Service** | ** ** | **Transportation  Miles** | ** ** | **Pipeline Capacity (MMcf/D) (2)**                     | ** ** | **Gas Throughput (MMcf/D) (3)** | ** ** |
| MIGC                              |       | 1970                        |       | 263                       |       | 130                                                    |       | 146 |   |
| MGTC                              |       | 1963                        |       | 251                       |       | 18                                                     |       | 7 |   |
| Total                             |       |                        |       | 514                       |       | 148                                                    |       | 153 |   |

 

----

(1)                      Our interest in both facilities is 100%, and we operate bothfacilities.

(2)                      Pipeline capacity represents certificated capacity at the Powder Riverjunction only and does not include interruptible capacity or capacity at otherdelivery points.

(3)                      Aggregate volumes transported by a pipeline.

 

***Marketing***

 

***Gas*****.*   ***We market gas produced at our wells and atour plants and gas purchased from third-parties to end-users, localdistribution 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 ourgas marketing operations continues to be 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 through the use of firmtransportation capacity.

 

***NGLs*****.* ***We market NGLs, or ethane, propane,iso-butane, normal butane, natural gasoline and condensate, produced at ourplants and purchased from third-parties, in the Rocky Mountain, Mid-Continentand Southwestern regions of the United States. A majority of our production of NGLs moves to the Gulf Coast area, whichis the largest NGL market in the United States. Through the development of end-use markets and distributioncapabilities, we seek to ensure that products from our plants move on areliable basis, avoiding curtailment of production. Consumers of NGLs areprimarily the petrochemical industry, the petroleum refining industry and theretail and industrial fuel markets.  Asan example, the petrochemical industry uses ethane, propane, normal butane andnatural gasoline as feedstocks in the production of ethylene, which is used inthe production 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.

 

29

----

 

**ITEM 3.**      **QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKETRISK**

 

Ourcommodity price risk management program has two primary objectives.  The first goal is to preserve and enhance thevalue of our equity volumes of gas and NGLs with regard to the impact ofcommodity price movements on cash flow and net income in relation to thoseanticipated by our operating budget.  Thesecond goal is to manage price risk related to our marketing activities toprotect profit margins.  This riskrelates to fixed price purchase and sale commitments, the value of storageinventories and exposure to physical market price volatility.

 

Weutilize a combination of fixed price forward contracts, exchange-traded futuresand options, as well as fixed index swaps, basis swaps and options traded inthe over-the-counter, or OTC, market to accomplish these goals.  These instruments allow us to preserve valueand protect margins because corresponding losses or gains in the value of thefinancial instruments offset gains or losses in the physical market.

 

Wealso use 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.

 

Weenter into futures transactions on the New York Mercantile Exchange, or NYMEX,and OTC swaps and options with various counterparties, consisting primarily ofinvestment banks, financial institutions and other natural gas companies.  We conduct credit reviews of all of our OTCcounterparties and have agreements with many of these parties that containcollateral requirements.  We generallyuse standardized swap agreements that allow for offset of positive and negativeOTC exposures with the same counterparty. OTC exposure is marked-to-market daily for the credit reviewprocess.  Our exposure to OTC credit riskis reduced by our ability to require a margin deposit from our counterpartiesbased upon the mark-to-market value of their net exposure.  We are also subject to margin depositrequirements under these same agreements and under margin deposit requirementsfor our NYMEX transactions.  AtMarch 31, 2005, we had $13.1 million of margin deposits outstanding.

 

Wecontinually monitor and review the credit exposure to our marketingcounterparties.  In recent months theprices of natural gas and NGLs, and therefore our credit exposures, haveincreased significantly.  In order tominimize our credit exposures, we have utilized existing netting agreements toreduce our net credit exposure, established new netting agreements withadditional customers, terminated several long-term marketing obligations,negotiated accelerated payment terms with several customers, and increased theamount of credit which we make available to substantial companies which meetour credit requirements.  Althoughnetting agreements similar to those that we utilize have been upheld bybankruptcy courts in the past, if any of the customers with whom we havenetting agreements were to file for bankruptcy, we can provide no assurancethat our agreements will not be challenged or as to the outcome of anychallenge.

 

Theuse of financial instruments may expose us to the risk of financial loss insome circumstances, including instances when (i) our equity volumes areless than expected, (ii) our customers fail to purchase or deliver thecontracted quantities of natural gas or NGLs, or (iii) our OTCcounterparties fail to perform.  To theextent that we engage in hedging activities, we may be prevented from realizingthe benefits of favorable price changes in the physical market.  However, we are similarly insulated againstdecreases in these prices.

 

Weenter into derivatives for the future sale or purchase of natural gas to useour storage and transportation capacity. These transactions utilizing our capacity are economic hedges, but arenot afforded hedge accounting treatment. Therefore, the non-cash mark-to-market of these economic hedges willfluctuate through earnings with changes in market prices.  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.

 

***Risk Policy and Control.**** *We control the extent of risk management and marketing activitiesthrough policies and procedures that involve the senior level ofmanagement.  On a daily basis, ourmarketing activities are audited and monitored by our independent riskoversight department, or IRO.  This departmentreports to the Chief Financial Officer, thereby providing a separation ofduties from the marketing department. Additionally, the IRO reports monthly to the Risk Management Committee,or RMC.  This committee is comprised ofcorporate managers and officers and is responsible for developing the policiesand guidelines that control the management and measurement of risk, subject tothe approval 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.

 

30

----

 

***Hedge Positions.***** **As of March 31, 2005, we have hedged approximately 61% of ourprojected 2005 equity natural gas volumes and approximately 32% of ourprojected 2005 equity production of crude oil, condensate, and NGLs.  All these contracts are designated andaccounted for as cash flow hedges.  Assuch, gains and losses related to the effective portions of the changes in thefair value of the derivatives are recorded in Accumulated other comprehensiveincome, a component of Stockholders’ equity. Realized gains or losses on these cash flow hedges are recognized in theConsolidated Statement of Operations through Sale of gas or Sale of natural gasliquids when the hedged transactions occur.

 

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 our exposure to the risk of commodity price changes is reduced.  To meet this requirement, we hedge the priceof the commodity and, if applicable, the basis between that derivative’scontract delivery location and the cash market location used for the actualsale of the product.  This structureattains a high level of effectiveness, ensuring that a change in the price ofthe forecasted transaction will result in an equal and opposite change in theprice of the derivative instrument hedging the transaction.  We utilize crude oil as a surrogate hedge fornatural gasoline and condensate.  Ourhedges are tested for effectiveness at inception and on a quarterly basisthereafter.  We use regression analysisbased on a five-year period of time for this test.  Gains or losses from the ineffective portionsof changes in the fair value of cash flow hedges are recognized currently inearnings through Price risk management activities.  During the first quarter of 2005, werecognized a loss of $87,000 from the ineffective portions of our hedges.

 

***Earnings Sensitivity.*** Historically, the non-cash mark-to-market valuation of the gas storageand transportation contracts which were considered to be derivativeseffectively offset non-cash mark-to-market changes to the forward derivativecontract to sell our stored or transported natural gas.  After the adjustments to correct the prioraccounting for these contracts as derivatives, the non-cash mark-to-market ofthe future sale derivative contract on the sale of gas will fluctuate throughearnings with changes in market prices and will not be offset by acorresponding mark to market on the gas storage and transportationcontracts.  For example, at March 31,2005, we held gas in our contracted storage facilities and in imbalances ofapproximately 13.4 Bcf.  This inventoriedgas was sold forward with derivatives. Based on a $1.00 increase in the forward price of gas in the anticipatedmonth of withdrawal, the change in the non-cash mark-to-market value of thesederivatives will reduce pre-tax earnings by $13.4 million and a $1.00 decreasein the forward price of gas in the anticipated month of withdrawal willincrease pre-tax earnings by $13.4 million. As the stored or transportednatural gas is sold and the future sale derivatives are settled, we willrealize the benefit of the storage and transportation transactions throughearnings.

 

***Outstanding Equity Hedge Positionsand the Associated Basis for 2005****.*  Thefollowing table details our hedge positions as of March 31, 2005.  In order to determine the hedged price to theparticular operating region, deduct the basis differential from the NYMEXprice.  The prices for NGLs do notinclude the cost of the hedges of approximately $468,000 as of March 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                                                                                                                                                                                                                                                              |

 

31

----

 
| 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 |

 

Accountbalances related to hedging transactions (designated as cash flow hedges underSFAS 133) at March 31, 2005 were $2.1 million in Current assets from pricerisk management activities, $13.5 million in Current liabilities from pricerisk management activities, ($4.1) million in Deferred income taxes payable,net, and a $7.2 million after-tax unrealized loss in Accumulated othercomprehensive income, a component of Stockholders’ equity.  The unrealized loss in Accumulated othercomprehensive income will be reclassified to earnings in 2005.

 

***Summary of Derivative Positions.***  Asummary of the change in our derivative position from December 31, 2004 toMarch 31, 2005 is as follows (dollars in thousands):

 

| Fair value of contracts outstanding at  December 31, 2004 (restated) |   | $       | 15,640  |   |
|---------------------------------------------------------------------------|--------|---------|---------|--------|
| Decrease in  value due to change in price                                 |   | (14,442 | )       |
| Decrease in  value due to new contracts entered into during the period    |   | (17,030 | )       |
| (Gains)  realized during the period from existing and new contracts       |   | (10,197 | )       |
| Changes in  fair value attributable to changes in valuation techniques    |   | —  |    |
| Fair value  of contracts outstanding at March 31, 2005 (restated)    |   | $       | (26,029 | )      |

 

Asummary of our outstanding derivative positions at March 31, 2005 is asfollows (dollars in thousands):

 
| ** **                        | ** ** | **Fair Value of Contracts at March 31, 2005 (restated)** | ** ** |
|-----------------------------------|------------|---------------------------------------------------------------|------------|
| **Source of Fair Value**          | ** ** | **Total  Fair Value**                                         | ** ** | **Maturing  In 2005** | ** ** | **Maturing In  2006-2007** | ** ** | **Maturing In  2008-2009** | ** ** | **Maturing  Thereafter** | ** ** |
| Exchange  published prices        |       | $                                                             | (8,255     | ) | $ | (5,888 | ) | $ | (2,367 | ) | — |   | — |   |
| Other actively  quoted prices (1) |       | (4,643                                                        | )          | (4,112 | ) | (555 | ) | $ | 24 |   | — |   |
| Other  valuation methods (2)      |       | (13,131                                                       | )          | (13,131 | ) | — |   | — |   | — |   |
| Total fair  value                 |       | $                                                             | (26,029    | ) | $ | (23,131 | ) | $ | (2,922 | ) | $ | 24 |   | — |   |
|                                   |            |                                                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

----

(1)          Otheractively quoted prices are derived from broker quotations, trade publications,and industry indices.

 

(2)          Othervaluation methods are the Black-Scholes option-pricing model utilizing pricesand volatility obtained from broker quotations, trade publications, andindustry indices.

 

***Foreign Currency Derivative MarketRisk***.  As a normal part of our business, we enterinto physical gas transactions 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 March 31, 2005, we had sold forward contracts for $14.3million in Canadian dollars in exchange for $11.9 million in U.S. dollars, andthe fair market value of these contracts was a loss of $30,000 in U.S. dollars.

 

 

**ITEM 4.  CONTROLS AND PROCEDURES**

 

**Evaluation of Disclosure Controls and Procedures**

 

TheCompany’s management evaluated, with the participation of the Chief ExecutiveOfficer and Chief Financial Officer, the effectiveness of the Company’s disclosurecontrols and procedures, as such term is defined under Rule 13a-15(e) ofthe Securities and Exchange Act of 1934, as of the end of the period covered bythis Quarterly Report on Form 10-Q/A. Based on this evaluation, the ChiefExecutive Officer and Chief Financial Officer have concluded that because ofthe material weakness in internal control over financial reportingrelating to the determination and periodic review of whether its gas storageand transportation contracts meet the definition of a

 

32

----

 

derivative under generally acceptedaccounting principles which was previously identified in “Management’s Reporton Internal Control over Financial Reporting (as restated)” included in Item 8of our Annual Report on Form 10-K/A for the year ended December 31,2004 (“2004 Form 10-K/A”) had not yet been remediated, our disclosurecontrols and procedures were ineffective as of March 31, 2005. Notwithstandingthis material weakness, the Company’s management believes that the consolidatedfinancial condition, results of operations and cash flows are fairly presentedin this Form 10-Q/A.

 

**RemediationEfforts to Address This Material Weakness**

 

Inthe fourth quarter of 2005, we implemented controls to ensure that allcontracts accounted for as derivatives are reviewed as to their terms and themarkets on which they are traded to reaffirm that each contract meets thedefinition of a derivative.  This controlwill be performed on a monthly basis.

 

**Changes in Internal Control Over Financial Reporting**

 

Therewere no material changes to internal controls over financial reporting duringthe first quarter ended March 31, 2005, that have materially affected, or arereasonably likely to materially affect, the Company’s internal control overfinancial reporting. Management continues to work on its remediation plan toaddress the material weakness relating to the accounting for gas transportationand storage contracts identified in our 2004 Form 10-K/A.

 

33

----

 

**PART II- OTHER INFORMATION**

 

**ITEM 1.    LEGALPROCEEDINGS**

 

Referenceis made to “Notes to Consolidated Financial Statements (Unaudited) – LegalProceedings,” in Item 1 of this Form 10-Q/A and incorporated by referencein this Item 1.

 

**ITEM6.      EXHIBITS**

 
| **Exhibit  Number** | ** ** | **Description**                                                                                                                                                                                                                                                           |
|---------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                |       |                                                                                                                                                                                                                                                                      |
| 3.1                 |       | Certificate  of Incorporation of Western Gas Resources, Inc. (previously filed as  Exhibit 3.1 to our Registration Statement on Form S-1, Registration  No. 33-31604 and incorporated herein by reference).                                           |
|                |       |                                                                                                                                                                                                                                                                      |
| 3.2                 |       | Certificate  of Amendment to the Certificate of Incorporation of Western Gas  Resources, Inc. (previously filed as Exhibit 3.2 to our  Registration Statement on Form S-1, Registration No. 33-31604 and  incorporated herein by reference).          |
|                |       |                                                                                                                                                                                                                                                                      |
| 3.3                 |       | Certificate  of Designation, Preferences and Rights of Series A Junior Participating  Preferred Stock (previously filed as part of Exhibit 1 to our  Form 8-A filed on March 30, 2001 and incorporated herein by  reference).                         |
|                |       |                                                                                                                                                                                                                                                                      |
| 3.4                 |       | Amended  and Restated Bylaws of 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 filed on May 11, 2004 and  incorporated herein by reference). |
|                |       |                                                                                                                                                                                                                                                                      |
| 31.1                |       | Section 302  Certification of the Chief Executive Officer.                                                                                                                                                                                                           |
|                |       |                                                                                                                                                                                                                                                                      |
| 31.2                |       | Section 302  Certification of the Chief Financial Officer.                                                                                                                                                                                                           |
|                |       |                                                                                                                                                                                                                                                                      |
| 32.1                |       | Section 906  Certification of the Chief Executive Officer and Chief Financial Officer.                                                                                                                                                                               |

 

34

----

 

SIGNATURES

 

Pursuantto the requirements of the Securities Exchange Act of 1934, the Registrant hasduly caused this report to be signed on its behalf by the undersigned,thereunto duly authorized.

 
|                          | WESTERN GAS RESOURCES,  INC. |
|-------------------------------|------------------------------|
|                          | (Registrant)                 |
|                          |                         |   |
|                          |                         |   |
| Date: December 19,  2005 | By:                          | /s/ PETER A. DEA |   |
|                          |                         | Peter A. Dea |
|                          |                         | Chief Executive Officer  and President |
|                          |                         |   |
|                          |                         |   |
| Date: December 19,  2005 | By:                          | /s/WILLIAM J. KRYSIAK |   |
|                          |                         | William J. Krysiak |
|                          |                         | Executive Vice President -  Chief Financial  Officer |
|                          |                         | (Principal Financial and  Accounting Officer) |

 

35

----

 

INDEX TO EXHIBITS

 
| **Exhibit  Number** | ** ** | **Description**                                                                                                                                                                                                                                                           |
|---------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                |       |                                                                                                                                                                                                                                                                      |
| 3.1                 |       | Certificate  of Incorporation of Western Gas Resources, Inc. (previously filed as  Exhibit 3.1 to our Registration Statement on Form S-1, Registration  No. 33-31604 and incorporated herein by reference).                                           |
|                |       |                                                                                                                                                                                                                                                                      |
| 3.2                 |       | Certificate  of Amendment to the Certificate of Incorporation of Western Gas  Resources, Inc. (previously filed as Exhibit 3.2 to our  Registration Statement on Form S-1, Registration No. 33-31604 and  incorporated herein by reference).          |
|                |       |                                                                                                                                                                                                                                                                      |
| 3.3                 |       | Certificate  of Designation, Preferences and Rights of Series A Junior Participating  Preferred Stock (previously filed as part of Exhibit 1 to our  Form 8-A filed on March 30, 2001 and incorporated herein by  reference).                         |
|                |       |                                                                                                                                                                                                                                                                      |
| 3.4                 |       | Amended  and Restated Bylaws of 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 filed on May 11, 2004 and incorporated  herein by reference). |
|                |       |                                                                                                                                                                                                                                                                      |
| 31.1                |       | Section 302  Certification of the Chief Executive Officer.                                                                                                                                                                                                           |
|                |       |                                                                                                                                                                                                                                                                      |
| 31.2                |       | Section 302  Certification of the Chief Financial Officer.                                                                                                                                                                                                           |
|                |       |                                                                                                                                                                                                                                                                      |
| 32.1                |       | Section 906  Certification of the Chief Executive Officer and Chief Financial Officer                                                                                                                                                                                |

 

36

----