**SECURITIESAND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

### **FORM10-Q**

**(Mark One)**

 

**ý****                                ****QUARTERLY REPORT PURSUANT TOSECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

**FOR THE QUARTERLY PERIOD ENDEDMARCH 31, 2005**

**OR**

**o****                                ****TRANSITION REPORT PURSUANT TOSECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**

**FOR THE TRANSITION PERIOD FROM                             TO**

 

**Commission file number 1-10389**

 

**WESTERNGAS RESOURCES, INC.**

(Exact name of registrantas specified in its charter)

 
| **Delaware**                                                                         | ** ** | **84-1127613**                        |
|--------------------------------------------------------------------------------------|------------|---------------------------------------|
| (State or other  jurisdiction of  incorporation or organization)                     |       | (I.R.S. Employer  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 since last report). |

 

Indicate by checkmark whether the registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements for thepast 90 days. Yes ý  No  o

 

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

 

On May 4, 2005,there were 74,226,162 shares of the registrant’s Common Stock outstanding.

 

 

----

 

**WesternGas Resources, Inc.**

**Form 10-Q**

**Table of Contents**

 
| PART I - Financial  Information |                                                                                                 |
|---------------------------------|------------------------------------------------------------------------------------------------------|
|                            |                                                                                                 |
| 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                      |                                                                                                 |

 

2

----

 

**PART I - FINANCIAL INFORMATION**

 

**ITEM 1.****     FINANCIALSTATEMENTS**

 

WESTERNGAS RESOURCES, INC.

CONSOLIDATED BALANCE SHEET

(Unaudited)

(Dollars inthousands, except share data)

 
| ** **                                                                                                           | ** ** | **March 31,  2005** | ** ** | **December 31,  2004** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|---------------------|------------|------------------------|------------|
| ** **                                                                                                           | ** ** | ** **          | ** ** | ** **             | ** ** |
| ASSETS                                                                                                               | ** ** | ** **          | ** ** | ** **             | ** ** |
| Current assets:                                                                                                      |       |                |       |                   |       |
| Cash and cash  equivalents                                                                                           |       | $                   | 1,725      |                   | $          | 390 |   |
| Trade accounts  receivable, net                                                                                      |       | 380,047             |       | 393,750                |       |
| Inventory                                                                                                            |       | 64,592              |       | 94,604                 |       |
| Assets from  price risk management activities                                                                        |       | 20,859              |       | 22,238                 |       |
| Other                                                                                                                |       | 6,134               |       | 12,494                 |       |
| Total current assets                                                                                                 |       | 473,357             |       | 523,476                |       |
|                                                                                                                 |       |                |       |                   |       |
| 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                                                                        |       | 536                 |       | 618                    |       |
| Equity  investments                                                                                                  |       | 36,108              |       | 35,729                 |       |
| Other                                                                                                                |       | 26,403              |       | 26,676                 |       |
|                                                                                                                 |       |                |       |                   |       |
| Total other  assets                                                                                                  |       | 97,473              |       | 90,727                 |       |
|                                                                                                                 |       |                |       |                   |       |
| TOTAL ASSETS                                                                                                         |       | $                   | 1,875,677  |                   | $          | 1,840,112 |   |
|                                                                                                                 |       |                |       |                   |       |
| LIABILITIES AND  STOCKHOLDERS’ EQUITY                                                                           |       |                |       |                   |       |
| Current  liabilities:                                                                                                |       |                |       |                   |       |
| Accounts payable                                                                                                     |       | $                   | 387,310    |                   | $          | 400,672 |   |
| Accrued expenses                                                                                                     |       | 58,592              |       | 60,472                 |       |
| Liabilities from  price risk management activities                                                                   |       | 31,206              |       | 11,099                 |       |
| Dividends  payable                                                                                                   |       | 3,710               |       | 3,704                  |       |
| Total current  liabilities                                                                                           |       | 480,818             |       | 475,947                |       |
|                                                                                                                 |       |                |       |                   |       |
| Long-term debt                                                                                                       |       | 385,900             |       | 382,000                |       |
| Liabilities from  price risk management activities                                                                   |       | 310                 |       | 417                    |       |
| Other long-term  liabilities                                                                                         |       | 53,187              |       | 51,827                 |       |
| Deferred income  taxes payable, net                                                                                  |       | 251,737             |       | 247,893                |       |
|                                                                                                                 |       |                |       |                   |       |
| Total liabilities                                                                                                    |       | 1,171,952           |       | 1,158,084              |       |
|                                                                                                                 |       |                |       |                   |       |
| Stockholders’ equity:                                                                                           |       |                |       |                   |       |
| Common stock,  par value $.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                                                                                                   |       | 307,605             |       | 278,687                |       |
| Accumulated  other comprehensive income                                                                              |       | (5,498              | )          | 4,262                  |       |
|                                                                                                                 |       |                |       |                   |       |
| Total  stockholders’ equity                                                                                     |       | 703,725             |       | 682,028                |       |
|                                                                                                                 |       |                |       |                   |       |
| TOTAL  LIABILITIES AND STOCKHOLDERS’ EQUITY                                                                     |       | $                   | 1,875,677  |                   | $          | 1,840,112 |   |

 

The accompanyingnotes are an integral part of the consolidated financial statements.

 

3

----

 

WESTERN GASRESOURCES, INC.

CONSOLIDATED STATEMENT OFCASH FLOWS

(Unaudited)

(Dollars inthousands)

 
| ** **                                                                              | ** ** | **Three Months Ended  March 31,** | ** ** |
|-----------------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                              | ** ** | **2005**                          | ** ** | **2004** | ** ** |
| Reconciliation  of net income to net cash provided by operating activities:             |       |                              |       |   |   |
| Net income                                                                              |       | $                                 | 32,628     |   | $ | 29,088 |   |
| 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                                                                  |       | 11,364                            |       | 10,465 |   |
| Non-cash change  in fair value of derivatives                                           |       | 8,469                             |       | 6,219 |   |
| 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                                            |       | (1,261                            | )          | 642 |   |
| (Increase) in other  assets and liabilities, net                                        |       | (407                              | )          | (171 | ) |
| (Decrease)  increase in accounts payable                                                |       | (9,210                            | )          | 6,816 |   |
| Increase in  accrued expenses                                                           |       | 5,485                             |       | 7,932 |   |
|                                                                                    |       |                              |       |   |   |
| Net cash  provided by operating activities                                              |       | 118,789                           |       | 126,010 |   |
|                                                                                    |       |                              |       |   |   |
| Cash flows from  investing activities:                                                  |       |                              |       |   |   |
| Purchases of  property and equipment, including acquisitions                            |       | (116,725                          | )          | (36,955 | ) |
| Distributions  from equity investees                                                    |       | 324                               |       | — |   |
| Proceeds from  the dispositions of property and equipment                               |       | 767                               |       | 315 |   |
|                                                                                    |       |                              |       |   |   |
| Net cash used in  investing activities                                                  |       | (115,634                          | )          | (36,640 | ) |
|                                                                                    |       |                              |       |   |   |
| 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 notesare an integral part of the consolidated financial statements.

4

----

 

WESTERN GASRESOURCES, INC.

CONSOLIDATED STATEMENT OFOPERATIONS

(Unaudited)

(Dollars inthousands, except share and per share amounts)

 
| ** **                                                                                          | ** ** | **Three Months Ended  March 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                                          | ** ** | **2005**                          | ** ** | **2004** | ** ** |
| 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                                                                   |       | (40                               | )          | (5,480 | ) |
| Other                                                                                               |       | 1,287                             |       | 1,642 |   |
| Total revenues                                                                                      |       | 854,315                           |       | 771,216 |   |
|                                                                                                |       |                              |       |   |   |
| 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                                                                                |       | 51,342                            |       | 38,382 |   |
| Provision for  income taxes:                                                                        |       |                              |       |   |   |
| Current                                                                                             |       | 7,350                             |       | 3,543 |   |
| Deferred                                                                                            |       | 11,364                            |       | 10,465 |   |
| Total provision  for income taxes                                                                   |       | 18,714                            |       | 14,008 |   |
|                                                                                                |       |                              |       |   |   |
| Income before  cumulative effect of changes in accounting principles                                |       | 32,628                            |       | 24,374 |   |
|                                                                                                |       |                              |       |   |   |
| Cumulative  effect of change in accounting principle net of tax of $2,710                           |       | —                            |       | 4,714 |   |
|                                                                                                |       |                              |       |   |   |
| Net income                                                                                          |       | 32,628                            |       | 29,088 |   |
|                                                                                                |       |                              |       |   |   |
| Preferred stock  requirements                                                                       |       | —                            |       | (816 | ) |
|                                                                                                |       |                              |       |   |   |
| Income  attributable to common stock                                                                |       | $                                 | 32,628     |   | $ | 28,272 |   |
|                                                                                                |       |                              |       |   |   |
| Net income per  share of common stock before cumulative effect of changes in accounting  principles |       | $                                 | 0.44       |   | $ | 0.34 |   |
|                                                                                                |       |                              |       |   |   |
| Cumulative  effect of change in accounting principle                                                |       | $                                 | —     |   | $ | 0.07 |   |
|                                                                                                |       |                              |       |   |   |
| Earnings per  share of common stock                                                                 |       | $                                 | 0.44       |   | $ | 0.41 |   |
|                                                                                                |       |                              |       |   |   |
| Weighted average  shares of common stock outstanding                                                |       | 74,148,269                        |       | 68,365,900 |   |
|                                                                                                |       |                              |       |   |   |
| Income  attributable to common stock - assuming dilution                                            |       | $                                 | 32,628     |   | $ | 29,088 |   |
|                                                                                                |       |                              |       |   |   |
| Earnings per  share of common stock - assuming dilution                                             |       | $                                 | 0.43       |   | $ | 0.39 |   |
|                                                                                                |       |                              |       |   |   |
| Weighted average  shares of common stock outstanding - assuming dilution                            |       | 75,559,318                        |       | 73,651,610 |   |

 

The accompanyingnotes are an integral part of the consolidated financial statements.

 

5

----

 

WESTERN GASRESOURCES, INC.

CONSOLIDATED STATEMENT OFCHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(Dollars inthousands, except share amounts)

 
| ** **                                             | ** ** | **Shares  of Common  Stock** | ** ** | **Shares  of Common  Stock  in Treasury** | ** ** | **Common  Stock** | ** ** | **Treasury  Stock** | ** ** | **Additional  Paid-In  Capital** | ** ** | **Retained  Earnings** | ** ** | **Accumulated  Other  Comprehensive  Income (Loss)  Net of Tax** | ** ** | **Total  Stock-  holders’  Equity** | ** ** |
|--------------------------------------------------------|------------|------------------------------|------------|-------------------------------------------|------------|-------------------|------------|---------------------|------------|----------------------------------|------------|------------------------|------------|------------------------------------------------------------------|------------|------------------------------------------|------------|
|                                                   |       |                         |       |                                      |       |              |       |                |       |                             |       |                   |       |                                                             |       |                                     |       |
| Balance at  December 31, 2004                          |       | 74,078,733                   |       | 50,032                                    |       | $                 | 7,430      |                | $          | (788                             | )          | $                      | 392,437    |                                                             | $          | 278,687                                  |       | $ | 4,262 |   | $ | 682,028 |   |
| Comprehensive  income:                                 |       |                         |       |                                      |       |              |       |                |       |                             |       |                   |       |                                                             |       |                                     |       |
| Net income, first  quarter of 2005                     |       | —                       |       | —                                    |       | —            |       | —              |       | —                           |       | 32,628                 |       | —                                                           |       | 32,628                                   |       |
| 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                |       | —                       |       | —                                    |       | —            |       | —              |       | —                           |       | —                 |       | —                                                           |       | 22,868                                   |       |
| 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                             |       | 74,212,479                   |       | 50,032                                    |       | $                 | 7,444      |                | $          | (788                             | )          | $                      | 394,962    |                                                             | $          | 307,605                                  |       | $ | (5,498 | ) | $ | 703,725 |   |

 

The accompanyingnotes are an integral part of the consolidated financial statements.

 

6

----

 

WESTERNGAS RESOURCES, INC.

NOTES TO CONSOLIDATEDFINANCIAL STATEMENTS

(Unaudited)

 

***GENERAL***

 

We have preparedthe accompanying unaudited interim consolidated financial statements under therules and regulations of the Securities and Exchange Commission, or SEC.  As provided by such rules and regulations, wehave condensed or omitted certain information and notes normally included inannual financial statements prepared in conformity with accounting principlesgenerally accepted in the United States of America.

 

The interimconsolidated financial statements presented herein should be read inconjunction with the Consolidated Financial Statements and Notes theretoincluded in our Annual Report on Form 10-K for the year ended December 31,2004.  The interim consolidated financialstatements as of March 31, 2005 and for the three-month periods ended March 31,2005 and 2004 included herein are unaudited but reflect, in the opinion ofmanagement, all adjustments (which include only normal recurring adjustments)necessary to fairly present the results for such periods.  The results of operations for the threemonths ended March 31, 2005 are not necessarily indicative of the results ofoperations expected for the year ended December 31, 2005.

 

In March 2005, we revised our classification in theStatement of Cash Flows for the quarter ended March 31, 2004, of the Change inthe balance of outstanding checks from a component of Net cash provided byoperating activities to a component of Cash flows from financingactivities.  This change inclassification had the effect of decreasing previously reported cash providedby operating activities by $11.1 million for the quarter ended March 31, 2004,with a corresponding decrease in cash flows used in financing activities.

 

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

 

***Conversion of Preferred Stock.*** In December 2003, we issued a notice ofredemption for a total of 800,000 shares of our $2.625 cumulative convertiblepreferred stock.  The holders of theseshares had the right to convert them into shares of our common stock in lieu ofreceiving the redemption price in cash.  In January 2004, we issued an additional 1,979,244 shares of commonstock to holders who elected to convert their shares and paid $672,000 in cashproceeds to complete this redemption.  In March 2004, we issued an additional notice of redemption for theremaining 1,260,000 shares of our $2.625 cumulative convertible preferredstock.  In April 2004, we issued anadditional 3,113,582 shares of common stock to holders who elected to converttheir shares and paid $391,000 in cash proceeds to complete thisredemption.  After these redemptions, the$2.625 cumulative convertible preferred stock was delisted from trading on theNew York Stock Exchange and was deregistered by the SEC.

 

***EARNINGSPER 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 common shares.  The following isa reconciliation of the weighted average shares of common stock outstanding tothe weighted average common shares outstanding – assuming dilution.

 

7

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| ** **                                                               | ** ** | **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 |   |

 

The calculation of fully diluted earnings per share reflectspotential common shares and any related preferred dividends.

 

***ACCUMULATED OTHERCOMPREHENSIVE INCOME***

 

Included in Accumulated other comprehensive income at March31, 2005 were unrealized losses of $7.2 million from the fair value ofderivatives designated as cash flow hedges and unrealized losses of $2.3million of cumulative foreign currency translation adjustments.

 

Included in Accumulated other comprehensive income at March31, 2004 were unrealized losses of $2.9 million from the fair value ofderivatives designated as cash flow hedges and unrealized gains of $1.4 millionof cumulative foreign currency translation adjustments.

 

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

 

In the GasGathering, Processing and Treating segment, we recognize revenue for ourservices at the time the service is performed. We record revenue from our gasand NGL marketing activities, including sales of our equity production, upontransfer of title.  In accordance withEITF 03-11, we record revenue on ourphysical gas and NGL marketing activities on a gross basis versus sales net ofpurchases basis because we obtain title to all the gas and NGLs that we buyincluding third-party purchases, bear the risk of loss and credit exposure onthese transactions, and it is our intention upon entering these contracts totake physical delivery of the product. Gas imbalances on our production are accounted for using the salesmethod.  Gas imbalances on our productionat March 31, 2005 and 2004 are immaterial. For our marketing activities, we utilize mark-to-market accounting forour derivatives.  Under mark-to-marketaccounting, the expected margin to be realized over the term of the transactionis recorded in the month of origination. To the extent that a transaction isnot fully hedged or there is any hedge ineffectiveness, additional gains orlosses associated with the transaction may be reported in future periods.  In the Transportation segment, werealize revenue 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 deliveredfrom the pipeline.

 

***CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES***

 

##### ***Depreciation, Depletionand Amortization for Oil and Gas Properties. ***We follow the successfulefforts method of accounting for oil and gas exploration and productionactivities.  Effective January 1, 2004,we redefined the asset groupings for the calculation of depreciation anddepletion on our oil and gas properties from a well-by-well basis to a fieldwide basis for each of the Jonah, Pinedale and Sand Wash fields and to agrouping of all wells drilled into related coal seams for the Powder RiverBasin.  The cumulative effect of thechange in depreciation and depletion methodology for the quarter ended March31, 2004 was a benefit of $4.7 million, net of tax, or $0.07 per share ofcommon stock - assuming dilution, and is presented in the ConsolidatedStatement of Operations under the caption Cumulative effect of change inaccounting principle, net of tax.

 

***DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES***

 

The netgain recognized in earnings through Sale of residue gas and Sale of natural gasliquids 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.

 

The gains and losses currently reflected inAccumulated other comprehensive income will be reclassified to earnings as thehedged gas or NGLs is sold.  Based on theprices for our products on March 31, 2005, approximately

 

8

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$7.2 million of losses in Accumulated other comprehensive income isanticipated to be reclassified to earnings in 2005.

 

***SUPPLEMENTARY CASH FLOW INFORMATION***

 

Interest paid was $6.1 million and $3.0 million forthe three months ended March 31, 2005 and 2004, respectively.  Noincome taxes were paid in the three months ended March 31, 2005 and 2004.

 

***STOCKCOMPENSATION***

 

Aspermitted under SFAS No. 123, “Accounting for Stock-Based Compensation,” wehave elected to continue to measure compensation costs for stock-based employeecompensation plans as prescribed by Accounting Principles Board Opinion No. 25,“Accounting for Stock Issued to Employees.” We have complied with the pro forma disclosure requirements of SFAS No.123 as required under the pronouncement. We realize an income tax benefit from the exercise of non-qualifiedstock options related to the amount by which the market price at the date ofexercise exceeds the option price.  Thistax benefit is credited to additional paid-in capital.

 

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, which weretreated as repriced options.  Based onour stock price at March 31, 2005 of $34.45 per share and our stock price atMarch 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 following isa summary of the options to purchase our common stock granted and the weightedaverage fair value per share of the options granted duringthe quarters ended March 31, 2005 and 2004, respectively.

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

 

Duringthe quarter ended March 31, 2005, the valuesfor the options granted were estimated using the Black-Scholes option-pricingmodel with the following assumptions:

 
| ** **                      | ** ** | **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  As Reported**       | ** ** | **2005  Pro Forma** | ** ** | **2004  As Reported** | ** ** | **2004  Pro Forma** | ** ** |
| Net income                                                                                                                                     |       | $                           | 32,628     |   | $ | 30,949 |   | $ | 29,088 |   | $ | 27,946 |   |
| Income  attributable to common stock                                                                                                           |       | 32,628                      |       | 30,949 |   | 28,272 |   | 27,130 |   |
| Earnings per  share of common stock                                                                                                            |       | 0.44                        |       | 0.42 |   | 0.41 |   | 0.39 |   |
| Earnings per  share of common stock - assuming dilution                                                                                        |       | 0.43                        |       | 0.41 |   | 0.39 |   | 0.38 |   |
| 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 |   | $ | — |   | $ | 1,257 |   |

 

9

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***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 and Treating.***  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 natural gas to extract NGLs and treat the natural gas inorder to meet pipeline specifications. In some areas, where no processing is required, we gather and compressproducers’ gas and deliver it to pipelines for further delivery to market.  Except for volumes taken in kind by ourproducers, the Marketing segment sells the residue gas and NGLs extracted atmost of our facilities.

 

Substantially all gasflowing through our gathering, processing and treating facilities is suppliedunder 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.

 

Approximately 19% of ourplant facilities’ gross margin for the month of March 2005 was under contractsthat are primarily fee-based from which we receive a set fee for each Mcf ofgas gathered and/or processed. This type of contract provides us with a steadyrevenue stream that is not dependent on commodity prices, except to the extentthat low prices may cause a producer to delay drilling.

 

Approximately 11% of our plant facilities’ grossmargin for the month of March 2005 was under contracts with “keepwhole”arrangements or wellhead purchase contracts. Under these contracts, we retain the NGLs recovered by the processingfacility and keep the producers whole by returning to the producers at thetailgate of the plant an amount of residue gas equal on a Btu basis to thenatural gas received at the plant inlet. The “keepwhole” component of the contracts permits us to benefit whenthe value of the NGLs is greater as a liquid than as a portion of the residuegas stream.  However, we are adverselyaffected when the value of the NGLs is lower as a liquid than as a portion ofthe residue gas stream.

 

***Exploration and Production.***  The activities of the Exploration andProduction segment include the exploration and development of gas properties inthe Rocky Mountain area and other unconventional gas plays, including thosewhere our gathering and/or processing facilities are located.  The Marketing segment sells the majority ofthe production from these properties and remits to the Exploration andProduction segment all of the proceeds from the sales of its gas net oftransportation charges.

 

***Marketing.***  Our Marketing segment buys and sells gas andNGLs in the United States and Canada from and to a variety of customers.  Revenues in this segment are sensitive tochanges in the market prices of the underlying commodities.  The marketing of products purchased fromthird parties typically results in low sales margins relative to the salesprice.  We sell our products under agreementswith varying terms and conditions in order to match seasonal and other changesin demand.  Also included in this segmentare our Canadian marketing operations, which are conducted through our whollyowned subsidiary WGR Canada, Inc. and are immaterial for separate presentation.

 

***Transportation.***  The Transportation segment reflects theoperations of Western’s MIGC, Inc. and MGTC, Inc. pipelines.   The majority of the revenue presented inthis segment is derived from transportation of residue gas for our Marketingsegment and other third parties.  TheTransportation segments’ firm capacity contracts range in duration from sevenmonths to approximately five years.

 

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***Segment Information.*** Thefollowing tables set forth our segment information as of and for the threemonths ended March 31, 2005 and 2004 (dollars in thousands).  Due to our integrated operations, the use ofallocations in the determination of business segment information isnecessary.  Inter-segment revenues arevalued at prices comparable to those of unaffiliated customers.  Prior period Corporate Plant operating andtransportation expense of $935,000 in the interim segment information has beenreclassified to the Gas Gathering and Processing segment to conform to thepresentation used in 2005.

 

**Quarter Ended March 31, 2005:**

 
| ** **                                        | ** ** | **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 and transportation 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                                 | )          | —                           |       | 47            |       | —              |       | —        |       | —                   |       | (40       | )          |
| Interest income                                   |       | —                              |       | 4                                |       | —        |       | —              |       | 9,502         |       | (9,506                   | )          | —    |       |
| Other, net                                        |       | 1,105                               |       | 2                                |       | —        |       | —              |       | 180           |       | —                   |       | 1,287     |       |
| Total revenues                                    |       | 298,247                             |       | 74,373                           |       | 841,850       |       | 5,937               |       | 9,692         |       | (375,784                 | )          | 854,315   |       |
|                                              |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| 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                         |       | 52,289                              |       | 38,952                           |       | 1,805         |       | 3,267               |       | 9,692         |       | (9,505                   | )          | 96,500    |       |
|                                              |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| 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        |       | $                   | 1,768      |          | $          | 3,021                    |       | $         | (17,754    | ) | $ | 11 |   | $ | 51,342 |   |
|                                              |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| 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                           |       | 133,714       |       | 48,960              |       | 425,113       |       | (98,095                  | )          | 534,722   |       |
| Total  identifiable assets                        |       | $                                   | 753,629    |                             | $          | 522,394       |       | $                   | 133,729    |          | $          | 86,462                   |       | $         | 1,235,700  |   | $ | (856,237 | ) | $ | 1,875,677 |   |

 

11

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**Quarter Ended March 31, 2004:**

 
| ** **                                        | ** ** | **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                      |       | $         | —     |   | $ | — |   | $ | 663,661 |   |
| 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                                 | )          | —                           |       | (5,459        | )          | —              |       | —        |       | —                   |       | (5,480    | )          |
| Interest income                                   |       | —                              |       | —                           |       | —        |       | —              |       | 4,009         |       | (4,009                   | )          | —    |       |
| Other, net                                        |       | 341                                 |       | 1                                |       | (2            | )          | —              |       | 1,302         |       | —                   |       | 1,642     |       |
| Total revenues                                    |       | 271,740                             |       | 59,671                           |       | 762,586       |       | 5,739               |       | 5,311         |       | (333,831                 | )          | 771,216   |       |
|                                              |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| 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                           |       | 2,959         |       | 2,398               |       | 5,311         |       | (4,016                   | )          | 76,756    |       |
|                                              |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| 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        |       | $                   | 2,848      |          | $          | 2,044                    |       | $         | (16,595    | ) | $ | 8 |   | $ | 38,382 |   |
|                                              |       |                                |       |                             |       |          |       |                |       |          |       |                     |       |      |       |
| 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                            |       | 60,172        |       | 27,152              |       | 319,475       |       | (52,120                  | )          | 365,390   |       |
| Total identifiable  assets                        |       | $                                   | 629,193    |                             | $          | 309,458       |       | $                   | 60,189     |          | $          | 65,655                   |       | $         | 857,541    |   | $ | (496,643 | ) | $ | 1,425,393 |   |

 

***LEGALPROCEEDINGS***

 

***Gracey et al. v. Western Gas Resources, Inc. et al., UnitedStates District Court, Southern District of New York, Case No.03-CV-6186 (vm) (S.D.N.Y.). ***OnSeptember 17, 2004, the plaintiffs, traders of natural gas futures contracts onNYMEX filed this action on behalf of themselves and a putative class of otherssimilarly situated.  In the complaint,the plaintiffs claim that the Company manipulated the prices of natural gasfutures on the NYMEX in violation of the Commodity Exchange Act, or CEA, byreporting allegedly “inaccurate, misleading and false trading information” totrade publications that compile and publish indices of natural gas spotprices.  In addition, the complaintasserts that the Company aided and abetted the alleged CEA violations ofothers.  The plaintiffs seek to recoveractual damages on behalf of themselves and a class of natural gas futurestraders, and their costs of litigation including attorney’s fees.  The Company believes that the claims arewithout merit and intends to vigorously contest the allegations in this case.

 

***OtherLitigation.**** * We are involved in various other litigationand administrative proceedings arising in the normal course of business.  In the opinion of our management, anyliabilities that may result from these claims will not, individually or in theaggregate, have a material adverse effect on our financial position, results ofoperations or cash flow.

 

***RECENTLY ISSUEDACCOUNTING PRONOUNCEMENTS***

 

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

 

**SFASNo. 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, *“Accountingfor Stock Based Compensation.*” If SFAS No. 123(R) had been in effect during the first quarter of 2005,Earnings per share of common stock - assuming dilution in the first quarterended March 31, 2005 would have been $0.41 per share of common stock or areduction of approximately $0.02 per share of common stock from the actualresults for the first quarter of 2005.

 

**SFASNo. 151.**   SFAS No. 151, “*Inventory Costs, an amendment of ARB No. 43, Chapter4”*was issued in November 2004 and is effective for the Company forinventory costs incurred in fiscal years beginning after June 15, 2005,and will be applied prospectively.  SFASNo. 151 amends APB Opinion No. 43, Chapter 4, “Inventory Pricing” toclarify the accounting for abnormal amounts of costs and the allocation offixed production overheads.

 

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We believe that the adoption of SFAS No. 151 will not affect ourresults of operations, financial position or cash flows.

 

**SFAS No. 153.**   SFASNo. 153, “*Exchanges of NonmonetaryAssets, an amendment of APB Opinion No. 29”*was issued in December2004 and is effective for the Company for nonmonetary asset exchanges occurringin fiscal periods beginning after June 15, 2005, and will be appliedprospectively.  SFAS No. 153 amendsAPB Opinion No. 29, *Accounting forNonmonetary Transactions*.  Theguidance in APB Opinion No. 29 is based on the principle that exchanges of nonmonetaryassets should be measured based on the fair value of the assets exchanged butincluded certain exceptions to that principle. SFAS No. 153 amends APB Opinion No. 29 to eliminate the exception fornonmonetary exchanges of similar productive assets and replaces it with ageneral exception for exchanges of nonmonetary assets that do not havecommercial substance.  A nonmonetaryexchange has commercial substance if the future cash flows of the entity areexpected to change significantly as a result of the exchange.  We will adopt SFAS No. 153 as required.

 

**EITFNo. 04-13.  **At itsNovember 2004 meeting, the Emerging Issues Task Force, or EITF, of the FASBbegan discussion of Issue No. 04-13, “Accounting for Purchases and Sales ofInventory with the Same Counterparty.” This Issue addresses the question of when it is appropriate to measurenon-monetary purchases and sales of inventory at fair value and record them incost of sales and revenues and when they should be recorded as an exchangemeasured at the book value of the item sold. The EITF did not reach a consensuson this issue, but requested the FASB staff to further explore the alternativeviews.  The implementation of this EITF,if approved, may reduce revenues and related costs but will not have a materialimpact on our results of operations, financial position or cash flows.

 

In order to minimizetransportation costs or make product available at a location of our customer’spreference, from time to time, we will enter into arrangements to buy productfrom a party at one location and arrange to sell a like quantity of product tothis same party at another location.  Inaccordance 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 $28.7 millionand $25.2 million, respectively, and product purchases of $26.7 million and$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 FASB Staff issued FASB Staff Position, or FSP,FAS 19-1, “Accounting for Suspended Well Costs.” This FSP amendsSFAS 19, “Financial Accounting and Reporting by Oil and Gas ProducingCompanies,” as it pertains to capitalizing the costs of drilling exploratorywells pending determination of whether the well has found proved reserves.  FSP FAS 19-1 states that exploratory wellcosts should continued to be capitalized if the well has found a sufficientquantity of reserves to justify its completion as a producing well and theentity is making progress assessing reserves and the economic and operationalviability of the project.  This FSP iseffective in the second quarter of 2005. We do not believe that this FSP will have a material impact on ourresults of operations, financial position or cash flows.

 

**FASBInterpretation No. 47. **FASBInterpretation No. 47, “Accounting for Conditional Asset RetirementObligations, an interpretation of FASB Statement No. 143”, or FIN 47, wasissued in March 2005 and is effective in fiscal periods beginning afterDecember 31, 2005.  FIN 47 clarifies theterm “conditional asset retirement obligation” as used in FASB Statement 143, “Accountingfor Asset Retirement Obligations”. Conditional asset retirement obligations as used in FASB Statement 143refers to a legal obligation to perform an asset retirement activity in whichthe timing and (or) method of settlement are conditional on a future event thatmay or may not be within the control of the entity. The obligation to performan asset retirement activity is unconditional even though uncertainty existsabout the timing and (or) method of settlement. Accordingly, an entity isrequired to recognize a liability for the fair value of a conditional assetretirement obligation if the fair value of the liability can be reasonablyestimated. When sufficient information exists, uncertainty about the timing and(or) method of settlement should be factored into the measurement of theliability. This interpretation is not expected to have a material impact on ourresults of operation, financial position or cash flows.

 

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**ITEM 2.****                    MANAGEMENT’SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS**

 

The following discussionand analysis relates to factors that have affected our consolidated financialcondition and results of operations for the three months ended March 31, 2005and 2004.  Certain prior year amountshave been reclassified to conform to the presentation used in 2005.  You should also refer to our interimconsolidated financial statements and notes thereto included elsewhere in thisdocument.  This section, as well as othersections in this Form 10-Q, contain “forward-looking statements” within themeaning of the Private Securities Litigation Reform Act of 1995, which can beidentified by the use of forward-looking terminology, such as “may,” “intend,” “will,”“expect,” “anticipate,” “estimate,” or “continue” or the negative thereof orother variations thereon or comparable terminology.  In addition to the important factors referredto herein, numerous factors affecting the gas processing industry generally andin the specific markets for gas and NGLs in which we operate could cause actualresults to differ materially from those in such forward-looking statements.

 

***CompanyOverview***

 

***BusinessStrategy. *** Maximizing the value of our existing coreassets is the focal point of our business strategy.   Ourcore assets are our fully integrated upstream and midstream assets in thePowder River and Greater Green River Basins in Wyoming, the San Juan Basin inNew Mexico, the Sand Wash Basin in Colorado and our midstream operations inwest Texas and Oklahoma.  Our long-termbusiness plan is to increase stockholder value by: (i) doubling proven naturalgas reserves and equity production of natural gas from the levels achieved in2001 over a five year period; (ii) meeting or exceeding throughput projectionsin our midstream operations; and (iii) optimizing annual returns.

 

***Industry and Company Overview.  ***In North America, ourindustry has experienced several consecutive years of declining natural gasproduction despite 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.

 

Our operations are conducted through the followingfour business segments:

 

***Explorationand Production. ***We explorefor, develop and produce natural gas reserves independently and to enhance andsupport our existing gathering and processing operations. Our producingproperties are primarily located in the Powder River, Greater Green River, SanJuan, and Sand Wash Basins.  These playsprovide low geologic risk, and are multi-year development projects.  These provide us with the opportunity to steadilyincrease our production volume over time at reasonable operating and lowfinding and development costs.  In thefirst quarter of 2005 our average production sold was 164 MMcfe per day, whichis a 13% increase over the daily average production volume sold in the firstquarter of 2004.

 

We continue to seek to add additional upstream coreprojects that are focused on Rocky Mountain natural gas.  We will utilize our expertise in explorationand low-risk development of unconventional gas reservoirs including tight-gassands, coal bed methane, biogenic, and shale gas plays to evaluate acquisitionsof either additional leaseholds, proven and undeveloped reserves or companieswith operations primarily focused in the Rockies.  We may also evaluate unconventional gasreservoirs in areas outside the Rockies where we can leverage our relatedexploration, production and gathering expertise.  In January 2005, we opened an office inCalgary, Alberta, Canada to evaluate opportunities in the Western CanadianSedimentary Basin.  Overall, at March 31,2005, we have acquired 

 

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the drilling rights on approximately 1.6 million net acres in variousRocky Mountain basins and continue to expand our leasehold positions.

 

***Gathering,Processing and Treating. ***Ourcore operations are in well-established areas such as the Permian, Anadarko,Powder River, Greater Green River, and San Juan Basins.  We connect natural gas from gas and oil wellsto our gathering systems for delivery to our processing or treating plantsunder contracts with terms ranging from one month to life of lease. At ourplants we process natural gas to extract NGLs and treat natural gas in order tomeet pipeline specifications.  We providethese services to major oil and gas companies, to independent producers ofvarious sizes and for our own production. We believe that our low cost of operations, our high on-line time andour safety records are key elements in our ability to compete effectively andprovide reliable service to our customers. Our expertise in gathering, processing and treating operations canenhance the economics of developing new upstream projects.

 

This segment of ouroperations has provided a stream of operating profit that is available forreinvestment into other projects or other segments of our business.  Overall throughput in our facilities duringthe first quarter of 2005 remained relatively constant as compared to the sameperiod in 2004 and averaged a total of 1.4 Bcf per day.

 

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

 

***Marketing. ***The primary goal of our gas-marketingsegment is to ensure that the product from our processing facilities andupstream activities is delivered timely to the market.  Additionally, our gas marketing operationsseek to preserve and enhance the value received for our equity volumes ofnatural gas.  This goal is achievedthrough the use of hedges on the production of our equity natural gas and NGLsand through the use of firm transportation capacity.  We also buy and sell natural gas and NGLs inthe 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 OFOPERATIONS***

 

**Threemonths ended March 31, 2005 compared to the three months ended March 31, 2004**

**(Dollarsin thousands, except per share amounts and operating data).**

 
| ** **                                            | ** ** | **Three Months Ended  March 31,** | ** ** | **Percent  Change** | ** ** |
|-------------------------------------------------------|------------|-----------------------------------|------------|---------------------|------------|
| ** **                                            | ** ** | **2005**                          | ** ** | **2004**            | ** ** | ** ** |
| **Financial  results:**                               |       |                              |       |                |       |   |   |
| Revenues                                              |       | $                                 | 854,315    |                | $          | 771,216 |   | 11 |   |
| Net income                                            |       | 32,628                            |       | 29,088              |       | 12 |   |
| Earnings per  share of common stock                   |       | 0.44                              |       | 0.41                |       | 7 |   |
| Earnings per  share of common stock-assuming dilution |       | 0.43                              |       | 0.39                |       | 10 |   |
| Net cash  provided by operating activities            |       | 118,789                           |       | 126,010             |       | (6 | ) |
| Net cash used in  investing activities                |       | (115,634                          | )          | (36,640             | )          | 215 |   |
| 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 |   |

 

Net income increased $3.5million for the three months ended March 31, 2005 compared to the same periodin 2004.  The increase in net income wasprimarily attributable to higher production of equity gas volumes and higherproduct prices in the first quarter of 2005. Partially offsetting these items was an increase in operating costs anddepreciation, depletion and amortization in the first quarter of 2005 and thecumulative effect of a change in accounting principle in the first quarter of2004.  Effective as of January 1, 2004,we revised our depreciation and depletion methodology for our oil and gasproperties.  This change in accountingprinciple resulted in a cumulative reduction of depreciation for periods priorto 2004 of $4.7 million, net of tax, in the quarter ended March 31, 2004.

 

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Revenuesfrom the sale of gas increased $30.9 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, 2005 compared tothe same period in 2004.  Included in therealized gas price were approximately $1.3 million of gains recognized in thethree months ended March 31, 2005 related to futures positions on equity gasvolumes.  We have entered into additionalfutures positions for approximately 61% of our equity gas for the remainder of2005.  See further discussion in “Item 3.Quantitative and Qualitative Disclosures About Market Risk”.  Average gas sales volumes decreased by 5% to1,302 MMcf per day for the quarter ended March 31, 2005 compared to the sameperiod in 2004.

 

Revenues from thesale of NGLs increased $40.1 million to $133.0 million for the three monthsended 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 to thesame period in 2004.  This increase insales volume was primarily due to the acquisition of various gathering andprocessing assets in the first quarter of 2005.

 

Product purchasesincreased by $50.0 million for the quarter ended March 31, 2005 compared to thesame period in 2004 as a result of the increase in product prices.  Overall, combined product purchases as apercentage 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.

 

Plant and transportation operating expense increasedby $5.8 million for the quarter ended March 31, 2005 compared to the sameperiod in 2004.  The increase wasprimarily due to increases in property tax expenses, labor costs, repairs andmaintenance, and third party gathering.

 

Oil and gas exploration and production expensesincreased by $7.8 million for the quarter ended March 31, 2005 compared to thesame period in 2004.  The increase wassubstantially due to increased lease operating expenses, or LOE, in the PowderRiver Basin coal bed development, the newly acquired production assets in theSan Juan Basin, and unsuccessful well expense of $1.7 million primarily relatedto an exploratory well in the Sand Wash area. Overall, LOE averaged $0.87 perMcf in the 2005 period compared to $0.64 per Mcf in 2004.  The increase in LOE is substantially due tohigher water handling charges on dewatering wells in several new pilot areasthat have no offsetting gas production as yet, contract labor, and fuel andoperating costs of wellhead blowers in the Powder River Basin as well asincreased costs related to initiating operations of the San Juan Basinproduction 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 2005 acquisition ofadditional midstream assets in the Greater Green River Basin.  We also had $4.6 million increase in DD&Ain our upstream operations primarily due to our continued development in thePowder River Basin, downward revisions to reserves in the Powder River Basin,and our October 2004 acquisition of producing properties in the San Juan Basin.

 

Selling and administrative expenses increased by $2.6million in the quarter ended March 31, 2005 compared to the same period in2004.  This increase is due to highercompensation and benefit costs, audit fees and legal fees.

 

***Cash FlowInformation***

 

Cash flows from operatingactivities decreased by $7.2 million in the first quarter of 2005 compared tothe first quarter of 2004. This decrease was primarily due to the timing ofcash receipts and payables.

 

Cash flows used in investingactivities increased by $79.0 million in the first quarter of 2005 compared tothe first quarter of 2004.  This increasewas primarily due to an increased level of capital expenditures including theFebruary 2005 acquisition of additional midstream assets in the Greater GreenRiver Basin.

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Cash flows used in financingactivities decreased by $81.9 million in the first quarter of 2005 compared tothe first quarter of 2004.  This decreasewas due to a significant reduction in our outstanding debt in the first quarterof 2004, as compared to the utilization of funds provided by financingactivities to fund our capital investments in 2005.

 

***Segment Information***

 

***Gas Gathering, Processing and Treating.***  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 in 2004.  The increase in operating profit in thissegment in 2004 is primarily due to higher realized prices and the resultingincrease in net margin as shown below.

 
| ** **                 | ** ** | **Quarter Ended March 31,** | ** ** |
|----------------------------|------------|-----------------------------|------------|
| ** **                 | ** ** | **2005**                    | ** ** | **2004** | ** ** |
| Gross Margin  ($/Mcf)      |       | $                           | 0.64       |   | $ | 0.49 |   |
| Operating  Expense ($/Mcf) |       | 0.22                        |       | 0.18 |   |
| Net Margin  ($/Mcf)        |       | $                           | 0.42       |   | $ | 0.31 |   |

 

***Exploration and Production.***  The Exploration and Production segmentrealized segment-operating profit of $39.0 million in the first quarter of 2005compared to $33.1 million in 2004. The increase is due to increased equityproduction, higher product prices, and the acquisition of production assets inthe San Juan basin in the fourth quarter of 2004.   During the first quarter of 2005, ourproduction of natural gas, as compared to the same period in 2004 increased by9% 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 |   |

 

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

(2)       Of the totalGathering and transportation expense, approximately $0.63 per Mcfe and $0.66per Mcfe in the quarters ended March 31, 2005 and 2004, respectively, was theresult of inter-segment charges. 

 

***Marketing.***  The Marketing segment realizedsegment-operating profit of $1.8 million for the three months ended March 31,2005 compared to $3.0 million in the same period of 2004.  The decrease was due to lower pricedifferentials between the Rocky Mountain and Mid Continent market centers,which impacted the Marketing segment’s ability to capitalize on ourtransportation contracts.

 

***Transportation.***  The Transportation segment realizedsegment-operating profit of $3.3 million for the three months ended March 31,2005 compared to $2.4 million in the same period of 2004.  The Transportation segment includes theresults from the MIGC and MGTC pipelines in the Powder River Basin.

 

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

 

#### **Oursources of liquidity and capital resources historically have been net cashprovided 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 futuredevelopment and acquisition projects, and we may be required to seek additionalor alternative financing sources. Product prices,**

 

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#### **hedges ofequity production, sales of inventory, the volume of natural gas processed byour facilities, the volume of natural gas produced from our producingproperties, the margin on third-party product purchased for resale, as well asthe timely collection of our receivables are all expected to have significantinfluences 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.**

 

During the past several years, we have beensuccessful in developing additional reserves of natural gas and increasing ourequity natural gas production.  However,the overall level of drilling and production associated with our producingproperties will depend upon, among other factors, the price for gas,availability of transportation capacity to market centers, the energy andenvironmental policy and regulation by governmental agencies, the drillingschedules of the operators of our non-operated properties, the issuance ofdrilling and water disposal permits, the available of oil field services, andthe length of time for wells in the Powder River Basin to be dewatered, none ofwhich is within our control.  Anyreduction in the levels of exploration, development and production by us or asignificant reduction in natural gas prices could have a material adverseeffect on our financial condition, results of 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.

 

Wehave effective shelf registration statements filed with the SEC for anaggregate of $262.0 million of debt securities, preferred stock or commonstock.  These shelf registrations allow usto access the debt and equity markets, subject to market conditions.

 

***Sources and Uses of Funds*.**  Our sources and uses of funds for the quarterended March 31, 2005 are summarized as follows (dollars in thousands):

 

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| **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                       |   | 118,789 |    |
| Distributions  from equity investments                           |   | 324     |    |
| Proceeds from  exercise of common stock options                  |   | 2,307   |    |
| Total sources of  funds                                          |   | $       | 954,252 |   |
| **Uses of  funds:**                                              |   |    |    |
| Payments related  to long-term debt (including debt issue costs) |   | $       | 828,205 |   |
| Capital  expenditures                                            |   | 116,725 |    |
| Change in  balance of outstanding checks                         |   | 4,283   |    |
| Common dividends  paid                                           |   | 3,704   |    |
| Total uses of  funds                                             |   | $       | 952,917 |   |

 

***Capital Investment Program.***  We currently anticipate capital expendituresin 2005 of approximately $376.4 million.  The 2005 capital budget is a 24% increase over the amount expended in2004.  This increase is the result of anexpected increase in drilling activity in each of our upstream areas andadditional drilling activity by third party producers whose acreage isdedicated to our midstream facilities. Overall, capital expenditures in the Powder River Basin CBM developmentand in the Greater Green River Basin operations represent 34% and 29%,respectively, of the total 2005 budget. Due to drilling and regulatory uncertainties that are beyond ourcontrol, we can make no assurance that our capital budget for 2005 will notchange or that we will actually incur this level of capital expenditures.  This budget may be increased to provide foracquisitions if approved by our board of directors.

 

The 2005 capital budget and our capital expendituresduring the quarter ended March 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 |   |

 

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

 

***Contractual Commitmentsand Obligations***

 

##### ***Contractual Cash Obligations. ***Asummary of our contractual cash obligations as of March 31, 2005 is as follows(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 |   |

 

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(1) The interest rate assumed on the revolving credit facility at March31, 2005 is 4.1% per annum.

 

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***Guarantee of Fort Union Project Financing.***   We own a 13% equity interest in Fort UnionGas Gathering, L.L.C., or Fort Union, and are the construction manager andfield operator.  Fort Union gathers andtreats natural gas in the Powder River Basin in northeast Wyoming.  Initial construction and any expansions ofthe gathering header and treating system have been project financed by FortUnion.  This debt is amortizing on anannual basis 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 our ConsolidatedBalance Sheet.

 

***Operating Leases. **** *Inthe ordinary course of our business operations, we enter into operating leasesfor office space, and for office, communication, transportation and compressionequipment.  Payments made on these leasesare a component of operating expenses and are reflected on the ConsolidatedStatement of Operations and, as operating leases, are not reflected on ourConsolidated Balance Sheet.  Our leaseshave terms ranging from one month to ten years and the majority of the leaseshave return or fair market purchase options available at various times duringthe lease.   If we were to exercise thepurchase options on all the leased compression equipment, these purchaseoptions would require the capital expenditure of approximately $44.9 millionbetween 2007 and 2013.

 

***FirmTransportation Capacity.***  Accessto firm transportation is also a significant element of our businessstrategy.  Firm transportation ensuresthat our equity production has access to downstream markets and allows us tocapture 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.

 

At March 31, 2005, the fixed fees associated with ourexisting contracts for firm transportation capacity during 2005 will averageapproximately $0.16 per Mcf.  Theassociated contract periods range from one month to twelve years.  Under firm transportation contracts, we arerequired to pay the fees associated with these contracts whether or not thetransportation is used.

 

***FirmStorage Capacity Agreements*.**  We customarily store gas inunderground storage facilities to ensure an adequate supply for long-term salescontracts and to capture seasonal price differentials.  As of March 31, 2005, we had contracts inplace for approximately 15.6 Bcf of storage capacity at various third-partyfacilities.  Firm storageagreements generally require the payment of fixed monthly fees regardless ofthe quantity of gas that is in storage under a particular agreement.  Of the total storage capacity under contract,approximately 5.0 Bcf is under contract to our Canadian subsidiary, WGR Canada,Inc., and Western guarantees the subsidiary’s performance under thesecontracts.  This subsidiary is whollyowned by us and fully consolidated in our financial statements.

 

Thefees associated with these contracts in 2005 will average $0.59 per Mcf of annualcapacity.  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 $5.03 per Mcf at March31, 2004.  These positions are forstorage withdrawals within the next 14 months. At the time we place product into storage, we contract for the sale ofthat product, physically or financially, and do not speculate on the futurevalue of the product.  Theseagreements for storage capacity are not reflected on our Consolidated BalanceSheet.

 

From time to time, we lease NGL storage space at majortrading locations to facilitate the distribution of products. At March 31,2005, we held NGLs in storage at various third-party facilities of 3,669 MGal,consisting primarily of propane and ethane, at an average cost of $0.45 pergallon compared to 2,863 MGal at an average cost of $0.30 per gallon at March31, 2004.

 

#### **Long-term Debt**

 

***Revolving Credit Facility. ***The commitment under the revolving creditfacility totals $500 million and matures in June 2009.  At March 31, 2005, $230.9 million wasoutstanding under this facility.   Loansmade under this facility are secured by a pledge of the capital stock of oursignificant subsidiaries, and these subsidiaries also guarantee the borrowingsunder 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 rate

 

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payableon borrowings under this facility was approximately 4.1% per annum.  Under the credit facility, we are subject toa number of covenants, including: maintaining a total debt to capitalizationratio of not more than 55% and maintaining a ratio of EBITDA, as defined in thecredit facility, to interest over the last four quarters in excess of 3.0 to1.0.  The credit facility ranks equallywith borrowings under our master shelf agreement with The Prudential InsuranceCompany.  This facility has been ratedBa1 by Moody’s and BB+ by S&P.

 

***MasterShelf Agreement. ***Amountsoutstanding under the master shelf agreement at March 31, 2005 are as indicatedin 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.

 

InDecember 2004, we gave notice to Prudential of our intention to prepay a $25million note due January 17, 2008.  Thisnote bore interest at 6.36% per annum and was prepaid at par on January 18,2005.  To fund the prepayment, we issueda new $25 million note to Prudential, due January 2015 and bearing interest at5.57% per annum.  During 2005, we willmake scheduled payments totaling $10.0 million on these notes.  We intend to fund these repayments with fundsavailable under the revolving credit facility.

 

***Upstream Operations***

 

A vital aspect of ourlong-term business plan is to double proven natural gas reserves and equityproduction of natural gas from the level at December 31, 2001 over a five-yearperiod.  In order to achieve this goal,we will focus on continued development of our leasehold positions in the PowderRiver Basin CBM development, the Greater Green River Basin, the San Juan Basin,and the Sand Wash basin. Each of our existing upstream projects is fully integratedwith our midstream operations.  In otherwords, in each of these areas, we provide the gathering, compression,processing, marketing or transportation services for both our own productionand for third-party operators. Additionally, we are actively pursuing new exploration, development andproducing property acquisition opportunities.

#### ** **

#### **Our principal upstream operationsare summarized in the following table:**

 
| **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                                             |       |

 

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(1)  Represents netproduction sold in MMcfe/day.

 

***Drilling Results.* **The following table sets forth the numberof wells we drilled during the three months ended March 31, 2005 and 2004 ineach of our major producing areas.  Thisinformation should not be considered

 

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indicative of future performance, nor should it beassumed that there is necessarily any correlation between the number ofproductive wells 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,** | ** ** |
|----------------------------------------|------------|-----------------------------|------------|
| ** **                             | ** ** | **2005**                    | ** ** | **2004** | ** ** |
| **Productive Area**                    | ** ** | **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 |   |

 

***Powder RiverBasin Coal Bed Methane. ***Wecontinue to develop our Powder River Basin CBM reserves and expand theassociated gathering system in northeast Wyoming.  Our net production sold from the Powder RiverBasin CBM averaged 112 MMcf per day in the first quarter of 2005.

 

Our production from the Big George coal continues toincrease and was 89 MMcf per day gross at March 31, 2005, or 37 MMcf per daynet, from the All Night Creek Unit, Pleasantville, SG Palo, Bullwhacker,Schoonover and Kingsbury Unit areas.  Inthe Big George coal, as of April 2005, we had 748 wells dewatering andproducing gas, 431 wells dewatering and 634 wells drilled and in various stages of completion and hook-up inpreparation for dewatering and production.

 

Drilling in the Powder River Basin is dependent on thereceipt of various regulatory permits, including BLM drilling permits, DEQwater discharge permits, and the Wyoming State Engineer’s Office reservoirpermits.  Most of our undevelopedprospects from the Big George formation are located in the Powder Riverdrainage area.  Water managementtechniques utilized by us, and approved by the DEQ on a site-specific basis,have included containment or treating. In order to facilitate the processing of our water discharge permitapplications on the west side of the basin, and in advance of the finalrequirements of the DEQ, we have installed and tested various types of watertreatment facilities and are treating the water produced in some areas of thebasin and, with the approval of the DEQ, discharging into the PowderRiver.  We believe many of the futuredevelopments in the Big George coal will likely require water treatmentfacilities.  These treating operationshave added and will add to the cost of development and operations in theseareas.  We continue to evaluate severaloptions for water treatment and are working with the governmental agencies toidentify effective and cost efficient methods.

 

Our 2005 capital budget for the Powder River Basincoal bed project is estimated at $81.2 million, of which $29.1million was spentin the first quarter of 2005.  In 2005,we plan to participate in the drilling of 730 gross wells, or 365 net wells, inthe Big George and related coals and an additional 120 gross wells, or 60 netwells, in the Wyodak and related coals. An estimated 640 wells of the 850-well program will be on federalleaseholds and require drilling permits from the Bureau of Land Management, orBLM.  The remaining 210 well locationsare on fee or state leaseholds.  Togetherwith our co-developer, as of May 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.

 

Approximately 300 gross wells in our 2005-drillingprogram will require permits to treat produced water.  The remainder of the wells to be drilled in2005 will require more conventional types of water discharge permits, such asreservoir containment or surface discharge. To date, we, together with our co-developer in this area, have receivedwater discharge permits from the DEQ for approximately 49% of the wells we planto drill in 2005.  An additional

 

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484 permit applications have been submitted to the DEQ which, whencombined with permits received, is more than enough necessary to complete our2005 drilling program.  Historically, theDEQ permit process has required approximately 120 to 150 days from initialsubmittal to final approval.  There is,however, no assurance as to the future timing of the receipt of drilling andwater discharge permits, the success of our drilling program, or the dewateringtime as our development progresses into the western and northern parts of thePowder River Basin.

 

On April 30, 2003, the BLM issued the final Record ofDecision, or ROD, for the Powder River Basin Oil & Gas Environmental ImpactStatement, or EIS.  The ROD requiresadditional surveys for plant and animal species, cultural surveys and noxiousweed mitigation prior to the BLM granting a drilling permit.  A number of cases have been filed byenvironmental groups against the BLM in Wyoming disputing the validity of theenvironmental impact statement and ROD. Due to our interests in developing federal leases in the Powder RiverBasin, we are an intervenor defendant in each of the foregoing cases.  In one of these cases filed in the UnitedStates District Court of Montana, the Court was asked to address the adequacy of the Montana PowderRiver Basin ROD and whether the BLM should have issued a single EIS for thePowder River Basin.  Under an Order datedMarch 4, 2005, the Court found that a single EIS for the Powder River Basin isnot required under NEPA. As these cases proceed, the BLM, in the eventof any adverse rulings, may be required to perform further environmentalanalysis and, in addition, could be ordered to cease issuing drilling permitsuntil it has completed such further analysis.  Consequently, our ability to receive permits and develop our leases maybe delayed or restricted by the outcome of these cases.

 

On August 10, 2004, the Tenth Circuit Court of Appealsissued its decision in Pennaco Energy, Inc. v. United States Department ofthe Interior.  The court upheld adecision by the Interior Board of Land Appeals, or IBLA, that the BLM had notcomplied with the National Environmental Policy Act in issuing three federalleases to Pennaco Energy, Inc. in the Powder River Basin for coalbed methanedevelopment.  We are not a party to thecase, and the IBLA and Tenth Circuit decisions do not directly address anyfederal leases held by us.  However, wehold approximately 70,000 net acres of federal leasehold in the Powder RiverBasin, which may potentially be affected by the response to the Pennaco case.  In order to resolve the issues raised in thePennaco decision and related issues, the BLM filed for and received publiccomment 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.

 

A complaint was filed on January 31, 2005 in the U.S.District Court of Wyoming against the BLM and the Department of Interior.  The complaint alleges that the BLM violatedNEPA “as described in Pennaco Energy, Inc. v. United States Department ofthe 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 fora  “review of the issuance” of theseleases.    We cannot predict whatactions, if any, the Department of the Interior, third parties, or the Courtmight take in response to this case, or how these actions may affect the paceof federal drilling or permitting and development of the Powder River Basin.

 

***Jonah/Pinedale Fields.***  Our exploration and production assets in theGreen River Basin of southwest Wyoming are located in the Pinedale Anticlineand Jonah Field areas.  During 2005, weexpect to participate in the drilling of 80 gross wells, or approximately ninenet wells, on the Pinedale Anticline. Our capital budget for 2005 in the Pinedale Anticline area provides forexpenditures of approximately $47.9 million for drilling costs and productionequipment, of which $16.8 million was spent in the first quarter of 2005.  Due to drilling and regulatory uncertainties,which are beyond our control, there can be no assurance that we will incur thislevel of capital expenditure during 2005.

 

#### ***MidstreamOperations***

#### ** **

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 and Treating.*** We operatea variety of gathering, processing and treating facilities, or plantoperations, as presented on the Principal Gathering and Processing Facilities Tableset forth below.  Our

 

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operations are locatedin some ofthe most actively drilled oil and gas producing basins in the UnitedStates.  Six of our processingplants can further separate, or fractionate, the mixed NGL stream into ethane,propane, normal butane and natural gasoline to obtain a higher value for theNGLs, and three of our plants are capable of processing and treating naturalgas containing hydrogen sulfide or other impurities that require removal priorto delivery to market pipelines.   In addition to our integrated upstreamand midstream operations in the Powder River and Green River Basins in Wyoming,and in the San Juan Basin in New Mexico, our core assets include our plant operations locatedin west Texas and Oklahoma.  We believethat our core assets have stable production rates, provide a significantoperating cash flow and continue to provide us with strategic growthopportunities.

 

In February 2005, we closed on the purchase of  certain natural gas gathering and processingassets in the eastern Greater Green River Basin for approximately $28.0million, before closing adjustments.  Wecurrently plan to integrate portions of the acquired systems into our RedDesert plant and our Table Rock, Wamsutter and Desert Springs gathering systemsduring the third quarter of 2005.

 

In the first quarter of 2005, we agreed to acquire a200 MMcf per day cryogenic processing facility for $9.0 million.  We intend to expend an additional $28.5million to install this facility and expand our Chaney Dell/Westana processingand gathering complex.  We currentlyexpect that this facility will be operational in the second quarter of 2006.

 

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***Principal Gathering and Processing Facilities Table.***  The following table provides informationconcerning our principal gathering, processing and treating facilities at March31, 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 |   |

 

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(1)                      Our interestin all facilities is 100% except for Midkiff/Benedum (73%); Newcastle (50%);Fort Union (13%) and Rendezvous (50%). We operate all facilities, and all data include our interests and theinterests of other joint interest owners and producers of gas volumes dedicatedto the facility.  Unless otherwiseindicated, all facilities shown in the table are gathering, processing ortreating facilities.

(2)                      Gasthroughput capacity is as of March 31, 2005 and represents capacity inaccordance with design specifications unless other constraints exist, includingpermitting or field compression limits.

(3)                      Aggregatenatural gas volumes delivered into our gathering systems.

(4)                      Volumes ofgas and NGLs are allocated to a facility when a well is connected to thatfacility; volumes exclude NGLs fractionated for third-parties.

(5)                      Sour gasfacility (capable of processing or treating gas containing hydrogen sulfideand/or carbon dioxide).

(6)                      Processingfacility that includes fractionation (capable of fractionating raw NGLs intoend-use products).

(7)                      NGLproduction includes conversion of third-party feedstock to iso-butane.

(8)                      The GrangerComplex includes the Lincoln Road facility. The volume information for this facility is reported with the volumeinformation for Granger.

(9)                      Thisfacility was acquired in a transaction, which closed on February 1, 2005.

(10)                The majority ofthe gas gathered by the Rendezvous gas gathering system is delivered to ourGranger facility and is included with the volume information reported forGranger.

(11)                A portion of thegas gathered by the Wamsutter gas gathering system is delivered to our RedDesert facility and is included with the volume information reported for RedDesert.

(12)                A portion of thegas gathered by Fort Union is also reported under Coal Bed Methane Gathering.

(13)                NGL fractionationfacility that receives product from a third-party owned liquids pipeline.

 

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##### ***Transportation Operations***

##### *** ***

##### ***We ownand operate MIGC, Inc., an interstate pipeline located in the Powder RiverBasin, and MGTC, Inc., an intrastate pipeline located in northeastWyoming.  MIGC charges a Federal EnergyRegulatory Commission, or FERC, approved tariff and is connected to pipelinesowned by Colorado Interstate Gas Company, Williston Basin Interstate PipelineCompany, Kinder Morgan Interstate Pipeline Co., Wyoming Interstate Company,Ltd. and MGTC.  MIGC earns fees on amonthly basis from firm capacity contracts under which the shipper pays fortransport capacity whether or not the capacity is used and from interruptiblecontracts where a fee is charged based upon volumes received into thepipeline.  Contracts with third partiesfor capacity on MIGC range in duration from one month to approximately fiveyears, 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.***

 

The following table provides information concerningour principal transportation assets 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 |   |

 

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(1)       Ourinterest in both facilities is 100%, and we operate both facilities.

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

(3)       Aggregatevolumes transported by a pipeline.

 

***Marketing***

 

***Gas*.*   ***We market gas produced atour wells and at our plants and gas purchased from third-parties to end-users,local distribution companies, or LDCs, pipelines and other marketing companiesthroughout the United States and Canada. In addition to our offices in Denver, we have marketing offices inHouston, Texas and Calgary, Alberta. Third-party sales, firm transportation capacity on interstate pipelinesand our gas storage positions, combined with the stable supply of gas from ourfacilities and production, enable us to respond quickly to changing marketconditions and to take advantage of seasonal price variations and peak demandperiods.  One of the primary goals of 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, producedat our plants and purchased from third-parties, in the Rocky Mountain,Mid-Continent and Southwestern regions of the United States.  A majority of our production of NGLs moves tothe Gulf Coast area, which is the largest NGL market in the United States.  Through the development of end-use marketsand distribution capabilities, we seek to ensure that products from our plantsmove on a reliable basis, avoiding curtailment of production. Consumers of NGLsare primarily the petrochemical industry, the petroleum refining industry andthe retail and industrial fuel markets. As an example, the petrochemical industry uses ethane, propane, normalbutane and natural gasoline as feedstocks in the production of ethylene, whichis used in the production of various plastics products.  Further, consumers use propane for homeheating, transportation and agricultural applications.  Price, seasonality and the economy primarilyaffect the demand for NGLs.

 

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**ITEM 3.**      **QUANTITATIVE ANDQUALITATIVE DISCLOSURES ABOUT MARKET RISK**

 

Our commodity price risk management program has twoprimary objectives.  The first goal is topreserve and enhance the value of our equity volumes of gas and NGLs withregard to the impact of commodity price movements on cash flow and net incomein relation to those anticipated by our operating budget.  The second goal is to manage price riskrelated to our marketing activities to protect profit margins.  This risk relates to fixed price purchase andsale commitments, the value of storage inventories and exposure to physicalmarket price volatility.

 

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

 

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

 

We enter into futures transactions on the New YorkMercantile Exchange, or NYMEX, and through OTC swaps and options with variouscounterparties, consisting primarily of investment banks, financialinstitutions and other natural gas companies. We conduct credit reviews of all of our OTC counterparties and haveagreements with many of these parties that contain collateral requirements.  We generally use standardized swap agreementsthat allow for offset of positive and negative OTC exposures with the samecounterparty.  OTC exposure ismarked-to-market daily for the credit review process.  Our exposure to OTC credit risk is reduced byour ability to require a margin deposit from our counterparties based upon themark-to-market value of their net exposure. We are also subject to margin deposit requirements under these sameagreements and under margin deposit requirements for our NYMEX transactions.  At March 31, 2005, we had $13.1 million ofmargin deposits outstanding.

 

We continuallymonitor and review the credit exposure to our marketing counterparties.  In recent months the prices of natural gasand NGLs, and therefore our credit exposures, have increased significantly.  In order to minimize our credit exposures, wehave utilized existing netting agreements to reduce our net credit exposure,established new netting agreements with additional customers, terminatedseveral long-term marketing obligations, negotiated accelerated payment termswith several customers, and increased the amount of credit which we makeavailable to substantial companies which meet our credit requirements.  Although netting agreements similar to thosethat we utilize have been upheld by bankruptcy courts in the past, if any ofthe customers with whom we have netting agreements were to file for bankruptcy,we can provide no assurance that our agreements will not be challenged or as tothe outcome of any challenge.

 

The use offinancial instruments may expose us to the risk of financial loss in somecircumstances, including instances when (i) our equity volumes are less thanexpected, (ii) our customers fail to purchase or deliver the contractedquantities of natural gas or NGLs, or (iii) our OTC counterparties fail to perform.  To the extent that we engage in hedgingactivities, we may be prevented from realizing the benefits of favorable pricechanges in the physical market.  However,we are similarly insulated against decreases in these prices.

 

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

 

***Hedge Positions.* **As of March 31, 2005, we have hedgedapproximately 61% of our projected 2005 equity natural gas volumes andapproximately 32% of our projected 2005 equity production of crude oil,condensate, and NGLs.  All thesecontracts are designated and accounted for as cash flow hedges.  As such, gains and losses related to the effectiveportions of the changes in the fair value of the derivatives are recorded inAccumulated other comprehensive income, a component of Stockholders’equity.  Realized gains or losses onthese cash flow hedges are

 

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recognized in theConsolidated Statement of Operations through Sale of gas or Sale of natural gasliquids when the hedged transactions occur.

 

To qualify as cashflow hedges, the hedge instruments must be designated as cash flow hedges andchanges in their fair value must be highly correlated with changes in the priceof the forecasted transaction being hedged so that our exposure to the risk ofcommodity price changes is reduced.  Tomeet this requirement, we hedge the price of the commodity and, if applicable,the basis between that derivative’s contract delivery location and the cashmarket location used for the actual sale of the product.  This structure attains a high level ofeffectiveness, ensuring that a change in the price of the forecastedtransaction will result in an equal and opposite change in the cash price ofthe hedged commodity.  We utilize crudeoil as a surrogate hedge for natural gasoline and condensate.  Our hedges are tested for effectiveness atinception and on a quarterly basis thereafter. We use regression analysis based on a five-year period of time for thistest.  Gains or losses from theineffective portions of changes in the fair value of cash flow hedges arerecognized currently in earnings through Price risk management activities.  During the first quarter of 2005, werecognized a loss of $87,000 from the ineffective portions of our hedges.

 

***Outstanding EquityHedge Positions and the Associated Basis for 2005****.* The following table details our hedge positions as of March 31,2005.  In order to determine the hedgedprice to the particular operating region, deduct the basis differential fromthe NYMEX price.  The prices for NGLs donot include the cost of the hedges of approximately $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                                                                                                                                                                                                                                                                                 |
| 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                                                                                                                                                                                                                                                                                 |

 

Account balances related to hedging transactions(designated as cash flow hedges under SFAS 133) at March 31, 2005 were $2.1million in Current assets from price risk management activities, $13.5 millionin Current liabilities from price risk management activities, ($4.1) million inDeferred income taxes payable, net, and a $7.2 million after-tax unrealizedloss in Accumulated other comprehensive income, a component of Stockholders’equity.  The unrealized loss inAccumulated other comprehensive income will be reclassified to earnings in2005.

 

***Summary of Derivative Positions.***  A summary of the change in our derivativeposition from December 31, 2004 to March 31, 2005 is as follows (dollars inthousands):

 
| Fair value of  contracts outstanding at December 31, 2004              |   | $       | 11,341  |   |
|------------------------------------------------------------------------|--------|---------|---------|--------|
| Decrease in  value due to change in price                              |   | (11,759 | )       |
| Decrease in  value due to new contracts entered into during the period |   | (41     | )       |
| Gains realized  during the period from existing and new contracts      |   | (9,662  | )       |
| Changes in fair  value attributable to changes in valuation techniques |   | —  |    |
| Fair value of  contracts outstanding at March 31, 2005                 |   | $       | (10,121 | )      |

 

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A summary of our outstanding derivative positions atMarch 31, 2005 is as follows (dollars in thousands):

 
| ** **                        | ** ** | **Fair Value of Contracts at March 31, 2005** | ** ** |
|-----------------------------------|------------|-----------------------------------------------|------------|
| **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) |       | 11,265                                        |       | 6,061 |   | 5,180 |   | $ | 24 |   | — |   |
| Other valuation  methods (2)      |       | (13,131                                       | )          | (13,131 | ) | — |   | — |   | — |   |
| Total fair value                  |       | $                                             | (10,121    | ) | $ | (12,958 | ) | $ | 2,813 |   | $ | 24 |   | — |   |

 

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(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 Market Risk***.  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 protect marketingmargins from adverse changes in the U.S. and Canadian dollar exchange ratebetween 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  $14.3 million in Canadian dollars in exchangefor $11.9 million in U.S. dollars, and the fair market value of these contractswas a loss of  $30,000 in U.S. dollars.

 

**ITEM 4.**      **CONTROLS AND PROCEDURES**

 

***Disclosure Controlsand Procedures.***

 

Under the direction of our Chief Executive Officerand President, (“CEO”), and our Executive Vice President and Chief FinancialOfficer, (“CFO”), we reviewed and evaluated the effectiveness of our disclosurecontrols and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under theSecurities Exchange Act of 1934) as of the end of the period covered by thisreport.  Based on such evaluation, ourCEO and CFO concluded, as of the date of such evaluation, that our disclosurecontrols and procedures are effective.

 

***Changes in InternalControl over Financial Reporting.***

 

There have not been any changes in our internal control overfinancial reporting during the quarter ended March 31, 2005, that havematerially affected, or are reasonably likely to materially affect, ourinternal control over financial reporting.

 

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**PART II - OTHER INFORMATION**

 

**ITEM 1.    LEGAL PROCEEDINGS**

 

Reference is madeto “Notes to Consolidated Financial Statements (Unaudited)  — Legal Proceedings,” in Item 1 of this Form10-Q and incorporated by reference in this Item 1.

 

**ITEM 6.      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.                                                                                                                                                     |

 

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SIGNATURES

 

Pursuant to therequirements of the Securities Exchange Act of 1934, the Registrant has dulycaused this report to be signed on its behalf by the undersigned, thereuntoduly authorized.

 
|              | WESTERN GAS RESOURCES, INC. |                                                |
|-------------------|-----------------------------|-----------------------------------------------------|
|              | (Registrant)                |
|              |                        |                                                |
|              |                        |                                                |
| Date: May 6, 2005 | By:                         | /s/ Peter A. Dea                                    |   |
|              |                        | Peter A. Dea                                        |
|              |                        | Chief Executive Officer and President               |
|              |                        |                                                |
|              |                        |                                                |
| Date: May 6, 2005 | By:                         | /s/ William J. Krysiak                              |   |
|              |                        | William J. Krysiak                                  |
|              |                        | Executive Vice President - Chief Financial  Officer |
|              |                        | (Principal Financial and Accounting  Officer)       |
|                   |                             |                                                     |  |  |

 

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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                                                                                                                                                      |

 

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